November NG Targets $3.35 as Storage Surplus Shrinks From 148 Bcf to 118 Bcf

Natural gas futures have broken a two-month ceiling. At 10:25 GMT on Wednesday, the October NYMEX contract traded at $3.018 per MMBtu, up $0.053 or 1.79%, after touching a session high of $3.052. The contract pushed through the $3.026 swing top on Tuesday, and the $3.00 handle now marks the highest level since July 8. The November contract, which takes over as front month after the October expiry on September 28, rose 2.25% to $3.187.

The trigger is weather. Forecasts call for above-average temperatures across the South-Central U.S. through October 6, extending air-conditioning demand and lifting gas burn for power well past the normal end of cooling season. Late-season heat in Texas and the Gulf Coast hits the region with the largest gas-fired generation fleet, which makes each degree of warmth worth more gas demand than the same heat elsewhere.

The storage surplus is eroding fast. Inventories were estimated 3% above the five-year average for the week ended September 18, down from 3.7% a week earlier. One week before that, the surplus measured 148 Bcf, and it narrowed to 118 Bcf after a below-average build. Last week's EIA report showed a 44 Bcf injection, below the 48 Bcf estimate and far below the five-year average build of 74 Bcf.

Supply is softening at the same time. Daily output was expected to fall to an 11-week low of 109.8 Bcf/d on Tuesday. Exports are pulling harder. Average gas flows to the nine major U.S. LNG export plants rose to 18 Bcf/d so far in September from 17.2 Bcf/d in August, even with the 0.8 Bcf/d Cove Point terminal down for maintenance. Buyers in Europe and Asia are bidding for U.S. cargoes to refill storage before winter, with LNG flows from the Persian Gulf disrupted by the Middle East war.

The structural picture still leans bearish on a longer view. The EIA forecasts U.S. working gas inventories at 3,969 Bcf on October 31, 5% above the five-year average and 1% above October 2025. The deferred part of the curve reflects that: March futures at $2.863 remain below their 50-day moving average.

The thesis for this forecast is direct. The front of the curve is trading late-season heat and export pull, and it has the momentum to push the November contract toward $3.25 to $3.35 if Thursday's storage print comes in lean again. The back of the curve is trading a well-supplied winter. That split caps the rally: unless heating-season forecasts turn cold, November runs into selling above $3.35, and a mild October would drag the front back toward $2.85.

Session Tape: $2.999 Low, $3.052 High and a Curve That Splits

Wednesday's session extended Tuesday's breakout. On Tuesday, prices rose to $2.92 per MMBtu, the highest in more than two weeks, on the expected drop in production. The October contract then pushed through the $3.026 swing top, and the November contract followed with a stronger move on Wednesday.

The European morning printed the key levels. By 10:25 GMT, October traded at $3.018, with a session high of $3.052 and a low of $2.999. That puts Tuesday's settlement near $2.965. The session low held just under $3.00, which means buyers defended the breakout level on the first pullback. A $0.053 range between low and high is modest for natural gas, signalling controlled buying rather than a panic squeeze.

The curve structure is the most important signal of the day. November rose 2.25% to $3.187, outperforming October's 1.79% gain. March rose 1.63% to $2.863, lagging both. The front months are trading the hotter forecast through October 6, while March is still asking whether any of that matters once heating season begins. When the prompt contracts rally harder than winter contracts, the market is pricing near-term tightness, not a structural winter shortage.

The spread math makes the point. November at $3.187 sits $0.169 above October at $3.018. March at $2.863 sits $0.324 below November. A normal curve heading into winter shows January and February at a premium to November because of peak heating demand. A March contract trading well below November signals a market that expects storage to remain comfortable through the heating season.

The broader tape was supportive for energy. Energy ranked among the few sectors higher on a day the S&P 500 fell 0.54% and the Nasdaq Composite dropped 1.06% on a 10-year Treasury yield at 5.058%. WTI crude rose 1.55% to $91.92 after a Libya pipeline shutdown, and Brent climbed back above $101.

Gas equities led the energy complex. Venture Global, the LNG exporter, jumped $0.74, or 5.73%, to $13.65, and Antero Resources gained $1.32, or 3.83%, to $35.74. The equity market is betting on sustained export demand and higher realized prices for Appalachian producers.

For the rest of the session, $3.00 is the pivot. A settlement above $3.026 would confirm the breakout and set up a test of $3.052 and higher. A settlement below $2.999 would suggest the move is stalling ahead of Thursday's storage data.

Weather: South-Central Heat Through October 6

Weather is the single biggest driver of Wednesday's move. Above-average temperatures are forecast across the South-Central U.S. through October 6, potentially extending air-conditioning use and lifting gas consumption. The hotter outlook through October 6 is what the front months are trading.

The geography matters. The South-Central region, anchored by Texas, Louisiana and Oklahoma, burns more gas for power generation than any other U.S. region. Late-September heat there adds power burn at a time when utilities normally shift toward lower gas demand. It also coincides with fall maintenance at nuclear and coal plants, which increases reliance on gas-fired generation.

The weather shift was sudden. The forecast change altered near-term supply-demand expectations, counteracting normal seasonal assumptions of lower power burn and prompting rapid repricing across prompt-month futures. A two-week window of above-normal heat in late September can add several Bcf a day of demand relative to normal, shaving tens of Bcf off cumulative storage builds.

Earlier outlooks were milder. Before the latest update, forecasts pointed to mostly normal conditions through October 7. The move from normal to above-normal in the South-Central region is the incremental bullish change that pushed October through $3.00.

Summer heat already shaped the storage path. Strong output and mild spring weather kept inventories above the five-year average, but higher summer temperatures raised gas demand for power generation and reduced the surplus. The late-September heat extends that pattern into the shoulder season, when inventories normally build quickly.

Electricity demand is structurally rising. The EIA expects U.S. electricity sales to total a record 4,135 billion kilowatt-hours in 2026 and 4,211 billion kilowatt-hours in 2027, driven by data center development and increased manufacturing activity. Data centers run around the clock, which adds baseload gas demand that does not fade with the weather. The West South Central region, which includes Texas, accounts for the largest share of that growth, even with a pause in connecting new data centers in Texas to the grid.

The weather risk cuts both ways. If the heat breaks earlier than forecast, or if early October turns mild, the front of the curve loses its main support. Weather forecasts beyond 10 days carry wide uncertainty. For the forecast, the October 6 horizon is the key window: a hot finish supports $3.00-plus, while a cool turn sends the November contract back toward $2.90.

Storage: A 44 Bcf Build, a 118 Bcf Surplus and Thursday's 50 Bcf Estimate

Storage data has turned supportive after months of surplus. Last week's EIA report showed a 44 Bcf injection for the week ended September 11, below the 48 Bcf estimate and well below the five-year average build of 74 Bcf. That 30 Bcf shortfall against the five-year average is a significant bullish signal for the shoulder season.

The surplus is narrowing. The below-average build cut the inventory surplus over the five-year average to 118 Bcf from 148 Bcf a week earlier. When that report landed two weeks ago, futures surged 4.1% from a prior close of $2.836 to a session high of $2.959. Market estimates put inventories 3% above the five-year average for the week ended September 18, down from 3.7%.

Thursday's report is the next catalyst. The EIA storage estimate for Thursday calls for a 50 Bcf build. The five-year average build for late September typically runs in the 70s to 80s Bcf. A print near 50 Bcf would cut the surplus by another 20 to 30 Bcf. A print below 45 Bcf would be a bullish surprise that could push November through $3.25. A print above 60 Bcf would be a bearish miss that could drag October back below $2.95.

The end-of-season target frames the bigger picture. The EIA forecasts working inventories at 3,969 Bcf on October 31, 5% above the 2021-2025 average and 1% above October 2025. Relatively high inventories partly reflect strong production growth in the Permian and Haynesville. Even with the recent lean builds, the U.S. is on track to enter winter with more gas than normal.

Regional balances vary. Mountain region inventories are expected at 21% above the five-year average entering the withdrawal season, the Pacific at 10%, the Midwest at 6% and South Central at 4%. The East is expected to enter winter about equal to the five-year average, after starting the injection season 11% below it, with more limited regional production growth.

The East is the swing region for winter pricing. With the East at only the five-year average, a cold early winter in the Northeast would pull inventories below normal quickly and lift regional and Henry Hub prices. The comfortable surplus in the Mountain and Pacific regions cannot easily move east because of pipeline constraints.

For the forecast, storage supports the front of the curve for now. Two more lean builds in a row would push the surplus below 2%, a level that historically supports prices above $3.00 heading into winter.

Production: An 11-Week Low at 109.8 Bcf/d

The supply side is contributing to the rally. Daily output was expected to fall to an 11-week low of 109.8 Bcf/d on Tuesday, and lower production drove prices to their highest in more than two weeks. A dip in output during a period of rising demand tightens the daily balance and reduces storage injections.

Production dips in late September are often maintenance-driven. Pipeline maintenance, processing plant turnarounds and weather-related disruptions in the Gulf of Mexico can temporarily reduce reported output. Some of the decline may reverse as maintenance ends. The market treats the 11-week low as a short-term tightening signal rather than a structural decline.

The structural trend remains higher. The EIA attributes the relatively high inventory outlook to strong production growth in recent months, particularly in the Permian and Haynesville regions. Permian output is largely associated gas, produced as a by-product of oil drilling. With WTI near $92 and Brent above $101, oil producers have strong incentives to keep drilling, which keeps associated gas flowing regardless of gas prices.

That creates a floor on supply. Associated gas from the Permian does not respond to Henry Hub prices, because the drilling decision is driven by crude economics. As long as oil stays above $90, Permian gas output keeps growing, and that growth keeps a lid on sustained gas rallies. The Haynesville, by contrast, is a dry-gas basin that responds directly to Henry Hub prices. At $3.00, Haynesville producers have an incentive to add activity.

The oil-gas link is a critical feature of this market. The Middle East war has lifted oil prices, which has increased associated gas supply, which has kept U.S. gas prices lower than they would otherwise be. At the same time, the war has disrupted LNG flows from the Persian Gulf, which has increased demand for U.S. LNG exports. U.S. gas sits between those two forces.

Appalachian producers benefit most from the current setup. Companies like Antero Resources, EQT and Coterra sell into both domestic markets and LNG export channels. Antero's 3.83% gain on Wednesday reflects the market's view that higher Henry Hub prices and strong export demand lift realized prices for Appalachian gas.

For the forecast, production is a near-term support and a medium-term cap. A return to the 111 to 112 Bcf/d range after maintenance would add back 1 to 2 Bcf/d of supply and slow the rally. Continued output near 110 Bcf/d, alongside lean storage builds, would support a push toward $3.25.

LNG Exports: 18 Bcf/d and the Persian Gulf Disruption

Export demand is the strongest structural driver in the U.S. gas market. Average gas flows to the nine major U.S. LNG export plants rose to 18 Bcf/d so far in September from 17.2 Bcf/d in August, despite the temporary shutdown of the 0.8 Bcf/d Cove Point facility for planned maintenance. Without the Cove Point outage, feedgas would likely be near 18.8 Bcf/d.

Global demand is the reason. Stronger overseas demand is supporting exports, with buyers in Europe and Asia working to replenish inventories ahead of winter amid disruptions to LNG flows from the Persian Gulf. Qatar is one of the world's largest LNG exporters, and its shipments pass through the Strait of Hormuz. War-related disruption to Hormuz traffic has pulled cargoes off the global market and pushed buyers toward U.S. supply.

The Hormuz situation is shifting. Oil and LNG shipments through the Strait of Hormuz over the past two weeks reached their highest level in six months, according to U.S. Central Command. U.S. and Iranian officials held three hours of talks at the United Nations on Tuesday, and President Trump described them as very productive. Iran, however, denied it had dropped its preconditions for reopening the strait fully.

That creates a two-sided risk for U.S. gas. If Hormuz flows keep recovering and an Iran deal restores Qatari LNG exports fully, global LNG prices would fall and the premium pulling U.S. cargoes to Europe and Asia would narrow. U.S. feedgas demand would likely stay high because export contracts are long-term, but spot cargo demand would soften. If talks collapse and Hormuz tightens again, global LNG prices would spike and U.S. export demand would stay at maximum capacity.

Export capacity is the binding constraint. U.S. LNG terminals run near their limits, so feedgas cannot rise much beyond current levels until new capacity comes online. At 18 Bcf/d, U.S. LNG exports absorb roughly 16% of domestic production. The return of Cove Point from maintenance would add 0.8 Bcf/d of demand, a meaningful bullish factor for late September and October.

The equity market reflects the export story. Venture Global's 5.73% gain to $13.65 on Wednesday, with a market value of $34.1 billion, shows investors pricing strong export economics. The stock has a 52-week range of $5.72 to $17.62, and at $13.65 it sits 22.5% below its high.

For the forecast, LNG demand sets a firm floor under U.S. gas. With 18 Bcf/d of feedgas and Cove Point returning, export demand will keep pulling on domestic supply through the winter. The risk is a global LNG price collapse on an Iran deal, which would narrow the spread that makes U.S. exports profitable.

The Curve Split: Front Months Rally, March Lags

The shape of the futures curve tells the most important story in the market. On Wednesday, October rose 1.79% to $3.018, November climbed 2.25% to $3.187, and March gained 1.63% to $2.863. March remains below its 50-day moving average. The front-end rally and the deferred-curve weakness are two distinct trades running at the same time.

The front months are trading weather and exports. Heat through October 6, lean storage builds and 18 Bcf/d of LNG feedgas all affect the next four to six weeks of supply and demand. Those factors lift October and November directly.

March is trading winter supply. The March contract prices gas delivered at the end of heating season, when storage is at its seasonal low. With the EIA forecasting end-October inventories 5% above the five-year average, the market expects enough gas to get through winter without a shortage. That is why March lags.

The November-March spread is unusual. November at $3.187 sits $0.324 above March at $2.863. In a tight winter market, the curve typically rises from November into January and then falls toward March. A March contract well below November signals that the market sees late-winter supply as comfortable, even if early-season demand is strong.

The spread creates a trading opportunity and a warning. For traders, a November-March spread of $0.324 is wide and can compress if early winter weather turns mild. For producers, the current curve offers attractive hedging prices for November and December deliveries relative to the rest of the winter.

The contract roll matters this week. The October contract expires on September 28, and November becomes the front month. November's $3.187 price will then be the headline Henry Hub futures price, which means the front-month quote will jump even if the market does not move. Traders comparing prices across the roll should account for that shift.

The history of the recent low frames the move. Prices were near multi-month lows at $2.836 before the storage-driven rally two weeks ago. From $2.836 to $3.052, October has gained 7.6%. Natural gas has gained 5.66% over four weeks but is down 4.6% over twelve months. The rally is recovering lost ground rather than breaking into new territory.

For the forecast, the curve split limits the upside. The front can rally on weather, but without a colder winter outlook, the March contract will anchor the curve and cap how far November can run above $3.25.

Positioning: Shorts Covering Into a Technical Breakout

Positioning amplified Wednesday's move. Systematic funds and speculative traders held sizable short positions heading into late September, leaving the market vulnerable to upside squeezes. As prices broke through key technical resistance, automated buy-stops and aggressive short covering triggered rapid inflows.

The squeeze mechanics are familiar in natural gas. When a large short position meets a bullish catalyst, such as a hotter weather forecast or a lean storage print, shorts rush to buy back contracts to limit losses. Their buying pushes prices through technical levels, which triggers stop-loss orders from other shorts, which drives prices higher still. The October break of the $3.026 swing top on Tuesday was the kind of technical level that triggers that chain.

The breakout had fundamental support. The technical move was reinforced by expectations of another lean weekly injection, with late-summer heat and steady LNG feedgas limiting storage accumulation relative to five-year norms. Short covering accelerated a move that fundamentals had already started.

Squeezes have a limited shelf life. Once shorts cover, the buying that drove the move disappears. The price then needs fresh fundamental buyers to hold the gains. If Thursday's storage report comes in near or above the 50 Bcf estimate, the fundamental case for further gains weakens, and the post-squeeze pullback could be sharp.

The volatility profile of natural gas matters for positioning. Gas routinely moves 3% to 5% in a single session on storage and weather news. Two weeks ago, a lean storage print produced a 4.1% rally. Traders should expect similar swings around Thursday's report and the October 28 contract expiry.

The ETF complex reflects the leverage. The United States Natural Gas Fund (UNG) tracks front-month futures, while leveraged products like BOIL (2x long) and KOLD (2x short) amplify daily moves. Heavy flows into those products around catalysts can add short-term volatility to the underlying futures, especially near the roll.

For the forecast, positioning argues for caution chasing the breakout. The short-covering phase is likely well advanced after a 7.6% move from $2.836. A pullback to $2.95 to $3.00 after Thursday's report would reset positioning and give fundamental buyers a better entry.

Macro and Cross-Commodity: Oil at $92, a 5% Ten-Year and the Dollar

The macro backdrop affects gas differently from other commodities. The U.S. composite PMI jumped to 58.4 in September, with input costs rising at the fastest pace since October 2022, driven by fuel and transport costs. The 10-year Treasury yield hit 5.058%, its highest since July 2007. The Fed raised rates to a 3.75% to 4.00% range on September 16, and October hike odds climbed above 53%.

Strong growth supports gas demand. A U.S. economy running at a 4% to 5% annualized pace, with record electricity demand from data centers and manufacturing, burns more gas for power and industry. The PMI's report of the strongest factory hiring since February 2021 points to rising industrial gas consumption.

Oil is the key cross-commodity link. WTI rose 1.55% to $91.92 and Brent climbed above $101 after an armed group shut the pipeline from Libya's El Sharara field. Higher oil supports Permian drilling, which adds associated gas supply and caps U.S. gas prices. It also lifts global LNG prices, because many long-term LNG contracts are indexed to oil. Higher LNG prices increase the incentive to export U.S. gas.

The dollar is a mild headwind. The dollar index hit a seven-week high near 100.86 before rising further after the PMI. A strong dollar makes U.S. LNG more expensive for foreign buyers at the margin, but with global supply tight because of Persian Gulf disruptions, buyers are paying up regardless.

The Iran track affects gas through LNG. An Iran deal that fully reopens Hormuz would restore Qatari LNG flows, lowering global LNG prices and narrowing the export arbitrage for U.S. cargoes. That would be a moderate bearish factor for Henry Hub. A breakdown in talks would tighten global LNG further and support U.S. export demand.

The diesel and energy-policy backdrop adds noise. The administration is examining a diesel export ban to address record diesel prices. Energy policy that tightens refined product markets does not directly affect gas, but it signals a government willing to intervene in energy exports, which adds uncertainty for LNG exporters over the long term.

For the forecast, macro conditions are mildly supportive of gas demand. Strong growth, record electricity use and tight global LNG markets outweigh the rate and dollar headwinds. The biggest macro risk for U.S. gas is a sharp drop in oil and LNG prices on an Iran deal.

Gas Equities and ETFs: Venture Global, Antero and the Leveraged Complex

Gas-linked equities are outperforming a weak stock market. Venture Global jumped 5.73% to $13.65 and Antero Resources rose 3.83% to $35.74 on Wednesday, while the S&P 500 fell 0.54%. Energy was among the few sectors in positive territory.

Venture Global is the purest LNG play. The company's $34.1 billion market value reflects its position as a major U.S. LNG exporter. Its 52-week decline of 11.15% shows the stock has lagged despite strong export volumes, partly because investors worry about the long-term LNG price outlook once Middle East supply recovers. Wednesday's move reflects the market re-pricing near-term export profitability as global buyers compete for U.S. cargoes.

Antero is the Appalachian producer play. At $35.74, with a market value of $10.99 billion and a trailing P/E of 9.73, Antero trades at a moderate valuation relative to its exposure to higher gas prices. The stock's 52-week range of $29.10 to $45.75 leaves it 21.9% below its high. Appalachian producers benefit from both rising Henry Hub prices and strong demand from LNG export terminals along the Gulf Coast.

Other producers trade in the same direction. EQT, the largest U.S. gas producer, and Coterra Energy, with its mix of Permian and Marcellus gas, carry similar exposure. Cheniere Energy, the largest U.S. LNG exporter, benefits from strong global demand but is less sensitive to Henry Hub prices because its contracts pass through gas costs.

The ETF complex offers direct exposure. The United States Natural Gas Fund (UNG) tracks front-month futures and will roll from October to November ahead of the September 28 expiry. With November trading $0.169 above October, the roll will cost UNG holders some return as the fund sells cheaper October contracts and buys more expensive November ones. That roll cost, known as contango drag, is a structural headwind for UNG in an upward-sloping front curve.

Leveraged ETFs amplify moves. BOIL, the 2x long natural gas ETF, and KOLD, the 2x short, magnify daily futures moves. In a volatile market with 3% to 5% daily swings, leveraged products can suffer significant decay over time even if the underlying price ends flat. They are trading tools, not long-term holdings.

For the forecast, gas equities offer a way to express a view on export demand without taking on futures roll costs. Producers with low costs and export exposure benefit most if Henry Hub holds above $3.00 into winter. LNG exporters benefit if global LNG prices stay elevated on Middle East disruption.

Technical Map: $3.00 Pivot, $3.052 High and the November Roll

The chart has turned bullish for the front months. October broke through the $3.026 swing top on Tuesday and reached $3.052 on Wednesday. The move above $3.00 marks the highest level since July 8. A move through a two-month high, on rising volume, confirms a trend change for the prompt contract.

Resistance for October sits at $3.052, Wednesday's session high. A settlement above that level would open the path toward $3.10 and $3.15. With the contract expiring on September 28, October has only three more sessions of trading. The more important chart after Monday is November.

For November, the key levels are clear. November traded at $3.187 on Wednesday. Resistance sits at $3.25, then $3.35. A move above $3.35 would require a colder heating-season outlook, not just late-September heat. Support for November sits at $3.10, then $3.00.

Support for October is well defined. The first line is $2.999, Wednesday's session low. Below that, $2.965, Tuesday's settlement, then $2.92, Tuesday's intraday level. A break below $2.92 would erase the breakout. The deeper support sits at $2.836, the pre-rally close from two weeks ago.

The 50-day moving average is a key test for the back of the curve. March at $2.863 remains below its 50-day moving average, a sign that the winter contract has not confirmed the front-month breakout. If March moves above its 50-day average, it would signal that the market is starting to price a tighter winter, which would support a larger rally across the curve.

The momentum profile is strong but extended. From $2.836 to $3.052, October has gained 7.6% in two weeks. Natural gas rallies of that size often retrace 38% to 50% before continuing. A 38.2% retracement of that move lands near $2.97; a 50% retracement lands near $2.94. Both sit within the $2.92 to $3.00 support zone.

The trading range for October into expiry runs from $2.92 to $3.10. For November after the roll, the range runs from $3.00 to $3.35. Thursday's storage report is the catalyst that decides which end of those ranges is tested first.

Natural Gas Futures Price Forecast: $3.25 to $3.35 November Target, $2.92 Support, Verdict

The forecast breaks into three scenarios, each keyed to Thursday's storage data, weather through October 6 and LNG export demand.

The bull case targets $3.35 for November, 5.1% above its current $3.187, with $3.50 as an extension. It requires Thursday's storage report to show an injection below 45 Bcf, cutting the surplus toward 2%, heat to persist through October 6, Cove Point to return from maintenance and lift LNG feedgas toward 18.8 Bcf/d, and production to stay near its 11-week low of 109.8 Bcf/d. A colder shift in early-winter forecasts would add a structural bid. This path carries a 30% probability.

The base case is consolidation for November between $3.00 and $3.25 through mid-October. Thursday's injection lands near the 50 Bcf estimate, heat fades on schedule after October 6, production recovers toward 111 Bcf/d and LNG demand stays firm near 18 Bcf/d. The front of the curve holds above $3.00 as storage enters winter close to the EIA's 3,969 Bcf target. This path carries a 45% probability.

The bear case targets $2.90 for November, 9% below the current level, with October retesting $2.836. It requires a storage injection above 60 Bcf, an early break in the heat, a rebound in production above 111 Bcf/d and an Iran deal that restores Qatari LNG exports and lowers global LNG prices. The March contract's position below its 50-day average signals the market is already partly positioned for this outcome. This path carries a 25% probability.

Levels to trade for October into expiry: resistance at $3.026, $3.052 and $3.10. Support at $2.999, $2.965, $2.92 and $2.836. For November after the roll: resistance at $3.25, $3.35 and $3.50. Support at $3.10, $3.00 and $2.90.

The verdict on natural gas for September 23 is bullish for the front months and neutral for winter. October futures broke above $3.00 for the first time since July 8, reaching $3.052, and November rose 2.25% to $3.187 on heat across the South-Central U.S. through October 6. The storage surplus has narrowed from 148 Bcf to 118 Bcf and from 3.7% to 3% above the five-year average after a 44 Bcf build that missed the 74 Bcf average by 30 Bcf. Production fell to an 11-week low of 109.8 Bcf/d while LNG feedgas rose to 18 Bcf/d on European and Asian demand amid Persian Gulf disruptions. Against that, the EIA projects end-October storage 5% above normal and March futures at $2.863 remain below their 50-day average. Buy dips toward $3.00 in November ahead of Thursday's report, target $3.25 to $3.35, and take profits into strength above $3.35 unless heating-season forecasts turn colder.

That's TradingNEWS