November NG Slips Below $3 as Decade-High Storage Meets Capped LNG Exports — $2.75 in Sight

U.S. natural gas futures are under pressure. The November NYMEX contract, now the front month, is trading at $2.953 per million British thermal units, down 7.3 cents, or 2.4%, from Wednesday's $3.026 settlement. The contract has given back all of Wednesday's bounce and is back below $3.00, the level buyers defended earlier in the week. Natural gas is up just 0.1% over the past month and down 14.2% from a year ago.

The October contract rolled off the board after settling at $3.011 on Sept. 29. November takes over as the benchmark at a time when the market is deciding whether the injection season ends with a glut or a comfortable cushion. The answer so far points toward the glut.

The thesis for this forecast is that U.S. natural gas is a domestic market cut off from a global crisis. In Europe, the Dutch TTF benchmark is at €74.06 per megawatt-hour, up 135% from a year ago. Asian spot LNG reached a four-year high of $29.56 per MMBtu in September. The Strait of Hormuz, which carries 19% of global LNG supply, has been closed for seven months. Yet Henry Hub trades below $3.00. The reason is physical: U.S. LNG export terminals are running near full capacity, so the U.S. can't ship more gas abroad no matter how high overseas prices climb. Every extra molecule produced in the Permian and Haynesville stays home, and production is near a record.

That leaves U.S. prices driven by domestic fundamentals, and those are bearish. Lower 48 dry gas production rose to a near-record 115.0 billion cubic feet per day in late September. The U.S. Energy Information Administration forecasts working gas in storage will reach 3,969 Bcf by Oct. 31, 5% above the five-year average and the highest end-of-October level in a decade. The weather outlook through mid-October shows warm conditions in the South and mild temperatures elsewhere, with no meaningful cold.

The near-term focus is this week's EIA storage report, covering the week ended Sept. 25. The consensus calls for a 63 Bcf injection, well below the five-year average of 80 Bcf for the week. A light build would normally support prices. But the market already priced the low estimate on Wednesday, and with no cold in the forecast, sellers are pressing anyway.

The levels are clear. November must hold $2.90 to avoid a slide toward $2.75. A close back above $3.05 would suggest Wednesday's bounce can resume. The winter outlook is the only factor that can change the picture, and the forecast models don't show it yet.

Storage at 3,351 Bcf, 95 Bcf Above the Five-Year Average

U.S. natural gas storage is the anchor of the bearish case. Working gas in storage totaled 3,351 Bcf as of Sept. 18, according to the most recent EIA Weekly Natural Gas Storage Report. The week's injection was 53 Bcf, matching expectations. Stocks were 146 Bcf below year-ago levels but 95 Bcf, or 2.9%, above the five-year average of 3,256 Bcf. Total working gas is within the five-year historical range.

The build pattern in September has been modest. Injections were 30 Bcf in the week ending Aug. 28, 40 Bcf in the week ending Sept. 4, 44 Bcf in the week ending Sept. 11, and 53 Bcf in the week ending Sept. 18. Each of those weeks came in near or below the five-year average for the period. The surplus to the five-year average has narrowed from 148 Bcf on Sept. 4 to 95 Bcf on Sept. 18, as hot weather in the South kept power-sector demand elevated.

The regional picture shows strength in the consuming regions. The East held 815 Bcf as of Sept. 18, up 20 Bcf for the week, 1.5% above year-ago levels and 5.2% above the five-year average. The Midwest carried 959 Bcf after a 25 Bcf build, 1.9% above a year earlier and 3.5% above the five-year average. The East and Midwest are the regions that draw most heavily during winter, and their above-average levels reduce winter supply risk.

The South Central region has been weaker. In the week ending Sept. 4, South Central withdrew 7 Bcf, including an 11 Bcf draw from salt caverns, while every other region injected. Salt storage serves the Gulf Coast, where LNG export terminals are concentrated. Withdrawals from salt storage in early September reflect strong LNG feedgas demand and hot weather in Texas and Louisiana.

This week's report, covering the week ended Sept. 25, carries a consensus of 63 Bcf, with estimates as high as 64 Bcf. That compares with a 53 Bcf injection in the same week last year and a five-year average of 80 Bcf. A 63 Bcf build would narrow the surplus to the five-year average to roughly 78 Bcf and leave total storage near 3,414 Bcf.

The EIA's end-of-season forecast is the more important number. The agency expects storage to reach 3,969 Bcf by Oct. 31, 5% above the five-year average and 1% above October 2025 levels. Inventories on track to end October above 3.9 Tcf have historically been correlated with sub-$3.00 pricing. That historical relationship is why the market is trading below $3.00 now.

Production Near Record at 115.0 Bcf per Day

Supply growth is the main reason storage is comfortable despite strong demand. Lower 48 dry gas production rose to a near-record 115.0 Bcf per day in late September. The EIA forecasts U.S. dry natural gas production will average 111.70 Bcf per day in 2026, up from 107.64 Bcf per day in 2025, and rise further to 115.90 Bcf per day in 2027.

The Permian Basin is driving much of the growth. Most Permian natural gas is produced as a byproduct of oil drilling, which means it flows regardless of gas prices. The EIA notes that Permian gas production has been growing faster than crude oil production as gas-to-oil ratios rise in maturing wells. With WTI crude at $91.74 and Brent above $100, oil producers have strong incentives to keep drilling, and that drilling brings associated gas to market even when Henry Hub prices are weak.

The Haynesville Shale in Louisiana and East Texas is the other growth engine. Unlike the Permian, Haynesville production is driven mainly by gas prices, and the region sits close to the Gulf Coast LNG export terminals. Haynesville producers have increased output to supply LNG feedgas, and the EIA credits rising Permian and Haynesville production for supporting storage builds over the summer.

The supply response creates a ceiling on Henry Hub prices. When prices rise above $3.50, Haynesville producers add rigs and completions, bringing more supply within months. When prices fall below $2.50, they cut back. The Permian's associated gas adds a floor of supply that doesn't respond to gas prices at all. That combination tends to keep Henry Hub trading in a range between $2.50 and $3.50 absent a major weather or export shock.

Producers like EQT (NYSE: EQT), Chesapeake (NYSE: CHK) and Coterra Energy (NASDAQ: CTRA) face a challenging pricing environment. With Henry Hub below $3.00, many dry gas producers are earning thin margins. EQT, focused on the Appalachian Basin, has pipeline access to Gulf Coast and East Coast markets but still prices off Henry Hub. Producers with oil exposure, like Coterra, benefit from high crude prices that offset weak gas prices.

For the forecast, production is the variable most likely to keep prices capped. Even a cold snap would be met with rising supply from the Haynesville within weeks. A sustained rally above $3.50 would require a demand shock large enough to outrun supply growth, and the current weather outlook doesn't show one.

LNG Exports: Terminals at Capacity, Henry Hub Insulated

U.S. LNG exports are the key link between Henry Hub and the global gas crisis, and the link is constrained. The U.S. exported an estimated 17.9 Bcf per day of LNG in March, the second-highest monthly volume since the record 18.4 Bcf per day in December 2025. LNG terminals are running at high utilization rates, which limits further export growth and, in turn, limits how much global prices can pull Henry Hub higher.

That constraint explains the extraordinary gap between U.S. and global prices. At €74.06 per megawatt-hour and an exchange rate of 1.13 dollars per euro, European TTF gas costs roughly $24.50 per MMBtu. Henry Hub trades at $2.953. European gas is selling at more than eight times the U.S. price. In normal markets, that spread would draw every available cargo across the Atlantic. With U.S. terminals already full, the spread can't close.

LNG feedgas, the gas flowing to U.S. export terminals, remains large but eased slightly last week. Feedgas varies with terminal maintenance, weather on the Gulf Coast and the timing of new capacity. Any terminal outage reduces demand for U.S. gas and adds to storage, which is bearish for Henry Hub. Any new terminal startup or capacity expansion adds demand, which is bullish.

New export capacity is the most important medium-term catalyst for Henry Hub. Several U.S. LNG projects are under construction or ramping up, including expansions at existing terminals. As new capacity comes online through 2026 and 2027, U.S. export volumes will rise, pulling more domestic gas into the global market and tightening the U.S. balance. Cheniere Energy (NYSE: LNG), the largest U.S. LNG exporter, benefits directly from the wide spread between Henry Hub and global prices, since it buys gas at U.S. prices and sells LNG into higher-priced markets.

The EIA has said U.S. Henry Hub prices have remained generally insulated from price volatility abroad since the Strait of Hormuz closed on Feb. 28. That insulation is the defining feature of the 2026 U.S. gas market. A global supply shock that would normally lift all gas prices has instead created a two-tier market: tight and expensive abroad, comfortable and cheap at home.

For the forecast, LNG capacity sets the ceiling on how much global tightness can affect Henry Hub. Until meaningful new export capacity comes online, U.S. prices will be driven by domestic weather, production and storage. The global crisis is a background factor, not a direct driver.

Europe: TTF at €74.06, Storage 71% Full Heading Into Winter

Europe's gas market is the mirror image of the U.S. market. The Dutch TTF benchmark rose 2.35% to €74.06 per megawatt-hour on Oct. 1, up 135% from a year ago. TTF gained roughly 60% in the third quarter. It peaked above €80 on Sept. 14 and 15, fell to €75.025 on Sept. 25, and touched €68.61 on Sept. 30, its lowest since August, before rebounding Thursday.

Europe's storage position is the core problem. EU gas storage facilities are roughly 71% full, well below the five-year seasonal average. In mid-August, EU-wide storage stood at 60.8%, with Germany at only around 50%. Europe typically targets 90% or more by November to get through winter safely. With weeks left in the injection season, reaching that target looks unlikely, and Europe will enter winter with less of a cushion than in recent years.

The Qatar disruption drives the European shortfall. QatarEnergy declared force majeure on March 4 after Iranian drone attacks targeted its facilities. Qatar accounts for nearly 20% of global LNG exports, and roughly 80 million tonnes per year of LNG transits the Strait of Hormuz. In July, Qatar's Transport Ministry urged all vessels to temporarily cease maritime activity, the first blanket suspension by a Gulf state during the conflict, with direct implications for exports from Ras Laffan.

Qatari LNG is trickling back. At least five QatarEnergy carriers transited the Strait of Hormuz with their tracking transponders turned off in the week to Sept. 25. That pulled Asian spot LNG prices from a four-year high of $29.56 per MMBtu toward $26.20. Traders are holding a risk premium until Qatari exports resume at commercial scale.

Asia and Europe are competing for the same cargoes. The spread between Asian and European prices flipped in March from a European premium to an Asian premium, which diverted flexible LNG cargoes to Asia. European buyers now compete directly with Asian buyers for expensive LNG, with most expecting Europe to win the bidding war by paying higher prices. Both TTF and Asian prices recorded their highest second-quarter averages since 2022.

Demand destruction is already happening. Global gas demand contracted in the first half of 2026 and is expected to decline for the year, the third annual decline this decade. Asian demand is forecast to fall 0.5% as higher LNG prices push power producers toward coal. European demand is expected to fall more than 2% as renewables grow and high prices reduce industrial gas use.

For the Henry Hub forecast, Europe matters mainly through LNG demand. As long as European and Asian prices stay far above U.S. levels, U.S. terminals will run at capacity, providing a steady floor of export demand. Europe's tight storage also raises the risk of a winter price spike that could eventually drive investment in more U.S. export capacity.

Weather: Warm South, Mild North, No Cold Through Mid-October

Weather is the biggest short-term driver of Henry Hub, and the forecast is bearish. The outlook through Oct. 7 shows warm to hot conditions across the South and mild temperatures nearly everywhere else. California is baking in triple-digit heat. Outside California, none of that weather burns much gas. The Oct. 5 to Oct. 14 outlook doesn't have any meaningful cold either.

Heat in the South supports some power-sector demand, since gas-fired plants supply much of the electricity for air conditioning. In late September, forecasts for triple-digit temperatures briefly lifted prices. But early-October heat burns far less gas than July or August heat, because the overall cooling load is smaller and days are shorter. The demand boost from late-season heat is modest.

The shoulder season is starting. October is typically one of the lowest-demand months of the year for natural gas, falling between the summer cooling season and the winter heating season. Mild temperatures across most of the country mean neither heating nor cooling demand is strong. Storage injections typically remain large through October as a result, which adds to inventories and weighs on prices.

Cooler weather in late September already weighed on the market. The October contract fell 1.06% on Sept. 22 as forecasts turned cooler, reducing electricity demand for cooling. The market is now looking past the end of cooling season toward the start of heating season, and no early cold has shown up in the models.

The first meaningful cold of the season is the catalyst bulls need. In past years, early cold snaps in late October or November have driven sharp rallies in Henry Hub as heating demand jumped and storage injections slowed or turned to withdrawals. A colder run in the weather models is the only factor that would make short positions uncomfortable in the near term.

The winter outlook beyond October matters more for the full-season price. A cold winter would draw storage down faster and could push Henry Hub well above $4.00 by January. A mild winter would leave storage high and keep prices below $3.00. With storage starting the winter 5% above the five-year average, the market has a cushion that reduces the risk of a supply crunch, even in a moderately cold winter.

For the forecast, weather is bearish through mid-October. Prices are likely to stay under pressure until the models show cold. Traders should watch the six- to 15-day forecasts closely, since a shift to colder conditions could trigger a short-covering rally of 10% or more in a few sessions.

The EIA Outlook: $3.43 for 2026, $3.28 for 2027

The EIA's Short-Term Energy Outlook provides the official baseline for Henry Hub. The September outlook forecasts Henry Hub will average $3.43 per MMBtu in 2026, down from $3.53 in 2025, and $3.28 in 2027. The next outlook is due Oct. 6.

The 2026 average forecast implies higher prices ahead. Henry Hub has traded below $3.50 for most of the year, and the current price of $2.953 is well below the $3.43 annual average forecast. For the full-year average to reach $3.43, prices in the fourth quarter would need to rise meaningfully, most likely during the early winter heating season.

The EIA's storage forecast tempers that view. The agency expects storage to total 3,969 Bcf on Oct. 31, 5% above the five-year average and 1% above October 2025 levels. Relatively high inventories partly reflect strong production growth in recent months. High storage entering winter tends to cap price spikes, since there is more gas available to draw on during cold weather.

Consumption is growing, but more slowly than production. The EIA forecasts U.S. natural gas consumption will average 92.21 Bcf per day in 2026, up from 91.88 Bcf per day in 2025, and rise to 94.28 Bcf per day in 2027. Production is forecast to grow by more than 4 Bcf per day in 2026, far outpacing consumption growth of roughly 0.3 Bcf per day. The gap is absorbed by LNG exports and storage.

Natural gas's share of electricity generation is expected to hold at 40% in 2026 and 2027, down from 42% in 2024. Rising renewable generation is taking share from gas in power markets. That trend limits the growth of power-sector gas demand, even as electricity demand rises with AI data center construction.

Data center demand is the wildcard. AI infrastructure is driving electricity demand growth, and much of that demand is being met by gas-fired power plants. Amazon signed a 20-year power deal with Constellation Energy's Calvert Cliffs nuclear plant on Wednesday, part of a trend toward long-term power contracts by hyperscalers. Where nuclear and renewables can't meet demand, new gas plants fill the gap. That supports gas demand over the medium term.

For the forecast, the EIA baseline argues that current prices are below fair value for the year. The path to the EIA's $3.43 average runs through a winter rally. The timing of that rally depends on weather, and it is unlikely to start before late October.

The Global Price Gap: TTF at 8x Henry Hub

The gap between U.S. and global gas prices has reached an extreme level, and it tells the story of the 2026 market. European TTF at €74.06 per megawatt-hour equals roughly $24.50 per MMBtu. Asian spot LNG traded near $26.20 per MMBtu after easing from $29.56. Henry Hub trades at $2.953. Global gas costs eight to nine times more than U.S. gas.

The spread has widened all year. Before the Strait of Hormuz closed on Feb. 28, TTF traded near $11 per MMBtu and Henry Hub near $3. By the week ending April 24, TTF futures had risen to $14.80 per MMBtu, 35% higher than before the closure, and Asian JKM futures rose 51% to $16.02. In the second quarter, TTF averaged near $16 per MMBtu and Asian spot LNG $17.5. The spread kept widening through the summer as the Hormuz disruption persisted.

That spread represents a huge arbitrage that U.S. exporters can only partly capture. An LNG exporter buying gas at $2.953, paying roughly $3 per MMBtu for liquefaction and $1 to $2 for shipping, could deliver gas to Europe for $7 to $8 per MMBtu and sell it for $24.50. The margin is enormous. Companies with spare export capacity capture that margin. Companies without it can't.

The spread also shows how integrated and fragmented the global gas market is at the same time. Prices in Europe and Asia move in near lockstep, since both compete for the same flexible LNG cargoes. Henry Hub moves independently, since U.S. export capacity is maxed out. Without more export capacity, the U.S. market behaves like an island.

The spread is unlikely to close soon. Even a full reopening of the Strait of Hormuz would take months to restore Qatari exports to pre-war levels. Europe's low storage means it will be competing for LNG all winter. Asian demand remains strong despite some coal switching. New U.S. export capacity will come online gradually, not all at once.

For the Henry Hub forecast, the spread is a long-term bullish factor and a short-term neutral one. As U.S. export capacity grows, Henry Hub will gradually be pulled toward global prices. That process takes years, not weeks. In October, domestic weather and storage matter far more.

The Oil Link: Brent at $100.15, Associated Gas Keeps Flowing

Oil prices affect natural gas through supply more than demand. Brent crude rose 2.2% to $100.15 on Thursday after China suspended fuel exports for October, and WTI rose 1.5% to $91.74. High oil prices give producers strong incentives to keep drilling in the Permian Basin, where natural gas comes out of the ground alongside oil.

That associated gas flows regardless of natural gas prices. Permian producers drill for oil, and the gas is a byproduct. When oil prices are high, Permian drilling stays strong, and associated gas production keeps rising. The EIA notes that Permian gas production has been growing faster than oil production as gas-to-oil ratios rise. High oil prices are bearish for Henry Hub because they keep associated gas supply growing.

The Waha Hub in West Texas shows the effect. Permian gas often trades at a steep discount to Henry Hub because pipeline capacity to move gas out of the basin is limited. When pipelines are full, Permian gas prices can fall below zero, forcing producers to pay to have their gas taken away. New pipeline capacity has eased that constraint over the past two years, sending more Permian gas to the Gulf Coast and adding to supply at Henry Hub.

Oil and gas prices have diverged sharply in 2026. Brent is up 50.8% from a year ago, and WTI is up 49%. Henry Hub is down 14.2%. Normally, oil and gas prices move together to some degree, since they compete in some uses and are produced together in many fields. This year, oil has been driven by the Iran conflict and supply disruptions, while U.S. gas has been driven by domestic oversupply.

The diesel squeeze has an indirect gas angle. U.S. diesel futures jumped 4.5% to $5.1175 a gallon on Wednesday. In some industrial and power applications, high diesel prices encourage switching to natural gas, which adds modest demand. That effect is small relative to the overall U.S. gas balance.

For the forecast, high oil prices are a bearish factor for Henry Hub through the supply channel. As long as Brent stays above $90 and WTI above $85, Permian drilling will remain strong and associated gas will keep flowing. A sharp drop in oil prices, triggered by a ceasefire in the Iran conflict, would slow Permian drilling over time and modestly tighten the U.S. gas balance.

Technical Map: $2.90 Floor, $3.05 Pivot, $3.30 Ceiling

November natural gas futures are testing a key technical zone. The contract is trading at $2.953, below the $3.00 level that buyers defended on Wednesday. The failure to hold $3.00 on Thursday morning is a bearish signal, suggesting the light storage estimate didn't attract enough buying to sustain a bounce.

The first support is $2.90, the area where the November contract found buyers in late September. A daily close below $2.90 would open a decline toward $2.75 to $2.80, the next support zone. Below that, $2.60 is the level where the market found a floor earlier in the injection season.

The broader technical picture is more constructive. Henry Hub futures have shown consistently higher lows since April 2026. The contract hasn't broken that pattern yet. A move below $2.75 would break the series of higher lows and signal that the trend from April has ended.

On the upside, $3.00 is the first resistance, now acting as a ceiling after Thursday's failure. Above that, $3.05 is the pivot level from Wednesday's high. A daily close above $3.05 would suggest the selling has exhausted and a move toward $3.15 to $3.20 is possible. The $3.30 level is the major resistance, the top of the late-summer range.

Futures volatility is elevated. The October contract moved 1% to 2% on most days in late September, and the November contract is showing similar daily ranges. Leveraged ETFs like the ProShares Ultra Bloomberg Natural Gas (AMEX: BOIL) and ProShares UltraShort Bloomberg Natural Gas (AMEX: KOLD) magnify those moves. The United States Natural Gas Fund (AMEX: UNG) tracks front-month futures and is affected by the contango in the futures curve.

Contango is important for gas ETFs. Winter contracts trade at higher prices than the front month, reflecting expected heating season demand. ETFs that roll from expiring contracts into later months pay that premium, which erodes returns over time. Investors using UNG or BOIL to bet on a winter rally should be aware that contango can offset part of any price gain.

The trading setup is defined. Short positions below $3.00 with a stop above $3.10 target $2.75 to $2.80. Long positions are best timed for a weather shift, with entries near $2.80 and a stop below $2.65, targeting $3.20 to $3.30 on the first cold forecast.

Catalysts: Weekly Storage, Weather Models, Winter Outlook

The calendar for natural gas over the next several weeks is driven by a few recurring data points.

The weekly EIA storage report every Thursday at 10:30 a.m. ET is the primary data release. This week's report covering the week ended Sept. 25 carries a 63 Bcf consensus. Next week's report will cover the week ended Oct. 2. Injections below the five-year average would support prices modestly. Injections above the five-year average would add pressure. The surplus to the five-year average, at 95 Bcf as of Sept. 18, is the number to watch.

Weather models are the most important driver. The six- to 10-day and eight- to 14-day outlooks from U.S. forecasters update daily. A shift toward colder conditions in the Midwest and East would trigger a rally. Continued mild forecasts would keep prices under pressure. The market will react quickly to any sign of early-season cold.

The EIA's next Short-Term Energy Outlook, due Oct. 6, will update the agency's price and storage forecasts. A downward revision to the 2026 Henry Hub price forecast from $3.43 would confirm the bearish near-term view. An upward revision to winter demand forecasts would support prices.

LNG developments matter as well. Terminal maintenance schedules, new capacity startups and feedgas volumes affect U.S. demand week to week. Hurricane season, which runs through November, poses a risk to Gulf Coast LNG terminals. A storm forcing terminal shutdowns would reduce demand and add to storage, which is bearish for Henry Hub.

Middle East developments are an indirect catalyst. Iran said it received a U.S. response to its ceasefire proposal. A ceasefire that reopens the Strait of Hormuz would restore Qatari LNG exports, lowering global prices and narrowing the spread with Henry Hub. That would have little direct effect on Henry Hub, since U.S. exports are capacity-constrained, but it would reduce the long-term pull from global markets.

Macro factors play a minor role. The 10-year Treasury yield at 5.34% and the dollar near 102 affect commodity markets broadly, but natural gas is driven far more by weather and storage than by financial conditions.

Scenarios and Targets: $2.75 Base Case, $3.30 Upside

The base case, with a 50% probability, is a decline to $2.75 by mid-October. In this scenario, weather stays mild through the first half of October. Weekly storage injections run near or above the five-year average as cooling demand fades and heating demand hasn't started. Production stays near 115 Bcf per day. The surplus to the five-year average stabilizes or widens. November natural gas breaks $2.90 and drifts to $2.75, a 6.9% decline from $2.953.

The bull case, with a 25% probability, requires an early cold shift. Weather models turn colder for the second half of October in the Midwest and East. Storage injections slow sharply. LNG feedgas holds near capacity. November natural gas rallies through $3.05 and reaches $3.30, an 11.8% gain from $2.953. A severe early cold snap could push the contract toward $3.50.

The bear case, with a 25% probability, is a deeper slide. Mild weather persists into November. An LNG terminal outage or hurricane disruption reduces export demand. Production pushes above 116 Bcf per day. Storage heads toward 4,000 Bcf by the end of October. November natural gas breaks $2.75 and falls to $2.55 to $2.60, a decline of 12% to 14%.

The risk-reward favors a modest short bias in the near term. From $2.953, the base-case target of $2.75 offers 20 cents of downside. The bull case offers 35 cents of upside, but with a lower probability. The bear case offers another 35 to 40 cents of downside. Expected value is slightly negative for longs through mid-October.

The timing matters more than the direction. Natural gas is a seasonal market, and the bearish case is strongest in early October before heating demand starts. The bullish case strengthens as winter approaches. A sensible approach is to hold a short bias through mid-October and look for a long entry near $2.75 to $2.80 ahead of the first cold forecasts, targeting a winter rally toward the EIA's $3.43 annual average.

Position sizing should reflect gas futures volatility. Daily moves of 3% to 5% are common, and weather-driven rallies can exceed 10% in a few sessions. Stops should be wider than in most commodities, and leveraged ETFs should be used with caution given the contango drag.

Verdict: Bearish Through Mid-October, $2.75 Target

U.S. natural gas enters October as a domestic market isolated from a global crisis. Europe's TTF is at €74.06, up 135% from a year ago, and Asian LNG reached a four-year high of $29.56 per MMBtu in September. The Strait of Hormuz, carrying 19% of global LNG, has been closed for seven months. European storage is just 71% full heading into winter. Global gas markets are tight and expensive.

None of that is reaching Henry Hub. U.S. LNG terminals are running at capacity, so the U.S. can't export more gas regardless of overseas prices. Lower 48 production is near a record 115.0 Bcf per day, boosted by Permian associated gas flowing with oil drilling as Brent tops $100. Storage stood at 3,351 Bcf as of Sept. 18, 95 Bcf above the five-year average, and the EIA expects it to reach 3,969 Bcf by Oct. 31, the highest end-of-October level in a decade. The weather outlook through mid-October shows no meaningful cold.

The near-term price reflects that oversupply. November natural gas futures are at $2.953, down 2.4% and back below $3.00 after Wednesday's bounce failed. A light storage estimate wasn't enough to hold buyers, and with no cold in the forecast, sellers remain in control. The higher lows since April keep the broader trend intact, but that pattern is under pressure.

The verdict is bearish through mid-October. The base-case target is $2.75, a 6.9% decline from $2.953, with a 50% probability. The bull case of $3.30 requires an early shift to cold weather. The bear case of $2.55 to $2.60 requires persistent mild weather and an LNG disruption. Shorts below $3.00 with a stop above $3.10 target $2.75, and a long entry near $2.75 to $2.80 positions for the seasonal winter rally toward the EIA's $3.43 forecast. Weather models are the single most important variable, and the first cold forecast of the season will be the signal that the bearish phase is ending.

That's TradingNEWS