Natural Gas (NG) Grinds at $2.977 as Qatar Stays Offline and Henry Hub Ignores It — Storage Surplus Is the Ceiling

Natural gas futures trade at $2.977 per MMBtu on Monday, September 7, 2026, against a previous close of $2.975. The session range runs $2.932 to $2.994 off a $2.940 open, and the contract settled at $2.946 on Friday. Front-month prices pushed above $2.95 during the first week of September, the highest level in nearly two months.

The 52-week range spans $2.483 to $7.827. At $2.977, the front month sits 19.9% above the low and 62.0% below the high.

That last number is the story of this market. Iran struck Ras Laffan Industrial City — home to the world's largest LNG export plant — earlier this year, Abu Dhabi suspended operations at its Habshan gas facilities, LNG assets in Bahrain were hit by missile barrages, and Qatar, which exported nearly 20% of global LNG supplies through the Strait of Hormuz in 2025, has repair timelines on damaged trains running up to five years. European storage sits at its lowest level for this point in the calendar in 15 years.

Henry Hub trades at $2.98.

The thesis for this forecast is that US natural gas has decoupled from the global LNG market, and the decoupling is a function of two domestic numbers that override everything happening overseas: inventories 5.2% above the five-year seasonal average and Lower 48 production at record highs.

American gas is landlocked by liquefaction capacity. Export terminals are running near peak, and until new trains come online the United States physically cannot ship enough to arbitrage the spread. That constraint caps how much the war can lift Henry Hub, no matter how tight Europe and Asia become.

What it does not cap is the forward curve. The EIA has forecast Henry Hub averaging just under $3.50 per MMBtu in 2026 before rising to just under $4.60 in 2027, driven by feed gas demand from LNG export facilities outrunning supply growth.

Spot at $2.977 sits $0.52 below the 2026 forecast with under four months left in the year.

US markets are closed Monday for Labor Day, leaving energy futures on abbreviated holiday liquidity. The weekly EIA storage report lands Thursday and the updated Short-Term Energy Outlook publishes Wednesday.

This is a winter trade being priced in a shoulder-season tape.

The Tape: A Six-Cent Range and Contract Mechanics

Monday's price action has been narrow and the contract specifications matter for anyone sizing a position.

The front month traded $2.932 to $2.994 on Monday, a range of 6.2 cents or 2.1% of price. The contract opened at $2.940 and has held above $2.93 through the session. Previous close was $2.975 and Friday's late reading came in at $2.946.

Contract mechanics: the tick size is 0.001 with a tick value of $10, and each full point is worth $10,000. The next settlement date is September 28, 2026. Technical indicators and moving averages generate a daily buy signal on the front month.

The recent move has been constructive without being decisive. Futures rose above $2.95 in early September, the highest in nearly two months, on a combination of elevated domestic cooling demand and tight overseas supply. That is a two-month high, not a breakout — the market spent July and August grinding between roughly $2.75 and $3.10.

Farther back the volatility has been extraordinary. The 52-week high of $7.827 was set during the winter withdrawal season when the Middle East conflict first disrupted global LNG flows, and the 52-week low of $2.483 came during the spring injection period when record production overwhelmed demand. A range that wide on the same contract inside twelve months tells you this market prices weather and geopolitics violently and reverts to fundamentals just as fast.

Historical reference points from this year: the front month traded $3.101 before a bearish July storage print sank it to $3.059, and NGI's weekly Henry Hub index sat at $3.010 in early April. Prices jumped roughly 5% to around $3.20 in March after the Ras Laffan attack, and rose more than 2.5% to $3.144 on a separate Iranian strike on Middle East energy infrastructure.

Each of those geopolitical spikes faded within days.

The pattern is consistent and it is the single most important behavioral fact for anyone trading this market: US natural gas rallies on Middle East LNG headlines and gives it all back once domestic storage data prints. Six separate occasions this year have produced the same sequence.

Monday's rally on renewed US-Iran hostilities is the seventh instance of the same setup.

Storage at 5.2% Above the Five-Year Average

The number that has capped every rally is the inventory surplus.

Utilities and other operators injected 30 Bcf into storage during the week ended August 28, a result that met expectations and initially deflated futures. Inventories stood 5.2% above their five-year seasonal average following that build.

The recent injection sequence has been modest. The week ended August 21 saw a 15 Bcf build to 3,184 Bcf, with stockpiles 30 Bcf below year-ago levels. The week ended August 14 brought a 16 Bcf injection to 3,169 Bcf. Adding the 30 Bcf for the week ended August 28 puts working gas near 3,214 Bcf.

Those are small builds by seasonal standards, and the reason is heat. Hot weather across the continental United States lifted power-burn demand for cooling, absorbing supply that would otherwise have gone into the ground. A 15 Bcf weekly build in late August is a genuinely tight physical result.

The problem is the starting point. Inventories arrived at the summer with a large cushion. In early July, the week ended July 3 produced a 61 Bcf injection — a bearish surprise against Reuters and Wall Street Journal estimates of 49 Bcf and 51 Bcf — taking Lower 48 stocks to 2,983 Bcf, 185 Bcf above the five-year average.

That 185 Bcf surplus has been compressing all summer through heat-driven power burn, but it has compressed to 5.2% above average rather than to a deficit. The market entered the injection season with too much gas and has spent three months working it off without eliminating it.

The forward projection frames the winter setup. The EIA has expected storage injections to outpace the five-year average and end October at 4,015 Bcf, following a withdrawal season that ended 3% above the five-year average at just over 1,900 Bcf.

Ending October near 4,015 Bcf would be a comfortable entry into winter and would cap upside through the first half of the heating season. Falling meaningfully short of it — which the recent 15 to 30 Bcf builds imply — is the bullish case nobody is pricing.

Full storage data publishes Thursdays at eia.gov/naturalgas/storage.

Lower 48 Output at Record Highs and 588 Active Rigs

The supply side is the reason the surplus has persisted through record cooling demand.

Average output in the Lower 48 states has remained at record highs. Earlier in the year Lower 48 dry gas production ran at 110.4 Bcf/d and was primed to increase further, with operators adding rigs and hydraulic fracturing spreads at the fastest weekly pace since late 2025.

The rig count has since stabilized. The total number of active oil and gas rigs in the United States held at 588 for the most recent reporting week — flat rather than expanding, which is the first hint that the production growth engine is losing momentum.

That distinction matters enormously for the 2027 outlook. Record production plus 5.2% surplus storage is the configuration that has kept Henry Hub near $3.00 all year. Flat rig counts plus rising LNG export capacity is the configuration that produces $4.60 in 2027, which is exactly what the EIA has forecast.

The mechanism the agency has described: annual supply growth kept pace with demand growth through 2026, holding the Henry Hub average near $3.50. In 2027, demand growth is expected to outrun supply growth, driven mainly by more feed gas demand from LNG export facilities, which reduces natural gas in storage.

Periods with higher-than-average inventories are generally associated with lower prices, while lower storage levels correspond with higher prices and tighter conditions. As inventories move toward or below the five-year average, the forecast Henry Hub price rises. Storage remains the key indicator of market balance and price formation.

Right now storage is 5.2% above average. That is the entire bear case in one number, and it is a strong one.

The associated-gas question sits underneath it. With Brent at $97.50 and WTI above $92, US oil producers have every incentive to drill, and associated gas from oil wells arrives regardless of what the gas price does. Oil at $92 is quietly bearish for natural gas because it subsidizes gas production that would not otherwise be economic at $2.98.

That is an underappreciated cross-commodity effect and it argues against a sharp Henry Hub rally while crude stays elevated.

LNG Feedgas Hits 18.3 Bcfd as Texas Plants Return

The demand side has genuinely improved, and the mechanism is export capacity utilization.

Average gas flows to the nine major LNG export plants rose to 18.3 Bcf/d in early September, up from 17.2 Bcf/d in August, as major facilities in Texas — including Cheniere Energy's Corpus Christi complex — returned to full operations after maintenance.

A 1.1 Bcf/d increase in feedgas demand is roughly 1% of Lower 48 production redirected offshore in a single month. That is a meaningful tightening at the margin and it explains why the front month climbed above $2.95.

The context that limits it: US LNG export facilities have been running at near-peak capacity throughout the conflict, exporting almost 18 Bcf/d in March, close to the record set in December 2025. With capacity utilization that high, only very limited flexibility exists to increase exports. The available flexibility comes from deferred maintenance, the pace of new project ramp-ups, and recent export authorization agreements.

That is the structural cap on this market. The world wants more American gas than America can liquefy. Every additional cargo Europe or Asia bids for has to come from a terminal that is already running flat out, and terminals take four to six years to build.

The consequence is a price disconnect rather than a price convergence. Hormuz disruptions have reduced global LNG supply and sharply increased the spread between the US benchmark Henry Hub spot price and European and Asian import prices. Foreign buyers are paying multiples of what US buyers pay for the same molecule, and the arbitrage cannot close because the pipe between them is full.

For the forecast, this reframes the LNG variable entirely. Rising feedgas is bullish for Henry Hub only to the extent capacity expands. Between now and the next tranche of liquefaction coming online, the 18.3 Bcf/d figure is close to a ceiling rather than a growth trajectory.

Watch feedgas holding above 18 Bcf/d through the autumn maintenance season. Any sustained move toward 19 would signal new capacity ramping and would be the single most bullish domestic development available.

Europe at 65% Full — the Lowest in 15 Years

The overseas storage picture is what makes this a winter trade rather than a shoulder-season one.

European storage facilities were 65% full, their lowest level for the period in 15 years, in an environment of added buying competition from Asia as Japan and Korea compete for their own LNG shipments.

Sixty-five percent going into September is a serious problem. European storage targets are typically set near 90% by November, and the continent has roughly eight weeks to add 25 percentage points of fill from a global LNG market that has lost Qatari supply through Hormuz.

The arithmetic does not obviously work. That is why buyers in Europe and Asia are seeking supplies to refill storage ahead of the winter heating season amid continued disruptions to LNG flows from the Persian Gulf, and it is why US feedgas jumped to 18.3 Bcf/d the moment Texas terminals came back from maintenance.

Every available American cargo has a bidder. The constraint is cargoes, not bidders.

The competitive dynamic between Europe and Asia is the accelerant. When Japan and Korea outbid European utilities for the same Gulf Coast cargo, the price paid rises for both and the physical shortage stays unresolved. That competition intensifies through Q4 as northern hemisphere heating demand arrives simultaneously in both regions.

The read-through to Henry Hub is indirect but real. American producers do not sell into TTF or JKM directly, but the terminals do, and terminal operators bid domestic molecules aggressively when export margins blow out. A sustained European scramble pulls feedgas demand to the absolute ceiling of installed capacity and keeps it there through March.

That is the bull case for the front of the 2027 curve.

The bear scenario for Europe is a mild winter. Storage at 65% is survivable with normal-to-warm temperatures and catastrophic with a cold December. Weather in a region 4,000 miles away is now a primary input into the US natural gas price, which is a genuinely new feature of this market.

Escalating US-Iran hostilities have raised fresh concerns over prolonged disruptions to energy shipments through Hormuz, adding to simmering concerns about global LNG supply and potentially adding demand for American exports should the war drag into the winter months.

The war dragging into winter is the base case. Vice President Vance has said no peace talks occur until Iran stops attacking ships.

Qatar, Ras Laffan, and a Five-Year Repair Timeline

The supply loss on the other side of the world is larger and more durable than most US traders appreciate.

In 2025, Qatar exported nearly 20% of global LNG supplies through the Strait of Hormuz. Iran launched missile strikes on Qatar's Ras Laffan Industrial City — the complex housing the world's largest LNG export plant — as one of several energy assets Tehran pledged to target following an Israeli strike on Iran's South Pars gas field. Abu Dhabi suspended operations at its Habshan gas facilities after intercepted missiles caused falling debris, and LNG assets in Bahrain were reportedly struck by heavy missile barrages.

QatarEnergy has estimated repairs on the damaged trains could take up to five years.

Five years is not a disruption. It is a structural removal of a meaningful share of global liquefaction capacity, and it arrives at the same moment European storage sits at a 15-year seasonal low and Asian buyers are competing for every uncommitted cargo.

The situation has deteriorated further. Tanker traffic through Hormuz has fallen to its lowest level since May, Iran has signaled a restricted maritime zone beyond the strait, and the United States struck three Iranian oil tankers over the weekend in retaliation for missile attacks on US warships.

Even repaired Qatari capacity cannot reach buyers if the waterway is contested.

The logical conclusion is that global LNG stays structurally short for years and that US export capacity becomes the scarcest infrastructure in energy. That conclusion is correct and it is already in the 2027 curve, where December 2027 futures have traded near $4.19 against an EIA estimate of $3.53.

What it has not done is lift the front month. Henry Hub at $2.977 with 5.2% surplus storage and record Lower 48 production is a domestic price for a domestic balance.

The event that would change that is a physical disruption to US supply — a hurricane taking Gulf production offline, or a freeze event during winter. Those transmit instantly because they hit the balance the front month actually prices.

Middle East headlines do not. Six spikes this year, six fades.

Weather, Power Burn, and the Shoulder-Season Handoff

The demand engine that has supported prices through August is about to switch off.

Hot weather across the continental United States kept cooling demand elevated through early September, supporting gas consumption for power generation. Strong cooling demand and pipeline operational constraints drove dramatic regional price spikes in the physical market as recently as last week.

Late-summer heat has been doing the work that would otherwise have required an inventory drawdown, and it is why weekly builds compressed to 15 and 30 Bcf rather than the 45 to 60 Bcf that would be seasonally typical.

That support has weeks left. Cooling degree days collapse through late September, and the market enters the shoulder period where neither cooling nor heating demand is meaningful. Injections normally accelerate sharply in that window, which is why the EIA has projected storage ending October at 4,015 Bcf despite the tight summer.

The counterweight this year is wind generation. One recurring analytical question through the summer has been how much strong wind generation offset hot temperatures in the power stack — renewables displacing gas-fired generation at precisely the hours when cooling demand peaks. That displacement is why some builds surprised to the upside despite record heat.

For the next four to six weeks, the balance depends on three variables in order of importance: the pace of injections once cooling demand fades, whether LNG feedgas holds above 18 Bcf/d through autumn maintenance, and whether Lower 48 production stays at record levels or begins responding to a sub-$3 price.

Hurricane season is the wild card. It runs through November and a storm taking Gulf production or a liquefaction terminal offline produces opposite effects — production outages are bullish, terminal outages are bearish, and the market has to price which one hit.

Meteorological forecasts have been the highest-frequency input. Steamy forecasts and shrinking surpluses have repeatedly failed to rally futures this summer, which is itself informative: when bullish weather stops moving price, the market is telling you supply is the binding constraint.

The handoff from cooling to heating demand happens in late October. Between now and then, this market has to justify $3.00 without weather help.

The EIA Forecast: $3.50 for 2026 and $4.60 for 2027

The official forecast and the traded price have diverged, and the gap is instructive.

The EIA has expected the Henry Hub benchmark to decrease about 2% to just under $3.50 per MMBtu in 2026 before rising sharply in 2027 to just under $4.60. The 2026 figure assumes annual supply growth keeping pace with demand growth. The 2027 figure assumes demand growth outrunning supply, driven mainly by feed gas demand from LNG export facilities, reducing storage.

Henry Hub has been running below that path. August 2026 delivered $2.78 against an EIA estimate of $2.89. The front month sits at $2.977 against a full-year forecast of just under $3.50, which means the remaining months would need to average well above $4.00 to hit the annual figure.

That is not going to happen. The 2026 forecast will be revised down.

The 2027 picture is more interesting. December 2027 futures have traded at $4.19 against an EIA STEO estimate of $3.53. In that year, the market is pricing above the official forecast rather than below it — a full reversal of the near-term relationship.

The curve is saying the same thing the fundamentals say: 2026 is oversupplied and 2027 is not, and the transition happens as new liquefaction capacity converts landlocked American gas into a globally priced commodity.

The updated Short-Term Energy Outlook publishes Wednesday, September 9, at eia.gov/outlooks/steo. The revisions to watch are the 2026 Henry Hub average, the end-October storage projection currently at 4,015 Bcf, and any change to the LNG export assumptions given the Hormuz situation.

An upward revision to 2027 alongside a downward revision to 2026 would confirm the market's own read and would steepen the curve further. That steepening is where the trade is.

For context on how the forecast has moved, the agency raised its Brent third-quarter projection by $11 per barrel in the August STEO after Hormuz constraints worsened. A comparable methodology applied to LNG feedgas assumptions would push the 2027 gas path higher.

The near-term forecast stays anchored to storage. Nothing in Wednesday's release changes the fact that inventories sit 5.2% above the five-year average today.

Technical Levels: $3.00 Overhead, $2.93 Underneath

The chart is compressed and the levels are close together.

Immediate resistance sits at $2.994, Monday's session high and the boundary of the psychological $3.00 handle. Reclaiming $3.00 on a settlement basis would be the first meaningful technical event since July and would confirm the two-month high that early September produced.

Above $3.00, the reference points come from earlier in the year: $3.010, where the weekly Henry Hub index sat in early April; $3.059 to $3.101, the range around the July storage-driven selloff; and $3.144 to $3.20, where the March Middle East spikes topped out.

Distance from $2.977: $3.00 is 0.8% up, $3.10 is 4.1%, $3.20 is 7.5%.

Support starts at $2.932, Monday's low, then $2.940 at the open, and $2.946 at Friday's close. Beneath that, the market has no visible structure until the mid-$2.70s where August traded, and then the 52-week low at $2.483.

Distance down: $2.932 is 1.5% below, $2.78 is 6.6%, and $2.483 is 16.6%.

The daily technical signal from moving averages and indicators reads Buy, which is consistent with a front month that has climbed to a two-month high from a base near $2.75.

What the chart lacks is volume conviction. Monday's session runs on abbreviated Labor Day liquidity with US markets closed, which makes any move today unreliable as a signal. Real positioning resumes Tuesday.

The asymmetry favors the upside modestly on a risk-reward basis. Storage at 5.2% above average caps rallies but the surplus has been compressing for three months, LNG feedgas is at a cycle high, European storage sits at a 15-year seasonal low, and the war shows no path to resolution. Against that, the downside from $2.977 to the low $2.70s is a well-traveled range that requires only the shoulder season arriving on schedule.

The trade structure that fits: long the winter strip against short the front month, expressing the storage-surplus-now versus LNG-shortage-later view without taking directional risk on a shoulder-season chop.

Why This Is a Fourth-Quarter Trade

The calendar is doing more work in this market than the fundamentals.

Everything bullish about natural gas is dated for the fourth quarter and beyond. European storage at 65% needs filling before December. Japanese and Korean heating demand arrives in November. Qatari repairs run for years. New US liquefaction capacity ramps through 2027. The EIA has 2027 at just under $4.60 against $2.977 today.

Everything bearish is happening now. Storage sits 5.2% above the five-year average. Lower 48 output is at record highs. Cooling demand fades within weeks. Injections accelerate through the shoulder period toward a projected 4,015 Bcf end-October level.

The result is a market where the front month has almost nothing to trade on while the deferred contracts carry the entire thesis. December 2027 futures at $4.19 against a $2.977 front month is a 40.7% contango — an enormous carry structure that pays storage operators to hold gas and penalizes anyone long the front.

That structure is itself the market's forecast, and it is a coherent one: oversupplied through the injection season, tightening as LNG capacity expands, and structurally short by 2027.

The scenario that collapses the front-month bear case before then is a cold early winter. Storage entering November near 4,015 Bcf with a severe December draws the surplus down within six weeks, and the market repricing from surplus to deficit inside a single quarter has historically produced 50% to 100% front-month moves. The 52-week high at $7.827 was set on exactly that dynamic last winter.

The scenario that extends it is a mild winter alongside continued record production, which takes the front month back toward the $2.483 low.

Between those, the base case for September and October is range-bound trading between $2.80 and $3.15 with storage prints setting the weekly direction and Middle East headlines producing spikes that fade within 48 hours.

Position sizing should reflect that a market with a $2.483 to $7.827 twelve-month range can move 20% in a week when weather turns. Stops placed on percentage distance get taken out routinely in natural gas.

The trade is the winter strip, not the front month.

This Week's Calendar: STEO Wednesday, Storage Thursday, CPI Friday

Four sessions carry three data points that matter and one that matters more than traders expect.

Monday is thin. US markets are closed for Labor Day, energy futures run on abbreviated liquidity, and the $2.977 print carries limited information.

Wednesday, September 9 brings the updated EIA Short-Term Energy Outlook. The revisions to watch are the 2026 Henry Hub average — currently just under $3.50 against a market that has been running near $2.90 — the end-October storage projection at 4,015 Bcf, and any adjustment to LNG export assumptions given the deterioration around Hormuz.

Thursday, September 10 delivers the weekly EIA natural gas storage report. The last print was a 30 Bcf injection for the week ended August 28 that met expectations and initially deflated futures. The market will be watching whether the recent pattern of below-normal builds — 16 Bcf, 15 Bcf, 30 Bcf across three consecutive weeks — continues now that cooling demand has begun to fade.

A build above 50 Bcf would signal the shoulder season arriving on schedule and would push the front month back toward $2.90. A build below 25 Bcf would suggest the summer tightness is persisting into September and would put $3.10 in play.

Friday, September 11 brings US August CPI, and this is the release traders underweight for natural gas. Headline inflation is forecast at 0.4% month over month driven by energy, against a benign 0.2% core, and the Federal Reserve decides September 15-16 with hike odds near 60%.

The transmission runs two ways. A hot print raises rate expectations, strengthens the dollar, and pressures dollar-denominated commodities broadly. It also confirms that energy is driving inflation, which sustains political attention on fuel costs at a moment when diesel has hit a record $5.85 per gallon.

OPEC's Monthly Oil Market Report and the IEA's monthly report also publish this week, giving three independent supply-demand balances for energy within days of each other.

Weekly storage data publishes at ir.eia.gov/ngs, with the STEO at eia.gov/outlooks/steo.

Thursday sets the direction. Wednesday sets the framing.

Scenario Map: Three Paths Through the Shoulder Season

Three outcomes are live between now and the end of October.

The base case is range-bound trading between $2.85 and $3.10 through the injection season, and it carries the highest probability. Storage at 5.2% above the five-year average caps rallies, record Lower 48 production keeps the supply side heavy, and cooling demand fading through late September accelerates builds toward the projected 4,015 Bcf end-October level. LNG feedgas at 18.3 Bcf/d provides a floor but cannot expand further given near-peak capacity utilization. Expect weekly storage prints to set the direction and Middle East headlines to produce 3% to 5% spikes that fade within two sessions.

The bull case requires storage builds continuing to run below the five-year average through September and October, taking the surplus from 5.2% toward parity before winter. Combine that with LNG feedgas holding above 18 Bcf/d, a cold early-season forecast, and European buyers scrambling to lift 65% storage toward 90%, and the front month clears $3.10 and targets $3.20 and then the $3.50 EIA forecast level. From $2.977 those represent gains of 4.1%, 7.5%, and 17.6%. A physical US supply disruption — hurricane or freeze — accelerates all of it.

The bear case is the shoulder season arriving on schedule with production at records. Injections of 60 to 80 Bcf per week through late September and October push storage above 4,015 Bcf, the surplus to the five-year average widens back toward 8% to 10%, and the front month retraces toward the mid-$2.70s and eventually tests the $2.483 low. Oil at $92 subsidizing associated gas production reinforces this path, and a mild European winter removes the export pull entirely.

Probability weighting on current inputs: range trading through October is the clear favorite. The bull and bear cases split roughly evenly beyond that, decided almost entirely by weather in two hemispheres.

The structural point that applies across all three: the 2027 curve at $4.19 for December against a $2.977 front month tells you the market already knows LNG capacity tightens this balance. What it does not know is when the surplus clears.

That is the trade — the timing of the tightening, not whether it happens.

Verdict: Range-Bound at $2.98 Until Storage Clears — $3.10 Is the Trigger, $2.93 the Line

The forecast is neutral for the front month and constructive for the winter strip. Natural gas at $2.977 has climbed to a two-month high on elevated US cooling demand and LNG feedgas rising to 18.3 Bcf/d from 17.2 Bcf/d as Texas terminals returned from maintenance, but it remains 62.0% below its 52-week high of $7.827 and cannot break $3.00 while inventories sit 5.2% above the five-year seasonal average with Lower 48 output at record highs. That surplus is the entire bear case and it has capped six separate Middle East spikes this year — Ras Laffan struck, Habshan suspended, Bahrain LNG hit, Qatari repairs running up to five years on capacity that carried nearly 20% of global LNG through Hormuz in 2025, and Henry Hub still trades at $2.98. American gas is landlocked by liquefaction that is already running near peak, which is why Hormuz disruptions have blown out the spread between Henry Hub and European and Asian import prices rather than lifting the US benchmark. What is genuinely bullish is dated forward: European storage at 65% full, its lowest for the period in 15 years, with eight weeks to add 25 percentage points against Japanese and Korean competition for the same cargoes; recent US builds of 16, 15, and 30 Bcf running well below seasonal norms; a flat 588-rig count; and an EIA path of just under $3.50 for 2026 and just under $4.60 for 2027 as feed gas demand outruns supply growth. December 2027 futures at $4.19 against a $2.977 front month is a 40.7% contango, and that curve is the market's own forecast that the balance tightens — it just does not tighten yet. Base case through October: chop between $2.85 and $3.10 with Thursday's storage print setting weekly direction, Wednesday's updated STEO likely cutting the 2026 Henry Hub average, and the shoulder-season handoff accelerating injections toward the projected 4,015 Bcf end-October level. The bull trigger is a settlement above $3.10 with builds continuing below the five-year average, which opens $3.20 and then $3.50. The bear trigger is builds above 50 Bcf resuming, which takes the front month back to the mid-$2.70s with the $2.483 low beneath it. Oil at $92 quietly subsidizing associated gas production is the underrated bearish input. Trade the winter strip, treat Middle East headlines as two-day spikes, and remember this contract has traveled from $2.483 to $7.827 in twelve months.

That's TradingNEWS