NG Holds $2.9255 as Storage Surplus Narrows From 5.5% to 3.7% in 3 Weeks — Break of $3.00 Opens $3.15

Natural gas futures are grinding higher on a simple fact: the U.S. is filling its storage caverns far more slowly than normal for September. The October Henry Hub contract traded at $2.9255 per MMBtu on Friday, up 0.84%, holding near its highest level since September 4. The move extends a rally that began Thursday, when government data showed a smaller-than-expected injection into storage.

The Energy Information Administration reported that working gas in storage rose by 44 Bcf in the week ended September 11, below expectations of a 49 Bcf build. The injection was half the 87 Bcf added in the same week last year and well short of the five-year average of 74 Bcf. Total inventories reached 3,298 Bcf, 122 Bcf below last year and 118 Bcf above the five-year average of 3,180 Bcf.

That surplus is shrinking fast. Storage stood 5.5% above the five-year average in late August. It now sits 3.7% above. In three weeks, the cushion has shrunk by 49 Bcf, from 167 Bcf to 118 Bcf. A string of light injections, 15 Bcf, 30 Bcf, 40 Bcf and now 44 Bcf, has eroded the surplus that record production built through the spring.

The drivers are on both sides of the market. Demand is strong: power burn across the Lower 48 is off to its strongest September start on record as summerlike heat lingers over the South, and forecasts call for warmer-than-normal weather through October 2. Exports are running hot, with flows to the nine major U.S. LNG export plants reaching a 20-week high of 18.8 Bcf per day. Supply has dipped, with Lower 48 output falling to a two-week low of 111.7 Bcf per day on Friday.

The global backdrop dwarfs Henry Hub. European gas futures jumped 3.53% on Friday to €79.05 per megawatt-hour, and U.K. wholesale gas has risen 78% since July as the Iran war disrupts supply routes through the Strait of Hormuz. Converted to U.S. units, European gas trades at more than nine times the Henry Hub price. U.S. gas is the cheapest major supply in the world, and every LNG cargo that leaves the Gulf Coast pulls domestic balances tighter.

The bearish case is not gone. Production averaged a record 113.1 Bcf per day in September, above August's record of 112.2 Bcf per day, and maintenance at Cameron LNG will cut export flows next week. The shoulder season of mild weather looms. The question for the next month is whether the storage surplus keeps shrinking enough to push the October contract through $3.00 before it expires.

The Session and the Week: A Grind From $2.77 to $2.93

Natural gas has spent the past month climbing in steps, and the path shows a market that keeps finding reasons to bid.

The September contract traded near $2.77 a month ago, reflecting a market weighed down by record production and inventories well above the five-year average. Mild spring weather and heavy output had kept storage above normal since March. The surplus peaked in the summer, and the price reflected that comfort.

The turn came with late-summer heat. Prompt-month futures posted a fourth straight weekly gain in late August, driven by strong cooling demand, tightening storage balances and a rebound in LNG feedgas flows. The market moved from pricing a glut to pricing a narrowing cushion.

This week pushed the contract to its highest level since early September. Futures rose above $2.90 on forecasts for continued warm weather and lower production, with Lower 48 output expected to fall to a two-month low of 108.4 Bcf per day on Tuesday. That drop in supply, even if temporary, landed just as demand was climbing.

Thursday's storage report added fuel. Natural gas futures were already higher when the EIA released its data at 10:30 a.m. ET, and they held comfortably in positive territory after the 44 Bcf build came in below expectations. The result was bullish relative to both forecasts and historical norms.

Friday extended the move. The October contract traded at $2.9255, up 0.84%, supported by a two-week low in production of 111.7 Bcf per day and LNG feedgas at a 20-week high. The market held its gains even as crude oil fell for a third straight session, a sign that gas is trading on its own balance rather than following the energy complex.

The contrast with oil stands out. WTI crude has fallen from its midweek highs as Saudi Arabia reroutes exports and supply fears ease. Natural gas has risen over the same stretch. The two markets are driven by different forces: oil by Middle East logistics, U.S. gas by domestic weather, production and export capacity.

The weekly structure points to a market building a base above $2.80. Each dip this month has found buyers, and each storage report has shown a smaller injection than the season would normally bring. With the October contract approaching expiration at the end of the month, the next week will determine whether the rally carries through $3.00 or stalls as traders roll into November.

The 44 Bcf Build: Half of Last Year's Pace

Thursday's storage report is the single most important data point for the natural gas market this month, and its details show a tightening balance.

The EIA's weekly storage report showed working gas in storage at 3,298 Bcf as of September 11, a net increase of 44 Bcf from the prior week. Market expectations had called for a 49 Bcf build, so the injection came in 5 Bcf light. More telling, it was 43 Bcf smaller than the 87 Bcf build in the same week last year and 30 Bcf below the five-year average of 74 Bcf.

The comparisons show how far behind the season is running. Stocks now sit 122 Bcf below last year's level, a 3.6% deficit. They remain 118 Bcf above the five-year average, a 3.7% surplus, and within the five-year historical range. The prior week's injection was 40 Bcf, and the week before that 30 Bcf.

The regional breakdown shows where the tightness sits. The Midwest led injections with a 26 Bcf build to 934 Bcf, 2.0% above last year and 3.9% above the five-year average. The South Central region, home to the Gulf Coast's storage and LNG export hubs, fell 5 Bcf to 1,039 Bcf. Salt caverns there dropped 5 Bcf to 222 Bcf while non-salt facilities held at 817 Bcf. South Central storage now sits 11.2% below last year and 0.2% below the five-year average.

That South Central deficit is the key detail. The region feeds both Gulf Coast LNG export terminals and power plants across Texas and the Southeast, where summerlike heat has persisted. Withdrawals in September, when the region normally injects, show demand outrunning supply in the market that matters most for exports.

The Pacific region fell 1 Bcf to 289 Bcf, 2.4% below last year but 9.9% above the five-year average. The Mountain region rose 2 Bcf to 241 Bcf, 7.3% below last year and 7.6% above average. All regions increased except the Pacific and South Central.

The pattern over four weeks is consistent. Injections of 15 Bcf in the week to August 21, 30 Bcf to August 28, 40 Bcf to September 4 and 44 Bcf to September 11 total 129 Bcf, an average of 32 Bcf per week. That is less than half the typical late-summer pace.

The next report arrives September 24. Another build below 60 Bcf would confirm the surplus is narrowing toward the five-year average and support a push through $3.00.

The Math Behind the Bull Case: 96 Bcf a Week to Hit the EIA Target

The most revealing number for the natural gas outlook is not in the weekly report but in the gap between current storage and the government's own forecast.

The EIA's Short-Term Energy Outlook, released September 9, forecasts U.S. working gas inventories will total 3,969 Bcf on October 31, 2026. That would be 5% above the previous five-year average and 1% above October 2025 levels. The agency attributes the relatively high inventories to strong growth in natural gas production in recent months.

Storage now stands at 3,298 Bcf. Reaching 3,969 Bcf by the end of October requires 671 Bcf of injections over the seven reporting weeks between September 11 and October 30. That averages 96 Bcf per week.

That pace is far above anything the market has delivered recently. The last four weeks averaged 32 Bcf per week. The five-year average for mid-September is 74 Bcf. Injections of 96 Bcf per week would require a sharp drop in demand, a sharp rise in supply or both.

The shoulder season can deliver bigger builds. As temperatures cool in October, air conditioning demand fades and power burn falls, while heating demand has not yet begun. Injections typically peak in the fall shoulder season. But the weather forecast points the other way in the near term, with warmer-than-normal conditions expected through October 2, keeping power burn elevated.

The gap sets up a likely revision. If injections continue near 45 to 60 Bcf per week for the rest of September before rising in October, storage would end October closer to 3,750 to 3,850 Bcf. That would leave inventories near or slightly above the five-year average heading into winter, rather than the 5% surplus the EIA projects.

That matters for price. A market expecting a comfortable 5% surplus entering winter can hold gas below $3.00. A market facing a surplus that shrinks toward zero will price in winter risk, and the winter contracts will pull the front month higher.

The EIA's next outlook arrives October 6. A downward revision to its end-October storage forecast would validate the tightening thesis and likely lift futures. The agency's production assumptions, including Haynesville output rising 1.4 Bcf per day in 2026, will be key to whether it lowers its storage call or holds it.

For the forecast, the storage math is the core of the bull case. The market is running well behind the pace needed to reach the government's own target, and every light injection widens that gap.

Record Production at 113.1 Bcf/d: The Bearish Anchor

The strongest argument against a sustained gas rally is the sheer volume of supply, and it explains why prices remain below $3.00 despite shrinking storage.

Lower 48 production averaged 113.1 Bcf per day in September, above August's record monthly average of 112.2 Bcf per day. U.S. dry gas production is running 4.4% higher than a year ago. That is the highest output in the history of the U.S. gas industry, and it has kept inventories above the five-year average since March.

The growth comes from several basins. The EIA forecasts Haynesville production will increase by 1.4 Bcf per day in 2026 and 1.3 Bcf per day in 2027, supported by stable Henry Hub prices, proximity to Gulf Coast LNG export terminals and nearby industrial demand. Appalachian production is expected to rise 0.6 Bcf per day in 2026. The Permian basin, where gas is produced as a byproduct of oil drilling, averaged a gas-to-oil ratio of nearly 4,200 cubic feet per barrel in 2025, 15% higher than in 2021.

The Permian link matters now. With oil above $100 for much of the Iran war, Permian drillers have strong incentives to pump crude, and every barrel brings associated gas. That gas flows regardless of the Henry Hub price, adding supply the market cannot easily shut off. New pipeline capacity additions support that growth.

Production has dipped this week. Output fell to a two-week low of 111.7 Bcf per day on Friday and was expected to drop to a two-month low of 108.4 Bcf per day on Tuesday. Those declines likely reflect pipeline maintenance and routine operational factors rather than a structural turn. Output tends to rebound quickly after maintenance ends.

The pattern creates a ceiling for prices. When Henry Hub rises, Haynesville producers, who drill specifically for gas, can add rigs and boost output within months. That responsiveness caps rallies. A move toward $3.50 would likely bring a supply response that pushes prices back down.

The balance explains the current price range. Record production keeps a lid on prices, while strong demand and exports keep a floor under them. The market sits between $2.70 and $3.10 because neither force has overwhelmed the other.

For the forecast, production is the key bearish variable. If output quickly returns to the 113 Bcf per day range after this week's dip, the storage deficit will narrow more slowly, and rallies above $3.00 will struggle. If production stays near the 111 Bcf per day level while heat and exports persist, the market has room to push toward $3.15.

LNG Feedgas at an 18.8 Bcf/d High and the Cameron Maintenance Dip

Exports have become the swing factor in the U.S. gas balance, and this week's flows sit near record territory.

Flows to the nine major U.S. LNG export facilities climbed to a 20-week high of 18.8 Bcf per day on Friday. That is gas leaving the domestic market to be liquefied and shipped overseas. At 18.8 Bcf per day, LNG exports absorb more than 16% of U.S. production, a share that has grown sharply as new export terminals have come online.

The global pull is extraordinary. European gas futures traded at €79.05 per megawatt-hour on Friday, up 3.53% on the day. Converted to U.S. units using the euro at $1.1464, that is $26.54 per MMBtu, more than nine times the Henry Hub price of $2.9255. U.K. wholesale gas reached 207 pence per therm on September 14, up 78% since July. Any U.S. exporter that can deliver a cargo to Europe earns a spread that dwarfs the cost of production and shipping.

The Iran war is behind the global spike. Qatar, one of the world's largest LNG exporters, ships its cargoes through the Strait of Hormuz. With the strait contested, tankers attacked and Iran enforcing a toll system on transits, Qatari supply to Europe and Asia faces disruption and higher costs. U.S. LNG fills the gap.

That makes U.S. export capacity the binding constraint. American terminals run at or near full capacity when global prices are this high. Every Bcf of new export capacity that comes online pulls more gas from the domestic market. The price gap between Henry Hub and global benchmarks shows the U.S. cannot export gas fast enough to close it.

A near-term dip is coming. LNG feedgas flows were expected to fall to a three-week low of 17.5 Bcf per day, mainly due to maintenance at Cameron LNG in Louisiana. That 1.3 Bcf per day drop from Friday's peak would leave more gas in the domestic market for a period, adding to storage injections and weighing on prices.

Maintenance is temporary by nature. Once Cameron returns, flows should climb back toward 18.8 Bcf per day or higher, given the global price incentive. The fall shoulder season also typically brings maintenance at several terminals, so feedgas can swing week to week.

For the forecast, LNG exports are the most powerful bullish driver. They connect Henry Hub to a global market in crisis. Short-term maintenance dips create buying opportunities, while the structural pull from Europe and Asia keeps a floor under U.S. prices as long as the Middle East conflict disrupts Qatari supply.

Weather: Record September Power Burn and Heat Through October 2

Weather drives natural gas more directly than any other commodity, and this September has delivered unusual heat.

Natural gas power burn across the Lower 48 is off to its strongest September start on record as summerlike heat lingers over the South. That heat has kept air conditioning demand high well past the typical end of the cooling season. Power plants burn gas to meet that demand, and gas remains the largest source of U.S. electricity generation.

The forecasts extend the heat. Warmer-than-normal weather is expected to persist through October 2, supporting gas demand from power generators. That covers the rest of the October contract's trading life and the early days of the November contract. Hotter temperatures are beginning to narrow the storage surplus that record production and mild spring weather built.

The regional heat is concentrated where it matters most. The South, including Texas and the Southeast, has borne the brunt. That region sits next to the Gulf Coast storage hubs and LNG terminals, and the South Central storage region has been withdrawing gas in September, when it would normally inject. South Central inventories now sit 11.2% below last year.

Heat also affects supply. High temperatures can reduce pipeline efficiency and force maintenance, contributing to production dips like this week's move to a two-week low of 111.7 Bcf per day.

The seasonal turn is approaching. By mid-October, cooling demand typically fades across most of the country, while heating demand does not build until November. That shoulder season is when injections usually peak. If heat breaks after October 2 as forecast, the market could see larger injections in the second half of October.

The longer-range outlook carries a wildcard. Forecasters have flagged the possibility of a strong El Niño pattern, which historically brings milder winters to the northern U.S. and could reduce heating demand. A mild winter would ease the market's concern about a shrinking storage surplus.

Winter risk works both ways. A cold winter with storage near or below the five-year average would send prices sharply higher, as heating demand overwhelms supply. A mild winter would leave storage comfortable and cap prices.

For the forecast, weather supports the near term. Heat through October 2 should keep injections light and power burn high, supporting prices above $2.80 through the October contract's expiration. The shoulder season and winter outlook will shape the November and December contracts.

The Iran War and Europe's Gas Crisis: Henry Hub's Global Link

Natural gas has become a global market, and the Middle East conflict has opened the widest gap between U.S. and international prices in years.

The Iran war has disrupted energy flows through the Strait of Hormuz for nearly seven months. Qatar's LNG exports, which supply a large share of Europe's and Asia's imports, depend on that passage. With tankers attacked and Iran asserting control over transits, the flow of Qatari gas faces constant risk.

Europe feels the impact most. European gas futures rose 3.53% to €79.05 per megawatt-hour on Friday, an elevated level that reflects tight supply heading into winter. U.K. wholesale gas prices have jumped 78% since July. The Bank of England cited those energy prices as the main driver of U.K. inflation, which reached 3.1% in August and is expected to rise further.

The pressure has reached central banks. The European Central Bank raised rates on September 10, citing energy-driven inflation, and flagged gas prices and supply disruption as upside risks. The Bank of England held rates on Thursday but three of nine policymakers voted to hike. The energy shock that lifts European gas prices is forcing monetary tightening across the continent.

Henry Hub remains insulated but connected. U.S. gas at $2.9255 trades at a fraction of European levels because the U.S. produces far more gas than it consumes and export capacity limits how much can leave. The gap is the clearest sign that American LNG terminals are running flat out and that more export capacity would pull U.S. prices higher.

The geopolitical path matters for gas as much as for oil. The president is weighing a major assault on Iran ahead of a meeting with Gulf leaders in New York next week. An escalation would further disrupt Qatari LNG, push European prices higher and intensify demand for U.S. cargoes. A negotiated end to the war would restore Qatari flows, ease European prices and reduce the pull on U.S. exports.

The U.S. impact is indirect. Because export capacity is already maxed out, higher European prices cannot pull much more U.S. gas overseas in the short term. The effect shows up instead in sentiment and in the value of new export capacity. Over months, persistently high global prices support investment in new terminals, which would raise U.S. prices as they come online.

For the forecast, the global crisis supports U.S. gas at the margin but does not dominate it. Henry Hub trades mainly on domestic storage, weather and production. The European crisis keeps U.S. export terminals full and adds a floor, but a Middle East peace deal would remove some of that support.

Energy Equities: EQT, Cheniere and What the Stocks Say

Natural gas producers and exporters offer a read on how investors view the market's durability.

Gas producers such as EQT, the largest U.S. natural gas producer, benefit directly from higher Henry Hub prices. Their margins expand as prices rise because production costs stay relatively fixed. EQT's operations in the Appalachian basin, where production is forecast to rise 0.6 Bcf per day in 2026, position it to capture any price gains.

Haynesville-focused producers face a similar setup. The Haynesville's proximity to Gulf Coast LNG terminals gives it a transport advantage, and the EIA forecasts it will lead U.S. production growth with a 1.4 Bcf per day increase in 2026. Coterra Energy, with operations in the Permian and Marcellus, produces both oil and gas and benefits from high crude prices driving associated gas output.

Exporters capture the global spread. Cheniere Energy, the largest U.S. LNG exporter, buys gas at Henry Hub prices and sells it into global markets. With European gas trading at more than nine times Henry Hub, the economics of LNG export are exceptionally strong. Cheniere's contracts are largely long-term with fixed fees, which provide stable income, but spot cargoes can capture windfall margins in a crisis like this one.

The broader energy sector has been muted. Exxon Mobil traded flat on Friday at $163.12, barely reacting to oil's third straight decline. The market is treating the war premium in energy as temporary, pricing long-term assets on normalized commodity prices rather than crisis levels.

Gas ETFs offer direct exposure. The United States Natural Gas Fund (UNG) tracks front-month futures and is affected by the roll between contracts. Leveraged products like BOIL, which offers twice the daily return of natural gas futures, and KOLD, which offers the inverse, magnify short-term moves and are best suited to active traders because of the cost of daily rebalancing.

The contract roll is relevant now. The October contract expires at the end of September, and traders are rolling into November. The November contract typically trades above October because it captures the start of heating season. ETFs like UNG face roll costs when later contracts trade at a premium, which can erode returns even if the spot price rises.

For the forecast, gas equities and ETFs give different ways to express the view. Producers and exporters offer longer-term exposure to the U.S. gas story. Futures and leveraged ETFs capture the near-term storage and weather dynamics, but carry roll and decay risks that make them better suited to short holding periods.

The Contract Roll and the Winter Premium

The structure of the natural gas futures curve adds a mechanical factor to the price outlook, and it matters as October expires.

The October contract trades at $2.9255 and expires at the end of September. Traders holding positions must roll them into November or later months. The November contract marks the start of the heating season, when demand shifts from power generation to residential and commercial heating. That transition typically lifts later contracts above the front month.

The winter contracts carry the market's risk premium. December, January and February contracts price in the potential for cold weather, when demand can surge and storage withdrawals accelerate. A shrinking storage surplus raises the value of that winter protection, because a cold snap would draw down inventories faster when the cushion is smaller.

That premium is growing. With storage surplus narrowing from 5.5% to 3.7% above the five-year average in three weeks, the market is less confident about entering winter with a comfortable buffer. That concern shows up first in the winter contracts, which then pull the front month higher as expiration approaches and the next contract becomes the benchmark.

The roll also creates volatility. As large positions shift from October to November, prices can move sharply in the final days of trading. Friday's triple witching in equity markets, with $7 trillion in options expiring, added to cross-market positioning, though gas trades on its own schedule.

The spread between the front month and winter contracts is a useful signal. A widening spread, with winter contracts rising faster than October, would confirm the market is pricing in tighter winter supply. A narrowing spread would suggest confidence that storage will reach comfortable levels.

The EIA's Henry Hub outlook frames the longer path. The agency's forecasts point to rising prices over the next year, with the spot price estimated at $4.05 per MMBtu by December 2027, well above the $2.89 average spot price in July 2026. That upward slope reflects expected growth in LNG exports and demand outpacing production gains over time.

For the forecast, the roll supports prices. As the October contract expires and November becomes the front month, the benchmark shifts to a contract that carries more winter demand. That structural lift, combined with a shrinking storage surplus, argues for a higher front-month price in October than in September, even if the physical market loosens in the shoulder season.

Technical Map: $3.00 Resistance, $2.80 Support, $3.15 Target

The October contract's chart shows a market building higher lows and pressing toward a key psychological level.

Immediate resistance sits at $3.00, a round number that has capped rallies throughout the late summer. A daily close above it would mark a breakout and the highest settle in weeks. Above $3.00, the next target is $3.15, where the market last consolidated before the summer decline. Beyond that, $3.25 marks a level that would signal the market has fully priced a winter storage deficit.

Immediate support is $2.90, the level the contract reclaimed this week and its highest point since September 4. Below that, $2.80 is the base of the recent range and the level where buyers have stepped in during pullbacks. A daily close below $2.75 would break the rising structure and open a path toward $2.70, then $2.60.

The math on the targets is clear. From $2.9255, a move to $3.00 is a 2.5% gain, $3.15 is 7.7% and $3.25 is 11.1%. On the downside, $2.80 is 4.3% below, $2.75 is 6.0% below and $2.60 is 11.1% below. Using $2.75 as the invalidation level and $3.15 as the target, the risk-reward runs close to 1.3 to 1.

Momentum favors the upside. The contract has risen from the $2.77 area a month ago to $2.9255, posting a series of higher lows. The storage surplus has narrowed for four straight weeks, giving the fundamental backdrop to the technical trend.

The key risk sits in the calendar. Cameron LNG maintenance will cut feedgas next week, and production could rebound from its dip toward the 113 Bcf per day record. Either could produce a larger injection in the next storage report, which would pressure prices back toward $2.80.

Natural gas is among the most volatile major commodities. Daily moves of 3% to 5% are common, and weather forecast changes can shift the price sharply within hours. Traders should expect wide swings around the $3.00 level.

The confirmation to watch is the September 24 storage report. A build below 60 Bcf, still well under the five-year average, would support a break above $3.00. A build above 80 Bcf would signal the shoulder season has arrived early and send prices back toward $2.80.

Natural Gas Futures Price Forecast Verdict: Bullish Toward $3.15, Invalidation Below $2.75

Natural gas enters the weekend with the fundamental balance tilting toward tighter supply. The October contract trades at $2.9255, up 0.84%, holding its highest level since September 4 after a bullish storage report.

The bull case rests on storage. The EIA's 44 Bcf injection for the week ended September 11 came in 5 Bcf below expectations, 43 Bcf below last year and 30 Bcf below the five-year average. The storage surplus has shrunk from 5.5% to 3.7% above the five-year average in three weeks. To reach the EIA's own end-October forecast of 3,969 Bcf, injections would need to average 96 Bcf per week, three times the recent pace. Power burn is off to its strongest September start on record, heat is forecast through October 2, LNG feedgas hit a 20-week high of 18.8 Bcf per day and production dipped to a two-week low of 111.7 Bcf per day. European gas at more than nine times Henry Hub keeps U.S. export terminals full.

The bear case rests on supply. Production averaged a record 113.1 Bcf per day in September, 4.4% above last year. Haynesville output is forecast to grow 1.4 Bcf per day this year. Cameron LNG maintenance will cut feedgas to 17.5 Bcf per day next week. The shoulder season approaches, and a possible El Niño could bring a mild winter. Storage remains within its five-year range and above average.

Weighing both, the forecast is bullish. The base case is a break above $3.00 as the October contract approaches expiration, with a move toward $3.15, a 7.7% gain from Friday's level, as the market rolls into the November contract and prices in a thinner winter cushion. That path requires the September 24 storage report to show another below-average injection and production to stay below its record pace.

The invalidation level is $2.75. A daily close below it would signal that record production and LNG maintenance have outweighed the heat, opening a path toward $2.60.

Natural Gas Futures Price Forecast verdict: bullish, with $3.15 as the target, $3.00 as the breakout trigger and $2.75 as the level where the thesis fails.