November Contract Slips to $3.119 as Mild Weather Outweighs a 107.1 Bcf/d Production Low — $3.09 EMA Guards the $3 Floor

US natural gas futures are under pressure again on Wednesday as weather models keep pushing heating demand further out. The NYMEX November contract traded at $3.119 per million British thermal units by midday in New York, 5 cents below Tuesday’s settlement of $3.169. The move puts the front month within 3 cents of its 200-day exponential moving average at $3.09, the support level traders have treated as the line between consolidation and a deeper slide.

The past three sessions have been a tug of war. On Friday, the November contract climbed back above $3.200 as domestic production declined and LNG feedgas strengthened, recovering from Thursday’s storage-driven selloff. On Monday it slipped 1.03% to $3.171 in early trading as warm forecasts weighed. On Tuesday, futures held steady at $3.169, up 0.2 cent, as bearish forecasts for milder weather offset a bullish drop in daily output to an eight-month low. Wednesday’s session tilted back to the bears.

Spot prices tell the same story. Henry Hub next-day gas traded at $3.10, unchanged from the prior day and below the $3.19 level of the same month last year. Henry Hub spot averaged $2.95 in September and $2.79 in August, after peaking at $7.72 in January during Winter Storm Fern.

The thesis for this forecast is direct: Henry Hub is trading on domestic weather and storage, not on the global gas crisis. European gas sits at a 45-month high and Asian prices exceed $26, yet US prices barely react because LNG export plants are already running at capacity. That leaves the November contract caught between two domestic forces. On one side, the National Weather Service assigns up to 80% odds of above-normal temperatures across the heating-sensitive north-central states, delaying winter demand. On the other, Lower 48 production has fallen from a record 113.3 billion cubic feet a day to an eight-month low near 107.1 Bcf/d, and storage injections have run below normal for eight straight weeks.

In the near term, weather is winning. Storage remains 68 Bcf above the five-year average, and warm forecasts through the end of October mean that surplus may not shrink as fast as bulls need. Over the coming weeks, the tighter production picture and the December contract roll could flip the balance.

That framing defines the range. Support sits at $3.09, the 200-day EMA, and then $3.00. Resistance begins at $3.30 and extends to $3.40, the barrier the November contract has failed to break all month. A daily close below $3.09 opens a move toward $3.00. A break above $3.40 would turn the picture decisively bullish.

Weather: NOAA Puts 80% Odds on Warmth Across the North-Central States

Weather is the single biggest driver of natural gas prices in October, and the latest forecasts are bearish.

NOAA’s Climate Prediction Center discussion issued October 13 assigns above-normal temperature probabilities extending to 80% across the north-central United States for the coming week. That region, covering the upper Midwest and northern Plains, is among the most heating-sensitive markets in the country. Warmth there in mid-October delays the start of residential and commercial heating demand.

The extended outlook offers no relief. The October 21–27 forecast also favors warmth across much of the United States, with probabilities above 70% in the north-central region. Parts of the western United States favor below-normal temperatures, which could offset some lost demand, but the outlook carries average confidence of about 60%. Forecasters see mostly milder-than-normal temperatures through October 29.

The degree-day numbers quantify the shortfall. The two-week forecast shows 115 heating degree days, essentially in line with 116 a year ago but well below the 10-year norm of 128 and the 30-year norm of 147. Total degree days, combining heating and cooling, stand at 167 against a 10-year norm of 175. Cooling degree days of 52 run above the 10-year norm of 47, but late-season cooling demand is small and fading.

Demand forecasts reflect the warmth. Average gas demand in the Lower 48, including exports, is projected to rise from 103.9 Bcf/d this week to 106.1 Bcf/d next week as seasonally cooler weather arrives. Those forecasts were revised lower from Monday’s outlook. Residential demand is expected to climb from 5.1 Bcf/d to 8.0 Bcf/d, and commercial demand from 6.1 Bcf/d to 7.8 Bcf/d, but both remain well below the 13.4 Bcf/d and 9.4 Bcf/d averages for residential and commercial use across 2025.

Regional differences matter. The Great Lakes and Northeast have seen some early heating demand, but it has been regional rather than national. A cold pocket in the East does not offset widespread warmth across the central states.

An 80% probability of above-normal temperatures does not mean extreme heat. It means heating demand will more likely than not run below normal. A shift toward colder conditions could change the picture quickly, and October forecasts are notoriously unstable.

For the forecast, weather is the dominant bearish factor through the end of October. Until models show a sustained cold shift for early November, the November contract has little reason to break above $3.30.

Storage: 3,500 Bcf, a Shrinking Surplus and Thursday’s 74–77 Bcf Estimate

Storage is where the bullish case lives, and it has been quietly building for two months.

The EIA’s latest weekly report showed Lower 48 working gas at 3,500 Bcf for the week ended October 2, after an 85 Bcf injection. Stocks were 68 Bcf, or 2.0%, above the five-year average of 3,432 Bcf and 130 Bcf, or 3.6%, below the year-earlier level of 3,630 Bcf. The 85 Bcf build fell short of the five-year average injection of 96 Bcf but exceeded market expectations, and futures slipped immediately after the print.

The trend underneath matters more than any single week. That was the eighth consecutive below-normal storage build. The last eight EIA reports added 347 Bcf against a five-year norm of 477 Bcf. Over that stretch, the surplus to the five-year average has fallen from 198 Bcf to 68 Bcf. In early September, storage sat 160 Bcf above the five-year average. Today the cushion is less than half that.

Thursday’s report is expected to continue the trend. Estimates for the week ended October 9 call for an injection of 74 Bcf to 77 Bcf. One forecast puts the build at 74 Bcf, 11 Bcf less than the prior week, 6 Bcf below the year-ago 80 Bcf build and 16 Bcf below the five-year average of 90 Bcf. That would shrink the surplus to the five-year average to 52 Bcf and widen the year-over-year deficit to 136 Bcf. Another estimate puts the build at 77 Bcf, lifting total storage to 3,577 Bcf, 1.6% above the five-year average.

The production disruptions explain the smaller builds. Hurricane Isaias shut in Gulf output during the reporting week, and pipeline problems curtailed supply in several states. Those factors should fade, which means injections could rebound in coming weeks just as warm weather reduces demand.

The EIA’s end-of-season forecast frames the bigger picture. Its October 6 outlook projects end-October inventories of 3,850 Bcf, 2% above the five-year average. That would leave the market well supplied entering winter, though below last year’s level.

For the forecast, Thursday’s number is the most important near-term catalyst. An injection at or below 74 Bcf would extend the run of tight builds and support the $3.09 to $3.10 zone. A build above 80 Bcf would signal that warm weather and recovering production are restoring the surplus, and that would likely push the November contract toward $3.00.

South Central: 1,076 Bcf, 2.3% Below Normal and Salt Caverns 14% Short

The national storage surplus hides a regional imbalance, and it sits in the region that matters most for Henry Hub.

South Central inventories of 1,076 Bcf are 2.3% below their seasonal average, while East and Midwest stocks stand above theirs. East, Midwest, Mountain and Pacific storage are all above their five-year averages. The national total of 3,500 Bcf is 2% above average only because surpluses in the North and West outweigh the South Central deficit.

The tighter detail is in salt storage. South Central salt caverns are 14.0% below normal. Salt storage is the most flexible form of gas storage, able to inject and withdraw quickly. It serves as the short-term balancing tool for the Gulf Coast market, where Henry Hub is located and where most LNG export terminals draw their supply. A 14% shortfall in salt storage means the region has less flexibility to absorb supply disruptions or demand spikes.

South Central did add gas in the latest week. South Central inventories increased 28 Bcf but remained 2.3% below their five-year average. In the same report, the Midwest added 26 Bcf and the East 22 Bcf.

The regional split explains why Henry Hub holds up better than northern hubs. The Gulf Coast is where LNG export demand concentrates, and with 18 Bcf/d flowing to export terminals, the South Central region faces structural demand that northern regions do not. Despite sizable builds, South Central inventories remain below both year-ago levels and the five-year average, reflecting demand pressure from exports and regional consumption.

The deficit is a source of support for Henry Hub specifically. If a cold snap or a production outage hits the Gulf Coast, tight salt storage could push spot prices higher quickly. That risk keeps a floor under the front month even when national weather forecasts are bearish.

The northern surplus works the other way. Excess gas in the Midwest and East cannot all reach the Gulf Coast quickly due to pipeline constraints, which explains part of the extreme regional price divergence visible in spot markets.

For the forecast, South Central’s tightness is the structural support beneath the November contract. It does not override the national weather picture, but it limits how far Henry Hub can fall relative to northern hubs and supports the $3.00 to $3.09 floor.

Production: From a 113.3 Bcf/d Record to a 107.1 Bcf/d Eight-Month Low

US production has dropped sharply in October, and that decline is the main bullish counterweight to warm weather.

Average gas output in the Lower 48 slid from record highs of 113.3 Bcf/d in August and September to 110.6 Bcf/d so far in October. On a daily basis, output was on track to fall to an eight-month low of 107.1 Bcf/d on Tuesday, even as production slowly returns in the Gulf of Mexico. That represents a 6.2 Bcf/d decline from the record, one of the steepest short-term drops this year.

The causes are temporary. The October decline reflects a combination of Hurricane Isaias production shut-ins, force majeure incidents and pipeline problems in Kentucky, Texas, West Virginia and elsewhere over the past month. Offshore, 59% of Gulf of Mexico gas output, or 1.3 Bcf/d, was shut in at the peak on October 9 when Isaias hit the Florida Panhandle. By Monday, that had fallen to 25%, or 0.5 Bcf/d.

Weekly data show the dip and the expected rebound. Lower 48 dry production averaged 111.1 Bcf/d the prior week, 109.4 Bcf/d this week and is forecast at 110.6 Bcf/d next week. Total US supply, including Canadian imports, falls from 118.1 Bcf/d to 116.4 Bcf/d this week before recovering to 117.8 Bcf/d.

The structural capacity is intact. EIA raised its 2026 dry-gas production forecast to 112.2 Bcf/d. The agency reported record July gross withdrawals of 137 Bcf/d, driven mainly by Permian growth, along with July records for dry and marketed production. US dry production is forecast to reach 112.5 Bcf/d in winter 2026–2027, with total supply projected at 119 Bcf/d.

That is the bearish catch. Producers have the capacity to restore output quickly once hurricane shut-ins and pipeline problems clear. Analysts anticipate a production rebound ahead of a winter in which export demand could surge and require near-record supply. If output returns to 112 to 113 Bcf/d by early November while weather stays warm, storage injections would rebound and the surplus would widen again.

Producer economics also matter. At $3.10, Henry Hub sits well below the $3.62 average futures price of 2025. Some producers may defer new drilling or completions at these prices, which would limit the production rebound.

For the forecast, the production dip is a temporary support. It explains the run of below-normal storage builds and why futures have not collapsed despite warm weather. Once output recovers, that support fades.

LNG: Capped at Capacity, 17.4 Bcf/d in October and a Freeport Train Offline

LNG exports are the fastest-growing source of US gas demand, but they cannot grow much further right now, and that cap is central to the forecast.

Average gas flows to the nine major US LNG export plants fell to 17.4 Bcf/d so far in October, down from 17.9 Bcf/d in September and a monthly record of 18.8 Bcf/d in April. Weekly data show some recovery: feedgas averaged 17.0 Bcf/d the prior week, 18.4 Bcf/d this week and is forecast at 18.7 Bcf/d next week. LNG feedgas deliveries reached 17.63 million Dth on October 7, with recent flows holding near 18 Bcf/d.

Freeport has been the drag. Freeport LNG has run one train short of its usual appetite for the past week, reducing US LNG feedgas demand by 0.7 Bcf/d and erasing nearly 5 Bcf of demand in a week. That outage was masked by early-cycle nominations, with a widening gap between Freeport’s initial feedgas nominations and final scheduled deliveries. A return of the missing train would add 0.7 Bcf/d of demand and support prices.

The capacity cap limits upside. US LNG exports are already near capacity, with feedgas around 17.5 Bcf/d in October. Until new export units come online, global prices have less pull on Henry Hub, leaving domestic weather and weekly storage reports to do most of the work. The US cannot export much more LNG until units under construction enter service in coming months and years.

New capacity is on the way. LNG exports are expected to rise by 2.2 Bcf/d over the winter as new liquefaction units start up. Lasting LNG supply disruptions caused by the Middle East conflict have made new US supply additions even more important heading into winter. As those units ramp, US export demand will grow and tie Henry Hub more closely to global prices.

The ramp timing matters. Each new train that starts up adds roughly 0.5 to 1.0 Bcf/d of demand. If several come online in November and December, export demand could approach or exceed the April record of 18.8 Bcf/d. That would absorb part of the production rebound and limit storage builds.

For the forecast, LNG is a structural bullish force with a near-term ceiling. Exports keep a floor under South Central demand and Henry Hub prices, but until new capacity starts, they cannot respond to European and Asian price spikes. The Freeport train’s return is the next near-term catalyst on the export side.

The $28 TTF Disconnect: Why Europe’s Crisis Barely Touches Henry Hub

The gap between US and global gas prices has rarely been wider, and understanding it is essential to forecasting Henry Hub.

European gas traded at $28.20 per mmBtu at the Dutch TTF benchmark, a 45-month high, while Asia’s Japan-Korea Marker traded at $26.09. Henry Hub futures traded near $3.12. European gas costs nine times as much as US gas. A year ago, TTF traded at $10.88 and JKM at $11.11. Both have more than doubled while Henry Hub has fallen.

The cause is the Middle East war. Global gas prices have spiked primarily due to supply disruptions linked to Russia’s invasion of Ukraine in 2022 and the US-Israeli war with Iran this year. Qatar, one of the world’s largest LNG exporters, ships its cargoes through the Strait of Hormuz, and disruptions there have cut global LNG supply. Iran’s attacks on tankers in Hormuz and Houthi strikes on Saudi infrastructure keep that risk premium high.

US prices have not followed. US prices have not reacted much to the war in Iran because the US produces all the gas it consumes and US LNG companies are already liquefying as much fuel as they can. No matter how high global gas prices go, the US cannot export much more until new units start up. The bottleneck is physical: LNG export capacity, not demand, limits how much US gas reaches global markets.

The arbitrage is enormous. US exporters buy gas near $3 and sell LNG cargoes into markets paying $26 to $28. Even after liquefaction, shipping and regasification costs, that spread generates large profits for LNG companies like Cheniere. Those profits will drive investment in new export capacity, which over time will tie Henry Hub more closely to global prices.

Oil is a separate story. Brent crude holds near $106 a barrel and WTI near $95, driven by the same Middle East conflict. Oil and gas prices in the US have decoupled: crude trades on global seaborne markets, while US gas trades on domestic pipeline balances.

Inflation creates an indirect link. September CPI rose 3.7% year over year, with gasoline up 9.1% and the energy index up 5.2%. Natural gas is a smaller CPI component, and low US gas prices have helped keep utility costs in check even as oil-driven fuel prices surge.

For the forecast, the global price spike is a long-term bullish factor for Henry Hub, as new export capacity will eventually transmit higher global prices to the US market. In the near term, it is almost irrelevant.

Power Burn, Wind and a PJM Emergency Order

Power generation is the largest single source of US gas demand, and this week’s data show it weakening just as heating demand stays absent.

Power plant gas demand is forecast to fall from 38.7 Bcf/d the prior week to 35.3 Bcf/d this week and 31.4 Bcf/d next week, compared with 36.0 Bcf/d on average across 2025. As cooling demand fades and heating demand has not yet arrived, power burn typically drops to its seasonal low in October. Gas-fired plants generate about 40% of US electricity, so weaker power demand translates directly into larger end-of-season inventories.

Wind is displacing gas this week. Wind’s share of US power generation is projected at 17% for the week ending October 16, up from 8% the prior week, while natural gas’s share falls to 37% from 44%. Gas’s share is also below the 40% of 2025 and 42% of 2024. A windy week in the shoulder season can cut gas burn by several Bcf/d, adding to storage.

Grid stress in the mid-Atlantic adds a twist. The Department of Energy issued an emergency order on October 12, effective October 13 to 16, authorizing PJM to dispatch specified units and use backup resources under defined reliability conditions, citing elevated demand and planned generation and transmission outages. Next-day power prices at PJM West jumped to $160.26 per megawatt-hour from $123.96, far above the $57.52 level of the same month last year.

The read-through for gas is mixed. The emergency confirms reliability concerns, but it does not establish that authorized units ran or that gas consumption rose by a specific amount. Electric demand may not follow the heating outlook mechanically, as maintenance and dispatch decisions alter the fuel mix. High power prices in PJM could pull more gas-fired generation online if units are available, supporting regional gas demand.

Hydroelectric conditions are relevant in the West. Northwest river forecasts for the 2027 water year show 87% of normal for the October-to-September period, up from 86% the prior day. Lower hydro output would raise gas burn in western power markets.

Industrial demand remains steady. Industrial gas use is forecast at 22.3 Bcf/d this week and 23.1 Bcf/d next week. Over the longer term, US industrial gas demand has reached 29.46 Bcf/d in 2026 year to date, up from 27.50 Bcf/d in 2020.

For the forecast, the power sector adds to the bearish near-term picture. Falling power burn and strong wind generation mean more gas flows into storage at exactly the moment bulls need injections to stay small.

Regional Basis Collapse: Transco Z6 at $0.88, Algonquin at $1.17

Spot prices across US trading hubs show how unevenly the warm weather and production picture is playing out.

Northeast prices have collapsed. Next-day gas at Transco Zone 6 New York traded at $0.88 per mmBtu, compared with $2.26 a year ago and a 2025 average of $3.53. Algonquin Citygate, which serves New England, traded at $1.17 against $2.51 a year ago and a 2025 average of $6.08. Enbridge South, the Appalachian supply hub formerly known as Dominion South, traded at just $0.61.

Those prices reflect a regional glut. Appalachian production is trapped behind limited pipeline capacity, and with mild weather limiting Northeast demand, gas backs up in the region and prices fall far below Henry Hub. The East region’s storage surplus confirms the oversupply.

Other hubs show different dynamics. Chicago Citygate traded at $2.44, below last year’s $2.92. Waha, the West Texas hub for Permian associated gas, traded at $1.89, compared with $0.00 a year ago, when pipeline constraints left Permian gas nearly worthless. New pipeline capacity out of the Permian has improved Waha prices. AECO in Canada traded at $1.24.

Western prices are firmer. PG&E Citygate traded at $3.56 and SoCal Citygate at $3.20, both near or above Henry Hub, reflecting the cooler weather forecast for parts of the West and western pipeline constraints.

Henry Hub stands apart. At $3.10 next-day, it trades well above the northern and Appalachian hubs because it sits at the center of Gulf Coast demand, where LNG exports, petrochemical plants and the South Central storage deficit all concentrate.

The basis spreads have forecasting value. Wide discounts at Northeast and Appalachian hubs show that the national oversupply is concentrated in specific regions. As winter arrives and Northeast heating demand surges, those discounts typically narrow sharply. A cold snap in New England can send Algonquin prices from $1 to $10 or more within days.

For the forecast, the regional data show that Henry Hub’s weakness is relatively contained. The real price collapse is in the Northeast and Appalachia, where trapped supply meets mild weather. Henry Hub’s link to Gulf Coast LNG demand keeps it near $3.

Winter Setup: El Niño, 112.5 Bcf/d Production and 3,850 Bcf in Storage

The November contract is a bridge to winter, and the winter outlook shapes how far the market is willing to sell the near term.

El Niño is the wild card. The prospect of a historically strong El Niño is raising questions about US heating demand this winter, but expanding LNG exports, subdued production and potential regional supply constraints are complicating the outlook. Strong El Niño winters have historically brought milder temperatures to the northern United States, reducing heating demand in key consuming regions. A mild winter would leave storage elevated into spring and pressure prices.

Supply looks ample. US dry gas production is forecast to reach 112.5 Bcf/d in winter 2026–2027, with total supply projected at 119 Bcf/d. Supply growth is seen outpacing winter demand despite LNG gains, with LNG exports rising by 2.2 Bcf/d and storage withdrawals easing.

The EIA’s baseline is comfortable. The agency forecasts end-October inventories of 3,850 Bcf, 2% above the five-year average, alongside rising LNG exports and production growth. Ample inventories relative to the five-year average limit upward price pressure, as ongoing production growth supplies rising LNG exports and domestic demand growth. The agency’s model inputs were finalized October 1, so newer NOAA outlooks and operational developments are not reflected.

The contract roll offers seasonal support. At the end of the month, trading will roll into the December contract, a time that is typically more bullish. December carries more winter demand risk than November, and the futures curve typically prices it at a premium. As the November contract expires on October 28, front-month price charts will shift to December, which often lifts the headline price even if fundamentals are unchanged.

The global backdrop provides a tail risk. With TTF at a 45-month high and global LNG supply disrupted, any further escalation in the Middle East could push global prices higher, increasing pressure to maximize US exports as new capacity starts up.

For the forecast, the winter setup is balanced. Ample storage, strong production capacity and a possible El Niño argue against a major winter rally. Rising LNG exports, the South Central deficit and the seasonal December roll argue against a deep collapse.

Price History: From $7.72 in January to $2.95 in September

Natural gas has had a volatile 2026, and the trajectory explains where the market sits now.

The year started with a spike. Henry Hub spot averaged $7.72 in January 2026, driven by Winter Storm Fern, sustained heating demand, record storage withdrawals and temporary price spikes. Prices fell to $3.62 in February as the cold eased, and the storage season began with working gas at 1,829 Bcf, near the five-year average.

Spring and summer brought a steady decline. Spot prices averaged $3.14 in June, $2.89 in July, $2.79 in August and $2.95 in September. Record production of 113.3 Bcf/d in August and September kept the market well supplied, and storage built steadily through the summer. By early September, inventories sat 160 Bcf above the five-year average.

The EIA’s forecasts tracked the decline. The agency’s annual spot price forecast has fallen more than 20% since its February 2026 estimate of $4.31 per mmBtu, which was influenced by the winter storm.

October has been a period of stabilization. Henry Hub spot traded at $3.00 on October 1, $2.90 on October 2, $2.96 on October 5 and $3.03 on October 6. Front-month futures have oscillated between roughly $3.10 and $3.30 over the past two weeks. Henry Hub futures traded at $3.35 at this point last year, averaged $3.62 across 2025 and $3.79 over the five years from 2021 to 2025.

The current price sits well below historical norms. At $3.119, the November contract is 14% below the 2025 average and 18% below the five-year average. That discount reflects the strong production base, a storage surplus and the cap on LNG exports.

The low point of the cycle may have passed. Henry Hub has shown consistent higher lows since April 2026 on the futures chart, and global demand supports bullish momentum. Since the August spot average of $2.79, prices have stabilized near $3, and the shrinking storage surplus suggests the market has been tightening underneath the surface.

For the forecast, the price history shows a market that has corrected from winter extremes and found a base near $3. The structure of higher lows since April supports the view that $3.00 is a meaningful floor, while the failure to break $3.30 to $3.40 shows that bulls need a catalyst to push higher.

Chart Map: $3.09 EMA, $3.00 Floor, $3.30–$3.40 Ceiling

The technical picture for the November contract is defined by a clear range.

Support begins at $3.09, the 200-day exponential moving average, which has acted as the major support level for the contract. Technical pivot analysis from Tuesday’s session puts first support at $3.105, just above that average. Wednesday’s price of $3.119 sits 0.9% above the 200-day EMA, close enough that a test is likely. Below $3.09, the next support sits at $3.00, the round-number level and the floor that has held for the spot market since August. A daily close below $3.00 would break the higher-low structure in place since April.

Resistance begins at the daily pivot of $3.182, then $3.20 to $3.24, where the contract traded on Friday and earlier this month. The key ceiling is the $3.30 to $3.40 zone. The November contract has struggled to break above the barrier that starts at $3.30 and extends to $3.40, with first technical resistance at $3.325. A break above $3.40 would be a significant bullish signal and open the path toward the higher levels of the summer range.

The structure is a range with a slight bearish tilt in the short term. Higher lows since April support the longer-term picture, while repeated failures at $3.30 to $3.40 show sellers defending the top of the range. The minor trend is down as warm weather caps rallies.

Momentum is mixed. Technical indicators show a neutral reading, with sixteen neutral signals against four buy and two sell signals in the latest scan. The contract is neither overbought nor oversold, which leaves room for a move in either direction depending on Thursday’s storage data and weather updates.

Volatility will rise into expiry. The November contract expires on October 28, and expiry weeks often bring sharp moves as positions roll into December. The December contract typically trades at a premium, which can lift front-month charts after the roll.

For the forecast, the levels are clear. A daily close below $3.09 targets $3.00. A close above $3.40 targets $3.60 as the next resistance area. Between those levels, the November contract trades in a range, currently near its lower boundary.

Catalysts: Thursday’s EIA Storage, NOAA Long-Lead Outlooks, Freeport and the October 28 Expiry

The next two weeks carry several events that will decide whether natural gas breaks its range.

Thursday, October 15: the EIA Weekly Natural Gas Storage Report for the week ended October 9. Estimates range from 74 Bcf to 77 Bcf, against a five-year average of 90 Bcf and a year-ago build of 80 Bcf. A build at or below 74 Bcf would mark a ninth straight below-normal injection and shrink the surplus to 52 Bcf, supporting the $3.09 to $3.10 zone. A build above 80 Bcf would signal recovering production and push futures toward $3.00.

Thursday, October 15: NOAA’s long-lead seasonal outlooks. These forecasts will shape expectations for November through February and update the El Niño picture. A colder-than-expected winter outlook would lift the December contract and support the November contract into expiry. A warm outlook would reinforce the bearish case.

Daily: weather model updates. The GFS and European models drive day-to-day price action in October. Any shift toward colder conditions for the first week of November would trigger short covering.

Daily: LNG feedgas data. Freeport’s return to full operation would add 0.7 Bcf/d of demand. New liquefaction trains starting up would add more.

Ongoing: production recovery. Gulf of Mexico shut-ins from Hurricane Isaias have fallen from 59% to 25%. A full recovery, along with resolution of pipeline problems in Kentucky, Texas and West Virginia, would return output toward 112 to 113 Bcf/d and weigh on prices.

October 16: the end of the DOE emergency order for PJM. Power demand patterns after the order expires will show whether grid stress persists.

October 22: the next EIA storage report, covering the week ended October 16.

October 28: November contract expiry. Trading rolls into the December contract, which typically carries a winter premium.

Background risks include the Middle East conflict, which could push global LNG prices higher and increase pressure on US exporters, and any new hurricane activity in the Gulf.

Natural Gas Forecast and Verdict: Bearish Near Term Inside a $3.00–$3.40 Range, $3.00 Target Below $3.09

The verdict for November natural gas futures is bearish in the near term within a defined range. At $3.119, the contract sits 5 cents below Tuesday’s $3.169 settlement and just above its $3.09 200-day EMA. NOAA assigns up to 80% odds of above-normal temperatures across the north-central states for the coming week and more than 70% for October 21 to 27. The two-week forecast shows 115 heating degree days against a 10-year norm of 128. Power burn is falling from 38.7 Bcf/d to 31.4 Bcf/d, and wind’s share of generation has jumped to 17%.

The bullish offsets are real. Lower 48 production has dropped from a record 113.3 Bcf/d to an eight-month low of 107.1 Bcf/d on hurricane shut-ins and pipeline problems. Storage injections have run below normal for eight straight weeks, cutting the surplus from 198 Bcf to 68 Bcf, and Thursday’s report is expected to show another below-normal build of 74 Bcf to 77 Bcf. South Central storage sits 2.3% below normal, with salt caverns 14% short. LNG exports remain near capacity at 17.4 Bcf/d to 18.4 Bcf/d, with Freeport’s missing train set to return.

The disconnect from global markets limits the upside. European gas at $28.20 and Asian gas at $26.09 have no immediate effect on Henry Hub because US export capacity is maxed out. EIA projects end-October storage at 3,850 Bcf, 2% above the five-year average, and winter production of 112.5 Bcf/d leaves the market well supplied.

The base case through the October 28 expiry is a test of $3.09. A daily close below the 200-day EMA targets $3.00, a 3.8% decline from current levels. A build above 80 Bcf on Thursday or a further warm shift in weather models would accelerate that move.

The bullish path requires a storage build at or below 74 Bcf, a colder shift in early-November forecasts, and Freeport’s return to full feedgas. That combination would likely lift the November contract back toward $3.30, a 5.8% gain. A daily close above $3.40 would break the range and target $3.60, opening the door to a stronger December contract rally into winter.

Forecast: bearish near term, with a $3.00 downside target on a confirmed break of $3.09 and a $3.30 to $3.40 upside test only on a tight storage print and colder forecasts. The structure of higher lows since April and the seasonal December roll make $3.00 a strong floor, while warm weather keeps $3.40 out of reach until the heating season begins in earnest.

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