NG ($2.908) Holds Above $2.80 Low as LNG Feedgas Hits 18.8 Bcf and TTF Trades 9.2x Henry Hub

Natural gas futures traded at $2.908 per million British thermal units on Tuesday, up 0.42% on the session, after climbing above $2.94 earlier in the day for the highest level since September 4. The move marked a second consecutive gain and extended the rebound from the three-week low of $2.80 printed on September 10. Over the past month, prices have risen 8.11%. Over the past year, they remain 6.28% lower.

That last number is the story. Every other major energy benchmark is surging. WTI crude ripped 4.60% to $106.06 a barrel on Tuesday afternoon, and Brent climbed 3.04% to $108.89. Heating oil jumped 6.03% to $5.26 a gallon and trades 119.79% above its level a year ago. European natural gas at the Dutch TTF hub stands at €79.38 per megawatt-hour, up 145.55% year over year. UK gas trades at 197.53 pence per therm, up 149.09%.

Henry Hub is the exception. The war with Iran, the effective closure of the Strait of Hormuz, the shutdown of Saudi Arabia's East-West pipeline and the Houthi advance on Bab el-Mandeb have sent global energy prices sharply higher. U.S. natural gas has barely participated.

The reason is structural. The United States produces far more gas than it consumes, and the only way to send that surplus into a global market paying 9.2 times more is through LNG export terminals that are already running at their limit. Feedgas flows to the nine major U.S. LNG export plants reached a 20-week high of 18.8 billion cubic feet per day last Friday. Lower 48 production averaged a record 112.9 Bcf per day in September. Storage stood at 3,254 Bcf as of September 4, 4.8% above the five-year average. Global scarcity cannot reach Henry Hub because the export pipe is full.

That structure is starting to shift at the margin. Lower 48 output is expected to fall to a two-month low of 108.4 Bcf per day on Tuesday, 4.5 Bcf per day below the September average. Hotter-than-normal temperatures are keeping power-sector demand elevated through September 30. The storage surplus is estimated to have narrowed to 3.6% above the five-year average in the week ending September 11, down from 4.8% the week before.

The thesis of this forecast is that Henry Hub is caught between a narrowing domestic surplus that points toward $3.00 and a mild-winter outlook that keeps the forward curve under pressure. The $2.80 low defines the floor, $3.00 defines the ceiling, and Thursday's storage report decides which breaks first.

From $2.80 to $2.94: How the Rebound Built Over Five Sessions

The path to Tuesday's price started with a bearish surprise.

On Wednesday, September 9, natural gas futures slipped below $2.80 ahead of the government storage report, extending a weekly retreat of 23 cents as fading power demand and the approach of milder fall weather pressured the market. Traders had targeted the $3 mark in early September as heat forecasts intensified and renewed U.S.-Iran fighting added a fresh jolt, but futures never closed above it.

The storage data on Thursday, September 10 deepened the selloff at first. The Energy Information Administration reported a 40 Bcf net injection for the week ending September 4, above consensus expectations for 31 Bcf. The build lifted total working gas in storage to 3,254 Bcf, 4.8% above the five-year average. Futures fell to a three-week low of $2.80 per MMBtu. The injection was lean by historical standards for early September, but the market had priced something even leaner.

Futures clawed back from those early losses during the same session. Lower production and strong LNG feedgas provided support, and prices rebounded despite fading weather-driven demand. Friday's session ended flat, but the prompt contract still posted a 14.4-cent weekly loss as the approaching shoulder season outweighed strong exports and lower output.

Monday, September 14 delivered the turn. Prompt futures gained momentum from the opening bell on strong LNG feedgas and stout near-term cooling demand. Lower 48 output fell to a two-week low of 111.7 Bcf per day on Friday, while feedgas flows to LNG terminals climbed to 18.8 Bcf per day, a 20-week high. Futures rose to $2.90 by the close. Intraday peaks failed to breach key technical resistance, a sign that sellers were still active above $2.90.

The physical market moved faster than futures on Monday. Cash prices vaulted across the Southeast and Gulf Coast as capacity cuts and restrictions piled up on regional pipelines while a heat wave kept summer-like temperatures in place.

Tuesday extended the gains. Futures pushed above $2.94, the highest price since September 4, as forecasts showed Lower 48 production falling to a two-month low of 108.4 Bcf per day. By afternoon trading, prices settled back to $2.908, up $0.0122 on the day.

The pattern since September 10 is a series of higher lows: $2.80, then $2.90, then $2.908 with a $2.94 intraday high. What has not happened yet is a daily close above $3.00.

Storage: 3,254 Bcf, a Surplus Shrinking From 4.8% to 3.6%

Storage is the anchor for Henry Hub pricing, and the trend has quietly turned supportive.

The Energy Information Administration's latest weekly report showed working gas at 3,254 Bcf as of September 4 after a 40 Bcf injection. The prior week's injection was 30 Bcf. At 4.8% above the five-year average, the surplus implies the five-year norm for that week sits at 3,105 Bcf, leaving a cushion of 149 Bcf.

That cushion has been shrinking. Record production and mild spring weather kept inventories above the five-year average since March. The heat of July, August and early September has steadily eroded the surplus. Analysts estimate that storage stood 3.6% above the five-year average in the week ending September 11. A drop of 1.2 percentage points in a single week is a meaningful move in a market where storage balances usually shift gradually.

The next data point lands Thursday, September 17, when the EIA releases storage data for the week ending September 11. The consensus estimate will decide whether futures break $3.00 or retreat to $2.80. A build below 40 Bcf would confirm that heat and exports are outpacing production. A build above 50 Bcf would suggest the production dip was temporary and demand is fading.

The EIA's own forecast sets up a key test. In its September Short-Term Energy Outlook, the agency projected U.S. working gas inventories will total 3,969 Bcf on October 31, 2026, 5% above the 2021-2025 average and 1% above October 2025 levels. The EIA attributed the high inventory outlook in part to strong growth in natural gas production in recent months.

The math behind that forecast is demanding. To move from 3,254 Bcf on September 4 to 3,969 Bcf on October 31, storage needs to add 715 Bcf over eight weeks, an average of 89 Bcf per week. The last two weekly injections came in at 30 Bcf and 40 Bcf, averaging 35 Bcf. Injections typically accelerate in late September and October as cooling demand fades, but the gap between a 35 Bcf pace and an 89 Bcf requirement is wide.

If lean injections persist into late September because of continued heat and record LNG exports, end-October inventories would land below the EIA forecast, and the surplus to the five-year average would shrink further. That is the bullish case for Henry Hub heading into winter. If temperatures cool quickly after September 30 and production recovers toward 113 Bcf per day, injections would accelerate toward the EIA's path, and the surplus would stabilize at 5%. That is the bearish case.

Production: Record 112.9 Bcf in September, Dropping to 108.4 Bcf Tuesday

Supply is the variable that has capped Henry Hub all year, and it is showing its first real crack.

Lower 48 dry gas production averaged 112.9 Bcf per day in September through September 10, above August's monthly record. That output has kept storage above the five-year average since March despite record LNG exports and one of the hottest summers on record. The EIA's forecast for high end-October inventories rests largely on that production strength.

The daily data this week tells a different story. Output fell to a two-week low of 111.7 Bcf per day last Friday. For Tuesday, average production is expected to drop to a two-month low of 108.4 Bcf per day. That represents a decline of 4.5 Bcf per day, or 4.0%, from the September average.

Several factors can drive short-term production drops of that size: pipeline maintenance, capacity restrictions that force producers to shut in wells, and weather-related disruptions. Monday's pipeline capacity cuts in the Southeast and Gulf Coast are a likely contributor. Early September also brought the season's first Gulf Coast tropical storm to the Texas-Louisiana LNG corridor, though it did not dent feedgas nominations.

The key question is duration. A single-day production dip caused by pipeline maintenance typically reverses within a week, and prices give back gains when output recovers. A sustained drop caused by producer curtailments in response to low prices would be a structural shift.

The price signal supports the curtailment argument at the margin. Henry Hub at $2.91 sits 6.28% below its level of a year ago, while producers face higher costs for diesel, steel and equipment tied to the broader energy and inflation shock. Heating oil and diesel are up 119.79% over the year. Gas-weighted producers operating in the Haynesville, which requires higher prices to justify drilling, face compressed margins at sub-$3 gas.

The associated gas problem cuts the other way. A large share of U.S. gas comes from oil wells in the Permian Basin, where production is driven by crude prices, not gas prices. With WTI at $106.06, Permian oil drillers have every incentive to keep pumping, and the gas that comes with their oil keeps flowing regardless of Henry Hub. Monday's sharp Permian cash price rebound reflects regional takeaway constraints, not a lack of supply.

For the forecast, production is the swing factor over the next two weeks. If output stays below 110 Bcf per day through the September 17 storage report and the following week, the injection pace stays lean and $3.00 comes into range. If it rebounds to 112 to 113 Bcf per day, the rally fades back to $2.80.

LNG Feedgas at 18.8 Bcf: The Export Pipe Is Full

LNG exports are the channel that connects Henry Hub to a global market in crisis, and that channel is running at its limit.

Average feedgas flows to the nine major U.S. LNG export facilities rose to 18.3 Bcf per day so far in September, up from 17.2 Bcf per day in August. Texas facilities returned to full operations after maintenance, lifting throughput. On Friday, September 11, flows reached 18.8 Bcf per day, a 20-week high. At 18.3 Bcf per day, LNG feedgas absorbs 16.2% of Lower 48 production.

Global demand explains the surge. Buyers in Europe and Asia are replacing disrupted Middle Eastern supplies and replenishing inventories ahead of the winter heating season. The memorandum of understanding signed by the U.S. and Iran in June 2026 to halt military operations effectively collapsed in July when Iran resumed targeting commercial shipping in the Strait of Hormuz. Qatar, one of the world's largest LNG exporters, ships its cargoes through that strait. The Houthi capture of islands controlling Bab el-Mandeb now threatens the Red Sea route that carries 80% of the LNG shipped north to Europe.

The price gap shows how disconnected the markets have become. TTF at €79.38 per megawatt-hour converts to $91.60 per megawatt-hour at a EUR/USD rate of 1.1540, or $26.85 per MMBtu. Henry Hub trades at $2.91. European buyers are paying 9.2 times the U.S. price, a spread of $23.94 per MMBtu. UK gas at 197.53 pence per therm converts to $26.62 per MMBtu at a GBP/USD rate of 1.3475, confirming the same gap.

That spread represents enormous profit per cargo for U.S. exporters and their offtakers, but it does not lift Henry Hub much because physical capacity limits how much gas can be liquefied. Every molecule of available export capacity is already being used. Additional demand from Europe and Asia cannot translate into additional U.S. gas consumption until new liquefaction trains come online.

Long-term contracts show confidence in future export growth. On Monday, Venture Global said it signed a sales and purchase agreement to supply 0.5 million tonnes per year of LNG to China Gas for 20 years starting in 2030, the latest in a series of agreements for its Gulf Coast project portfolio.

For Henry Hub, LNG is a floor-builder, not a price-setter. Feedgas at 18.3 to 18.8 Bcf per day provides a steady, price-insensitive demand base that keeps storage injections lean. Any disruption to export terminals, such as a hurricane forcing plant shutdowns, would be bearish for Henry Hub because stranded gas would flow back into domestic storage. The Gulf Coast hurricane season runs through November, making that a live risk.

Weather: Above-Normal Heat Through September 30 and a Historic El Niño Winter

Weather sets the near-term direction for Henry Hub, and the forecasts point in two directions depending on the time horizon.

The near term is supportive. Meteorologists expect temperatures to remain mostly above normal across the continental U.S. through September 30. Earlier forecasts extended above-normal heat through September 26, though conditions were projected to be less extreme than previously thought. Hot conditions across the South and Southeast are keeping air-conditioning demand elevated and forcing power generators to burn more natural gas.

September has been exceptionally warm. In early September, forecasts suggested the month could become the hottest September on record, giving traders a reason to target the $3 mark. Blistering heat across the western U.S. this summer has also massively tightened regional storage balances compared with historical norms heading into the shoulder season.

Power demand has a structural component beyond weather. Rising electricity consumption from data centers and industrial load is expanding natural gas's role as a flexible fuel for power generation. That trend increases gas burn during hot periods and raises the baseline demand that storage must cover. Federal emergency orders extending the lives of aging coal plants are complicating the pace of gas-to-power growth by keeping some coal generation online that would otherwise be replaced by gas.

The longer term is bearish. Natural gas winter forward prices sank to their lowest levels of the year last week as a historically strong El Niño and stout supply continued to pressure the 2026-27 winter strip. That slide mirrors the pattern of the past three years. A strong El Niño typically brings milder winter temperatures across the northern United States, reducing heating demand during the months when storage withdrawals are largest. A mild winter with inventories starting at 3,969 Bcf would leave the market oversupplied into spring 2027.

That creates a disconnect between the prompt contract and the winter strip. Near-term heat supports October futures at $2.91. The winter contracts, which normally trade at a significant premium to October because of heating demand, face pressure from the El Niño outlook. A narrowing of that seasonal premium limits how far the prompt contract can rally before traders sell the curve.

Regional weather effects add volatility. Above-average Midwest natural gas inventories have done little to erase regional premiums embedded in the winter forward curve, showing the value the market places on pipeline access and deliverability during peak demand periods.

For the forecast, weather supports a test of $3.00 into late September. The shoulder season in October and the El Niño winter outlook cap the rally beyond that.

The Energy Complex: WTI at $106, Heating Oil Up 120% and Henry Hub Down 6%

Natural gas is trading in a different universe from the rest of the energy complex, and the gap reveals both its weakness and its hidden support.

The oil market exploded again on Tuesday. WTI crude climbed 4.60% to $106.06 a barrel by afternoon, its highest level in four months, and has gained 25.51% over the past month. Brent reached $108.89, up 19.83% over the month. Saudi Arabia informed European refiners that their September crude cargoes were being canceled because its East-West pipeline remains shut after a September 11 drone attack. The outage puts 4 million barrels a day, 4% of global supply, at risk.

Refined products are moving even faster. Heating oil jumped 6.03% to $5.26 a gallon on Tuesday and is up 119.79% year over year. Gasoline rose 3.96% to $3.45 a gallon. Methanol, a gas-derived chemical, trades 47.15% above last year's level, and propane has gained 19.46% over the year.

The relative value comparison is extreme. WTI at $106.06 per barrel equals $18.29 per MMBtu of energy content. Heating oil at $5.26 per gallon equals $37.92 per MMBtu. Henry Hub natural gas at $2.908 delivers the same energy for a fraction of the price: one-sixth the cost of crude and one-thirteenth the cost of heating oil. WTI trades at 36.5 times the Henry Hub price.

That gap creates structural demand support. Industrial users that can switch between fuels have every incentive to burn gas instead of oil products. Petrochemical producers in the Gulf Coast gain a massive feedstock cost advantage over competitors in Europe and Asia who rely on oil-based naphtha or imported LNG. Power generators with dual-fuel capability run gas-fired units at maximum output.

The gap also reflects the fundamental difference in market structure. Oil is a global commodity with a single price set by seaborne trade. When Middle East supply is disrupted, every barrel everywhere reprices. U.S. natural gas is a regional commodity connected to global markets only through LNG terminals with fixed capacity. When Middle East LNG supply is disrupted, European and Asian prices soar, but Henry Hub only feels the effect through incremental export demand.

Coal adds context. Coal prices stand at $146.85 per tonne, up 44.68% year over year. Higher coal prices reduce the competitiveness of coal-fired power generation relative to gas, supporting gas burn in the power sector even with federal orders keeping some coal plants online.

For the forecast, the energy complex offers asymmetric support. If oil and global gas prices keep rising, pressure builds for more U.S. export capacity and fuel switching, which tightens domestic balances over time. If the Middle East de-escalates and oil collapses, Henry Hub would lose little because it never priced the war premium in the first place.

The Macro Layer: A 5% 10-Year Yield, a Fed Hike and the Dollar

Natural gas is less directly exposed to interest rates than equities or crypto, but the macro backdrop still shapes positioning and producer behavior.

The 10-year Treasury yield hit 5.041% on Tuesday, its highest level since 2007, before settling at 5.005% in the afternoon. Fed funds futures price an 86.3% chance that the Federal Reserve lifts its target range to 3.75% to 4.00% on Wednesday, the first hike since 2023. The dollar index stood at 99.636, up 0.25%.

Higher rates affect natural gas through three channels. The first is producer financing. Gas-weighted exploration and production companies rely on credit facilities and bond markets to fund drilling programs. Higher borrowing costs reduce the number of wells that clear return hurdles at sub-$3 gas, which supports the curtailment argument behind this week's production dip.

The second channel is LNG project finance. Every new liquefaction terminal requires billions of dollars of capital, and higher long-term rates raise the cost of that capital. Contracts like Venture Global's 20-year agreement with China Gas help secure project financing by locking in revenue, but rising rates still stretch development timelines. Slower export capacity growth leaves more gas trapped in the domestic market for longer.

The third channel is speculative positioning. Commodity funds and managed money traders adjust exposure based on risk appetite and the dollar. A firmer dollar generally weighs on commodities priced in dollars, and a hawkish Fed tends to trigger broad commodity deleveraging.

Inflation data creates a specific link to natural gas. August CPI rose 0.4% month over month and 3.4% year over year, driven heavily by energy. Natural gas feeds into electricity prices and household heating bills, both part of the CPI basket. If Henry Hub stays below $3.00 while oil rockets, gas becomes a disinflationary force relative to oil, which marginally reduces pressure on the Fed.

The broader equity market was weak on Tuesday. The S&P 500 traded at 7,588 in the afternoon, down 0.42%, and the Dow fell 0.79%. Energy stocks were the exception, with Exxon Mobil gaining 2.43% to $169.09. Gas-weighted producers typically lag oil-weighted names during oil-driven rallies because their revenue depends on Henry Hub, not WTI.

For the forecast, macro factors are a secondary input. A hawkish Fed dot plot on Wednesday could trigger brief commodity selling that pushes gas toward $2.85. The dominant drivers for Henry Hub remain storage, production, weather and LNG flows.

Technical Structure: $2.80 Floor, $2.94 High, $3.00 Ceiling

The chart reflects a market compressing between a tested floor and a round-number ceiling.

The primary support sits at $2.80, the three-week low printed on September 10 after the larger-than-expected storage build. That level held on a closing basis and sparked a rebound within the same session. A daily close below $2.80 would signal that the rebound has failed and the market is pricing an accelerating injection pace heading into October. From $2.908, $2.80 represents a 3.7% decline.

Below $2.80, the next support sits at $2.69, the level implied by Tuesday's 8.11% monthly gain, marking where futures traded in mid-August before the late-summer heat rally. That is a 7.5% decline from current prices. A break of $2.69 would erase the entire August-September advance.

On the upside, Monday's close at $2.90 is the first reference, and Tuesday's price sits just above it. Tuesday's intraday high above $2.94 is the first resistance. Monday's intraday peaks failed to breach key technical resistance, which confirms sellers are active at the $2.94 area.

The $3.00 level is the major ceiling. Traders targeted it in early September as heat forecasts peaked and U.S.-Iran fighting resumed, but futures never closed above it. A daily close above $3.00 would represent a 3.2% gain from $2.908 and would open the path toward $3.10, the level where prices traded a year ago based on Tuesday's 6.28% annual decline. That target sits 6.6% above current prices.

Momentum is building gradually. Two consecutive sessions of gains, a higher low at $2.90 and a new high since September 4 point to improving short-term structure. The 14.4-cent weekly loss in the week ending September 11 has been partly recovered.

Volatility is modest compared with oil. Tuesday's move of 0.42% contrasts with WTI's 4.60% jump. That relative calm reflects the insulated nature of the U.S. gas market, but it also means breakouts tend to be slower and more dependent on storage data than on headlines.

The October contract expires at the end of September, and the roll into November adds complexity. November carries a seasonal premium because it marks the start of the heating season, but the El Niño outlook has compressed that premium. Traders using continuous charts should watch for roll effects that can distort apparent price moves.

Natural Gas Equities: EQT, Coterra, Expand Energy and Cheniere

The equity market offers a leveraged read on how investors are pricing the gas outlook, and the picture diverges by business model.

Gas-weighted producers are the most direct Henry Hub play. EQT, the largest U.S. natural gas producer, operates primarily in the Appalachian Basin, where production costs are among the lowest in North America. Expand Energy, formed from the merger of Chesapeake Energy and Southwestern Energy, holds major positions in both Appalachia and the Haynesville. Coterra Energy has a more balanced portfolio spanning the Marcellus gas play and the oil-weighted Permian Basin.

For these companies, sub-$3 Henry Hub prices compress margins at a time when operating costs are rising. Diesel for drilling rigs and trucks has surged with heating oil prices up 119.79% year over year. Steel for well casing and equipment reflects broader inflation. The combination of flat revenue per unit and rising costs creates a margin squeeze that typically leads producers to defer new well completions, which is exactly the kind of discipline that supports prices over time.

The Haynesville is particularly sensitive. Its proximity to Gulf Coast LNG export terminals makes it the natural supply source for export growth, but its deeper wells require higher prices to generate returns. Producers there tend to respond fastest to price signals, making Haynesville activity a leading indicator for supply trends.

Coterra's Permian exposure gives it a hedge. With WTI at $106.06, its oil-weighted assets generate strong cash flow that offsets gas price weakness. The associated gas from those Permian wells, however, adds to national supply regardless of Henry Hub.

LNG exporters sit on the other side of the trade. Cheniere Energy, the largest U.S. LNG exporter, profits from the spread between low domestic gas prices and high international prices. With TTF trading at $26.85 per MMBtu and Henry Hub at $2.91, the spread is historically wide. Cheniere's long-term contracts lock in tolling fees, but its uncontracted spot volumes capture a portion of the spread directly.

Leveraged ETFs amplify the prompt contract. The United States Natural Gas Fund tracks front-month futures, while leveraged products magnify daily moves in both directions. These instruments suffer from roll costs when the futures curve is in contango, which can erode returns even when spot prices rise.

For the forecast, equity positioning offers a sentiment signal. A breakout in gas-weighted producers ahead of Henry Hub futures would suggest investors expect supply discipline and a tighter winter balance. Continued lagging would confirm the market views the El Niño winter as the dominant risk.

Scenario Map: Where Henry Hub Trades Over the Next 30 Days

The next month for natural gas depends on four variables: the pace of storage injections, the durability of the production dip, the September heat and the October shoulder season transition. They combine into three scenarios.

The first scenario is the base case. Thursday's storage report shows an injection in the 40 to 50 Bcf range, the surplus to the five-year average holds at 3.6%, production recovers partially to 110 to 111 Bcf per day, and above-normal heat fades after September 30. LNG feedgas stays at 18.3 Bcf per day. Futures test $3.00 in late September but fail to close above it, then drift toward $2.85 as October contracts roll and shoulder season demand falls. The trading range is $2.80 to $3.00.

The second scenario is the bullish breakout. Thursday's report shows an injection below 40 Bcf, the surplus narrows below 3%, production stays below 110 Bcf per day for more than a week, and heat extends into early October. Feedgas climbs back toward 18.8 Bcf per day. Futures close above $3.00 and target $3.10, a 6.6% gain, then $3.25 as the market prices end-October inventories well below the EIA's 3,969 Bcf forecast. A Gulf Coast hurricane that disrupts production without shutting LNG terminals would accelerate this path.

The third scenario is the bearish breakdown. Thursday's report shows an injection above 50 Bcf, production rebounds to 112 to 113 Bcf per day, and temperatures cool quickly. The storage surplus stabilizes at 4% and injection rates accelerate toward the 89 Bcf per week pace needed to reach the EIA forecast. The El Niño winter outlook pressures the entire curve. Futures break $2.80 and retreat toward $2.69, a 7.5% decline. A hurricane that forces LNG export plants offline would add to this path by trapping gas in domestic storage.

The probabilities favor the base case with a modest bullish tilt. The production dip to 108.4 Bcf per day and the shrinking storage surplus are real signals, and LNG demand has no reason to fall while European gas trades at $26.85 per MMBtu. The El Niño winter strip, however, caps how far the prompt contract can rally before the curve pulls it back.

One wildcard sits outside all three scenarios. A decisive escalation in the Middle East that closes Bab el-Mandeb to LNG tankers would push TTF sharply higher and intensify global demand for U.S. cargoes. Henry Hub would gain only modestly because export capacity is already full, but LNG exporters and long-dated U.S. gas contracts would rally.

Natural Gas Futures Price Forecast Verdict: $2.80 Floor, $3.00 Test, $3.10 Target on a Close Above

Natural gas futures at $2.908 per MMBtu are the calmest price in an energy market in crisis. WTI crude jumped 4.60% to $106.06, heating oil climbed to $5.26 a gallon and trades 119.79% above last year, and European gas at the TTF hub costs $26.85 per MMBtu, 9.2 times Henry Hub. U.S. gas is up just 0.42% on the day and 6.28% lower than a year ago because the domestic market is oversupplied and the LNG export pipe is full. Lower 48 production averaged a record 112.9 Bcf per day in September, storage stood at 3,254 Bcf and the EIA projects 3,969 Bcf by October 31.

The balance is tightening at the margin. Production is expected to fall to a two-month low of 108.4 Bcf per day on Tuesday. LNG feedgas hit a 20-week high of 18.8 Bcf per day on Friday. The storage surplus is estimated to have narrowed to 3.6% above the five-year average from 4.8%. Above-normal heat is forecast through September 30. And reaching the EIA's end-October forecast requires injections averaging 89 Bcf per week, far above the recent 35 Bcf pace.

The short-term bias is mildly bullish. Futures have posted higher lows at $2.80 and $2.90 and broke to their highest level since September 4 on Tuesday. The first test is the $2.94 area, where Monday's rally stalled. A daily close above $3.00 opens $3.10, a 6.6% gain from $2.908, with $3.25 as the extended target if Thursday's storage report shows an injection below 40 Bcf and production stays below 110 Bcf per day.

The downside risk is the shoulder season and the winter outlook. A storage build above 50 Bcf, a production rebound to 113 Bcf per day or an early cooldown would push futures back through $2.80 toward $2.69. The historically strong El Niño has already pushed the 2026-27 winter strip to its lowest level of the year, and that pressure limits how long any prompt rally can last.

The 30-day forecast range is $2.69 to $3.10, with $2.80 as the floor and $3.00 as the pivot. Thursday's EIA storage report for the week ending September 11 is the catalyst that decides which level breaks first. Until then, Henry Hub is a range trade with a modest upside bias, supported by falling production and record exports, and capped by a surplus that is shrinking but has not disappeared.

That's TradingNEWS