Henry Hub ($3.11) Pulls Back From 13-Week High as 112.8 Bcf/d Output Meets Record LNG Pull — $3.10 Pivot Guards the Path to $3.529

Natural gas futures opened the final week of September with a bearish gap. Henry Hub prices trade at $3.11 per million British thermal units, down 2.65% from $3.20, after slipping toward $3.100 in early trading. The 55-period moving average now sits overhead as resistance. The decline extends Friday's profit-taking, when prices fell as much as 5% to $3.1321 before settling near $3.15.

Monday carries an extra layer of volatility. The October Nymex contract expires today, and trading is rolling into November, which becomes the prompt month. October open interest fell sharply ahead of expiration last week, and November open interest also declined. Contract rollover days tend to produce erratic price action as traders close or roll positions, and today's gap lower reflects that churn along with a shift in the fundamental picture.

The backdrop explains the reversal. On Thursday, natural gas surged to a 13-week high, its highest level since July 8, on the biggest single-day gain since January. The trigger was a force majeure declaration on TC Energy's Columbia Gas Transmission pipeline in Appalachia after an unexpected mechanical issue, combined with a bullish storage report and falling production. The November contract ripped 5.80% in one session, running through $3.216, $3.264, $3.291 and $3.350 before topping at $3.377. Much of that move came from short covering ahead of October's expiration.

Over the weekend, the supports behind that rally faded. The major pipeline outage was resolved. Traders are also weighing storm fallout from a developing nor'easter and evolving demand as the country moves out of cooling season.

The bigger picture shows a market that has recovered but not broken out. Natural gas has risen 6.01% over the past month but trades 4.76% below its level a year ago. In August, Henry Hub spot prices averaged $2.76, ranging between $2.64 and $2.94.

The thesis for this forecast: US natural gas is caught between a domestic market with ample supply and a global market in crisis. Storage sits 95 Bcf above its five-year average and production averaged a near-record 112.8 Bcf/d in September, which caps prices at home. But LNG feedgas hit 17.8 Bcf/d this month as the Hormuz closure keeps Qatari supply offline and European gas trades above $24 per MMBtu. The domestic surplus is shrinking every week. The key level is $3.10: holding it keeps Thursday's breakout alive; losing it returns prices to the $2.976 floor of the new range.

Thursday's Squeeze: A 5.80% Session to $3.377 on Pipeline Force Majeure

To understand Monday's gap lower, start with Thursday's surge. November natural gas futures rallied 5.80% in a single session on September 24, their biggest gain since January, to a high of $3.377. Three catalysts converged on the same day.

The first was supply disruption. TC Energy's Columbia Gas Transmission pipeline in Appalachia declared force majeure after an unexpected mechanical issue in West Virginia. Columbia is one of the key systems moving gas out of the Marcellus and Utica shale basins, the largest gas-producing region in the country. A force majeure on a major Appalachian pipeline strands production and tightens supply to downstream markets.

The second was falling production. US Lower 48 output was on track to fall to an 11-week low of 108.4 Bcf/d on Thursday, mainly due to declines in Louisiana and West Virginia. An early print the next day showed 109.1 Bcf/d, after a revision to 109.8 Bcf/d, with an operational alert on the Braxton gathering system limiting Northeast volumes by 0.6 Bcf/d. Non-Permian Texas and Permian volumes also ran lower.

The third was storage. The EIA reported a 53 Bcf injection for the week ending September 18, within the 51 to 54 Bcf consensus range but well below the 77 Bcf build a year earlier and the five-year average of 76 Bcf. The smaller build narrowed the storage surplus over the five-year average to 95 Bcf from 118 Bcf.

Short covering amplified the move. Once November cleared $3.150, shorts started buying back positions, and the market ran through successive resistance levels in one session. Prices rose while open interest fell, the signature of short covering rather than fresh buying. The covering turned a modestly bullish storage report into a 5.80% rally.

The October contract rallied too. It closed at $3.02 on September 23, up six cents from the prior session, and traded at $3.13 on the morning of the storage report. October averaged $2.99 during that week, up from $2.90 the week before.

The squeeze defined a new trading range for November: $2.976 to $3.377. The retracement zone of that range sits between $3.177 and $3.129. Monday's price at $3.11 has already broken below that zone, which means Thursday's surge is starting to look more like a squeeze than the start of a new uptrend.

The question for the week is whether new buyers replace the shorts who covered. If they do, prices can hold above $3.10 and retest $3.377. If they do not, the market fades back toward the bottom of the range.

EIA Storage: 3,351 Bcf and a Surplus That Shrank From 118 to 95 Bcf

Storage data defines the domestic balance, and the trend over September has been bullish even as absolute levels remain comfortable. The EIA reported that working gas in storage reached 3,351 Bcf as of September 18, after a net injection of 53 Bcf. That left stocks 146 Bcf, or 4.2%, below the level a year earlier and 95 Bcf, or 2.9%, above the five-year average of 3,256 Bcf. Inventories sit within the five-year historical range.

The surplus is shrinking steadily. One week earlier, storage stood 3.7% above the five-year average. At the end of August, the surplus was 5.2%. Each week in September has brought an injection smaller than the seasonal norm, eroding the cushion.

The weekly pattern shows the tightening. The week ending September 4 brought a 40 Bcf injection, above expectations of 31 Bcf but below the five-year average of 52 Bcf and the 69 Bcf build a year earlier. The week ending September 11 added 44 Bcf, slightly below the 49 Bcf expected and far below the five-year average of 74 Bcf and the 87 Bcf build a year earlier. The week ending September 18 added 53 Bcf, against a five-year average of 76 Bcf. Across three weeks, injections totaled 137 Bcf against a five-year average of 202 Bcf, a shortfall of 65 Bcf.

The regional picture shows where the tightness sits. The East held 815 Bcf after a 20 Bcf build, 5.2% above its five-year average. The Midwest held 959 Bcf after a 25 Bcf build, 3.5% above average. The South Central region, which includes the Gulf Coast storage that feeds LNG export terminals, held 1,041 Bcf after just a 2 Bcf injection, leaving it 12.4% below last year and 1.7% below its five-year average.

The salt caverns flash a warning. Salt storage facilities, which can inject and withdraw quickly, held 217 Bcf after a 5 Bcf withdrawal during the injection season. That leaves salt storage 27.2% below last year and 12.5% below its five-year average. Salt caverns sit near the Gulf Coast LNG terminals, and their depletion shows LNG demand is pulling gas out of the South Central region faster than it can be replaced.

The end-of-season outlook remains comfortable. The EIA's September Short-Term Energy Outlook projects inventories will reach 3,969 Bcf on October 31, 5% above the five-year average and 1% above October 2025 levels. Hitting that target from 3,351 Bcf requires 618 Bcf of injections over six weeks, an average of 103 Bcf per week. Recent weekly builds of 40 to 53 Bcf run far below that pace.

The next storage report arrives Thursday, October 1.

Production Near Record: 112.8 Bcf/d in September, With Daily Output Slipping

Supply is the dominant bearish force in the US gas market. September production averaged a near-record 112.8 Bcf/d. On a single day earlier this summer, Lower 48 dry gas production rose to a near-record 115.0 Bcf/d. The United States is producing more natural gas than at almost any point in its history, and that output keeps a lid on domestic prices.

Growth continues into next year. The EIA forecasts US marketed natural gas production will increase by 4.5 Bcf/d in 2026 and 4.6 Bcf/d in 2027. The Permian and Haynesville basins together account for more than 70% of that growth. Permian production alone is forecast to grow by 1.7 Bcf/d in 2026 and 2.2 Bcf/d in 2027.

The Permian's growth is tied to oil. Most Permian gas is associated gas, produced as a byproduct of oil drilling. With WTI crude at $96.33, up 4.24% on Monday, oil producers have every incentive to keep drilling, which means associated gas output keeps rising regardless of Henry Hub prices. The Permian gas-to-oil ratio averaged nearly 4,200 cubic feet per barrel in 2025, 15% higher than in 2021, as wells produce more gas relative to oil as they age.

Pipeline capacity is expanding to move that gas. WhiteWater and its partners sanctioned the 4.5 Bcf/d Solitude Pipeline System, and forward prices at the Waha hub for 2029 to 2032 posted their largest daily basis gain of the year as traders bet the Permian could end up with more takeaway capacity than supply. Boardwalk Pipelines completed federal permitting for its Kosciusko Junction Pipeline Project.

Daily output has softened in recent weeks. Production fell to an 11-week low of 108.4 Bcf/d on September 24, mainly due to declines in Louisiana and West Virginia. Louisiana is home to the Haynesville shale, and West Virginia sits in the Appalachian basin. The Braxton gathering system alert removed 0.6 Bcf/d of Northeast supply.

The gap between the monthly average and the daily dip matters. September's average of 112.8 Bcf/d includes stronger early-month output. The drop to 108.4 Bcf/d represents a decline of 4.4 Bcf/d from the average, a meaningful reduction that helped drive Thursday's rally. If the Columbia pipeline and Braxton issues are fully resolved, daily output should recover toward 112 Bcf/d, adding supply back into the market.

For the forecast, production is the ceiling on prices. As long as output holds near 112 Bcf/d, rallies above $3.40 will struggle. A sustained drop below 109 Bcf/d, from maintenance or pipeline constraints, would tighten the market enough to push prices toward the 200-day moving average at $3.529.

LNG Feedgas Hits 17.8 Bcf/d as Exporters Chase a Global Shortage

The strongest bullish force in the US gas market comes from overseas. Average gas flows to the nine major US LNG export plants reached 17.8 Bcf/d in September, up from 17.2 Bcf/d in August. That increase came despite the planned shutdown of Berkshire Hathaway Energy's 0.8 Bcf/d Cove Point facility for annual maintenance. Without Cove Point's outage, feedgas would sit near 18.6 Bcf/d.

LNG exports have grown rapidly. US LNG exports reached 15.1 Bcf/d in 2025, up 26% from 2024, the largest increase of any exporting country. The EIA estimated exports hit 17.9 Bcf/d in March 2026, the second-highest volume on record at the time. The agency forecasts exports of 17.4 Bcf/d for 2026 and 18.6 Bcf/d in 2027.

New capacity is coming online. Golden Pass, a joint venture between QatarEnergy and ExxonMobil, shipped its first LNG cargo from Texas in April 2026. The EIA expects 2.4 Bcf/d of DOE-authorized export capacity to come online between April and December 2026 from Golden Pass Trains 1 and 2 and Corpus Christi Stage 3 Trains 5 through 7. Golden Pass's ramp-up has faced challenges, with feedgas running at 0.31 to 0.33 Bcf/d in July, below the level needed to support a single train at full capacity.

The driver of the export surge is the price gap. The Hormuz disruption has widened the spread between US and international gas prices to extreme levels, encouraging US exporters to run at maximum capacity. Capacity, not demand, is the constraint on how much gas the US can ship.

LNG demand is concentrated on the Gulf Coast. Most US export terminals sit in Louisiana and Texas, which explains why South Central storage held just a 2 Bcf build last week while the East and Midwest injected 20 and 25 Bcf. Salt cavern storage near the Gulf, down 27.2% from last year, shows LNG pull is draining the region feeding the terminals.

The maintenance calendar matters for the forecast. When Cove Point returns from its annual shutdown, feedgas will rise by up to 0.8 Bcf/d. Combined with new Golden Pass and Corpus Christi trains ramping up, US LNG feedgas could push toward 19 Bcf/d this fall. Each additional Bcf/d of LNG demand removes 7 Bcf of gas from the domestic market every week.

For the forecast, LNG is the floor under prices. As long as global prices remain several times higher than Henry Hub, US exporters will run at full tilt, steadily draining the domestic storage surplus. That structural demand is why prices have held above $2.97 despite near-record production.

The Hormuz Shock: 20% of Global LNG Offline and Qatar at Half Capacity

The global gas market has been in crisis since February 28, 2026, when the Strait of Hormuz closed. Before the war, around one-fifth of global LNG trade transited the strait, largely from Qatar, the world's second-largest LNG exporter after the United States. Qatar exported 10.6 Bcf/d of LNG in 2025, and Asian buyers took more than 80% of those volumes.

The damage went beyond shipping. Iranian drone attacks on Qatar's Ras Laffan and Mesaieed facilities in early March prompted QatarEnergy to halt LNG production. QatarEnergy declared force majeure on March 4 on some long-term contracts. Days later, a more damaging missile strike hit the Ras Laffan industrial complex, the world's largest LNG export facility, causing significant damage.

Qatar's recovery has been slow and uneven. QatarEnergy has notified buyers of allocations around 50% of annual contracted quantities, broadly aligning with a 2026 Qatari export forecast of 38.7 million tonnes, roughly half of pre-conflict capacity. Those notifications carry transit-related caveats. The US-Iran memorandum of understanding signed on June 17, 2026, collapsed in July when Iran targeted commercial shipping in the strait, including drone attacks on vessels using the Omani corridor without Iran's approval.

Monday's news extends the disruption. The White House rejected Iran's proposal to reopen the Strait of Hormuz, which included conditions on frozen funds, oil sanctions and the US naval blockade. Iran said it will not soften its conditions. Mediator talks are expected to resume this week, but the rejection pushes any Qatari LNG recovery further out.

The impact on global prices has been severe. Asian spot LNG prices jumped to $22 per MMBtu in July. European TTF hit its highest close since January 2023. Asian buyers who lost Qatari volumes are competing on the spot market with European buyers trying to refill storage.

The competition keeps US exporters busy. Every cargo that Qatar cannot ship must be replaced from somewhere, and the United States is the largest source of flexible LNG supply. That global scramble explains why US feedgas keeps climbing even with domestic prices near $3.

For the forecast, Hormuz is the wildcard. A breakthrough in the mediator talks that reopens the strait would allow Qatari exports to recover gradually, easing global prices and eventually reducing the pull on US gas. But even a deal would not restore Ras Laffan's damaged capacity quickly. Continued stalemate keeps global LNG tight and US export demand at maximum through the winter.

Europe and the Spread: TTF at €73.36 and a Henry Hub Discount Above $21

The gap between US and international gas prices has reached extreme levels, and it defines the economics of the entire US export industry. European TTF gas trades at €73.36 per megawatt-hour, up 2.05% on Monday and 125.24% higher than a year ago. Converted at the current EUR/USD rate of 1.1377, that equals more than $24 per MMBtu. Against Henry Hub at $3.11, European gas costs nearly eight times as much.

The spread explains US export behavior. The difference between Henry Hub and European prices exceeds $21 per MMBtu. After liquefaction, shipping and regasification costs, which typically total a few dollars per MMBtu, US exporters earn enormous margins on every cargo sent to Europe. That margin ensures every available liquefaction train runs at full capacity.

UK gas shows the same tightness. UK wholesale gas trades at 183.04 pence per therm, 118.37% higher than a year ago, after falling 4.02% on Friday. The Bank of England cited UK wholesale gas prices at 207 pence per therm on September 14, up 78% since July, as a key driver of its inflation forecast.

Europe's storage position is weak. European natural gas storage inventories finished last winter at 28% full, well below the five-year average of 41%. That forced European buyers to compete aggressively for spot cargoes through the summer to refill storage before the coming winter. European inventories remain at a deficit to the five-year average heading into the heating season.

European and Asian buyers are in direct competition. Most market participants expect European nations to win the bidding war for expensive LNG cargoes, given their greater storage capacity and financial resources. Asian storage capacity is smaller, so JKM prices tend to move with weather-driven spot demand.

The inflation link matters for the broader market. Eurozone energy inflation jumped to 14.3% in August, pushing headline inflation to 3.3%. The European Central Bank hiked on September 10, and the Bank of England is moving toward a hike. High gas prices are feeding directly into central bank decisions on both sides of the Atlantic.

For US natural gas, the spread is a structural bid. As long as European and Asian prices remain several times higher than Henry Hub, US LNG exports will run at capacity, and domestic storage will continue to tighten relative to normal. The spread will not close until either Qatari supply returns or US export capacity expands enough to flood global markets.

Weather: Lingering South-Central Heat, a Nor'easter and Normal Conditions Through October 9

Weather drives short-term natural gas demand, and the outlook heading into October is mixed. Forecasts point to mostly normal conditions through October 9. That means neither strong heating demand nor strong cooling demand across the country, the typical profile of the fall shoulder season.

Heat lingers in the South. Above-normal temperatures persist across the South-Central United States into early October, keeping late-season power burn active. Air conditioning demand in Texas and the Gulf states continues to pull gas into power generation, which supports demand at a time when it would normally decline.

The East faces a different setup. A developing nor'easter is expected to bring cooler conditions to the Southeast and the East Coast. Cooler weather in October reduces air conditioning demand but is rarely cold enough to trigger significant heating demand. The net effect of cooler shoulder-season weather is usually bearish, as it reduces power burn without replacing it with heating load.

Regional divergence is driving cash market volatility. Cash prices for gas delivered over the weekend and Monday swung with the weather as a sharp regional divide in temperatures kept demand expectations in flux. A developing nor'easter and a major pipeline outage added uncertainty.

The weather setup is not clean enough to drive the market alone. The heat is not strong enough to sustain a rally, and the cooling is not cold enough to trigger heating demand. That leaves storage data and production as the dominant drivers in the near term.

The seasonal transition is coming. November marks the start of the withdrawal season, when heating demand pulls gas out of storage. The November contract, now the prompt month after October's expiry today, prices in that transition. Early cold snaps in the Midwest and Northeast in late October or early November would lift heating demand and support prices.

Winter outlook matters more than October weather. With storage projected at 3,969 Bcf at the end of October, 5% above average, a normal winter would leave the market well supplied. A cold winter combined with maximum LNG exports could drain inventories faster than expected. Regional balances vary: the Mountain region is projected at 21% above its five-year average entering winter, the Pacific at 10%, the Midwest at 6% and South Central at 4%, while the East is expected to enter the withdrawal season about equal to average.

For the forecast, weather is a secondary factor this week. Normal conditions through October 9 remove the weather premium that supported Thursday's rally.

The Oil Link: WTI at $96.33 Drives Associated Gas and Inflation

Crude oil affects natural gas through two channels, and Monday's 4.24% jump in WTI to $96.33 strengthens both. The White House rejection of Iran's Hormuz proposal sent Brent to $107.11.

The first channel is supply. Most Permian gas is associated gas, produced alongside oil. When oil prices are high, Permian producers drill more wells, and more wells mean more associated gas regardless of Henry Hub prices. WTI above $95 gives oil producers strong incentive to keep drilling, which adds gas supply. This is the reason the EIA forecasts Permian gas production to grow by 1.7 Bcf/d in 2026 and 2.2 Bcf/d in 2027. High oil prices are bearish for US natural gas through the supply channel.

The second channel is substitution. At $96.33 per barrel, crude oil costs $16.61 per MMBtu on an energy-equivalent basis, using 5.8 MMBtu per barrel. Natural gas at $3.11 is one-fifth the cost of oil for the same energy content. That makes gas the cheapest fuel for power generation and industrial use in the United States, supporting long-term demand growth.

The Hormuz disruption hits oil and LNG together. The same strait that carried one-fifth of the world's crude also carried one-fifth of its LNG. Every escalation that lifts Brent also keeps Qatari LNG offline, which supports global gas prices and US export demand.

Heating oil adds to the substitution case. Heating oil futures trade at $4.77 per gallon, up 1.8% on Monday and 103% higher than a year ago. US diesel prices hit a record $6.52 per gallon last week, with distillate stocks 12% below their five-year average. For households and businesses that can switch heating sources, natural gas at $3.11 is far cheaper than heating oil.

The inflation effect runs through the entire market. Higher oil prices lift inflation expectations, which push the Federal Reserve toward more hikes. The 10-year Treasury yield sits at 5.22%, and fed funds futures price a 70.3% probability of an October hike. Higher rates raise financing costs for gas producers and LNG developers, and they can slow economic activity, which reduces industrial gas demand over time.

Energy equities are reacting to the oil move. EQT, the largest US natural gas producer, and Coterra Energy are tied to Henry Hub prices, while Cheniere Energy, the largest US LNG exporter, benefits from the global price spread. Oil producers like Occidental and ConocoPhillips are up 2% on Monday.

For the forecast, high oil prices are net bearish for Henry Hub in the near term through associated gas supply, but bullish for US LNG economics through the global shortage.

Technical Map: $3.10 Support, $3.377 Resistance and the $3.529 200-Day

The chart has defined a clear trading range for the November contract. Thursday's squeeze set the range between $2.976 and $3.377. Monday's price at $3.11 sits in the lower half of that range, having broken below the retracement zone between $3.177 and $3.129.

The first support is $3.10, the level where Monday's gap lower stalled. Holding $3.10 on a daily close would suggest buyers are defending the lower part of the retracement zone. The 55-period moving average above current price acts as dynamic resistance, adding pressure on any rebound.

The critical support is $2.976, the bottom of the new main range and the low before Thursday's squeeze began. A daily close below $2.976 would erase the entire squeeze and signal that Thursday's rally was driven purely by short covering ahead of expiration rather than by a shift in fundamentals. Below that, the August average spot price of $2.76 and the August low of $2.64 mark deeper support.

On the upside, the first resistance is the retracement zone between $3.129 and $3.177. Reclaiming $3.177 would signal that the pullback has run its course and that new buyers are stepping in. The next resistance levels sit at the points November cleared during Thursday's squeeze: $3.216, $3.264, $3.291 and $3.350.

The major resistance is $3.377, Thursday's high and the top of the new range. A sustained move above $3.377 would put the 200-day moving average at $3.529 in play. Above that, the June top at $3.631 becomes the next major target.

The forward curve shows the market's expectation of higher prices. Winter contracts trade at a premium to the prompt month, pricing in heating season demand. That contango reflects the seasonal pattern and the expectation that storage will tighten through the withdrawal season.

Open interest provides the signal to watch. Thursday's rally came with falling open interest, the mark of short covering. A rebound accompanied by rising open interest would show new buyers entering the market, which would support a more durable move higher.

The trading range for the week is defined: $2.976 support against $3.377 resistance, with $3.10 as the pivot. Scenario mapping ties the levels to data. A storage build above 70 Bcf on Thursday, combined with production recovery above 112 Bcf/d, would push prices toward $2.976. A build below 50 Bcf, combined with continued LNG feedgas strength, would lift prices back through $3.177 toward $3.377.

The Week's Calendar: EIA Storage Thursday, STEO October 6 and the November Rollover

The natural gas market faces a week of data that will test whether Thursday's breakout has legs.

Monday's October contract expiration is the first event. Once October rolls off, November becomes the prompt month, and its price becomes the headline Henry Hub benchmark. November prices in the start of heating season, which typically supports a premium over October.

Wednesday brings the broader macro calendar. The PCE inflation report at 8:30 a.m. ET will move Treasury yields and the dollar, which affect commodity markets broadly. Wednesday is also month-end and quarter-end, which adds rebalancing flows. The EIA's weekly petroleum report on Wednesday will update oil and distillate inventories, relevant for the oil-gas substitution picture.

Thursday is the key day for natural gas. The EIA's weekly natural gas storage report arrives at 10:30 a.m. ET on October 1, covering the week ending September 25. The five-year average injection for that week sits in the high 70s Bcf. Another build well below the five-year average would continue to shrink the storage surplus from its current 95 Bcf and support prices. A build near or above the average would stall the surplus decline and pressure prices back toward $2.976.

Production data runs daily. Traders will watch whether Lower 48 output recovers from the 11-week low of 108.4 Bcf/d toward the September average of 112.8 Bcf/d as the Columbia pipeline and Braxton gathering issues are resolved.

LNG feedgas is the other daily signal. Flows above 18 Bcf/d, especially as Cove Point returns from maintenance, would confirm maximum export demand.

Next week brings the EIA's October Short-Term Energy Outlook on October 6. The report will update forecasts for end-of-October storage, production growth and LNG exports, and any revision to the 3,969 Bcf end-of-season storage estimate will move prices.

Geopolitics runs throughout. US-Iran talks through mediators are expected to resume this week. Progress on reopening Hormuz would ease global LNG tightness over time, while continued stalemate keeps European and Asian prices elevated and US exporters running at capacity.

Weather forecasts update daily. Any shift toward colder conditions in the Midwest and Northeast for late October would lift heating demand expectations and support November and December contracts.

Natural Gas Price Forecast: Scenarios, Levels and the Verdict

The forecast for natural gas this week turns on whether the domestic storage surplus keeps shrinking fast enough to offset near-record production. On the bearish side, September production averaged 112.8 Bcf/d, storage sits 95 Bcf above the five-year average at 3,351 Bcf, the Columbia pipeline outage has been resolved, and weather forecasts point to normal conditions through October 9. On the bullish side, LNG feedgas reached 17.8 Bcf/d, the storage surplus has shrunk from 118 Bcf to 95 Bcf in one week, salt cavern storage sits 27.2% below last year, and European gas trades above $24 per MMBtu with the Strait of Hormuz still closed.

The bearish scenario requires production to recover and storage to build. If Lower 48 output returns to 112 Bcf/d as pipeline and gathering issues clear, and Thursday's EIA report shows an injection near or above the five-year average, the storage surplus stops shrinking. Prices break $3.10, fall through the $2.976 bottom of the range and target the August average of $2.76. That would confirm Thursday's rally as a short squeeze driven by October's expiration. That path represents 4% to 11% downside.

The base case is range trade between $3.10 and $3.377. Production stays near 110 Bcf/d, LNG feedgas holds near 18 Bcf/d, and the Thursday storage report shows another below-average injection that shrinks the surplus modestly. November settles into a range as the market waits for the October 6 STEO and early heating season weather signals. Prices close the week near $3.15 to $3.25.

The bullish scenario requires continued supply tightness and stronger export demand. If production stays below 110 Bcf/d, Cove Point returns to push LNG feedgas above 18.5 Bcf/d, and Thursday's storage report shows an injection below 50 Bcf, the surplus shrinks toward 70 Bcf. Prices reclaim $3.177, break the $3.377 high and target the 200-day moving average at $3.529. An early cold snap in the Midwest or Northeast would add a weather premium, opening the June top at $3.631. That path represents 9% to 17% upside.

The structural picture favors higher prices over the winter. US LNG exports are running at capacity with 2.4 Bcf/d of new capacity coming online through December, global supply remains short with Qatar at half capacity, and the storage surplus has shrunk every week in September. The EIA forecasts end-of-October storage at 3,969 Bcf, but recent injections running far below the 103 Bcf weekly pace needed to hit that target suggest inventories will enter winter below that forecast.

But near-record production and associated gas growth driven by $96 oil cap how high prices can go. The domestic market remains well supplied in absolute terms.

The verdict for natural gas at $3.11: neutral in the near term, with $3.10 as the pivot that decides the week and $2.976 as the level that separates a pullback from a failed breakout. Expect range trade between $3.10 and $3.377 through Thursday's storage report, with a directional move after. The medium-term outlook stays bullish above $2.976, supported by record LNG demand, a shrinking storage surplus and a global gas market that will not normalize until Hormuz reopens, with a retest of the 200-day moving average at $3.529 in play once prices clear $3.377 on a daily close.

That's TradingNEWS