Henry Hub Rolls Over to $2.73 With Storage Above the 5-Year Average Since March

Front-month natural gas futures are trading at $2.73 per MMBtu, down 1.45% on the session against a previous settlement near $2.77. Over the past thirty days the contract has fallen 1.98%, and it sits 2.64% below where it traded a year ago.

That flat-to-lower performance has happened during one of the hotter summers on record for the American South. A persistent heat dome has been supporting strong regional cooling demand and slowing the pace of storage injections — and the effect on total demand and Henry Hub pricing has been muted to the point of irrelevance.

The recent high tells the same story. Prices climbed above $2.80 on August 19, reaching their highest level since July 24, on forecasts pointing to hotter weather across much of the country. Five sessions later the market has given back the entire move and then some.

Context for how far this contract has fallen: the Henry Hub spot price printed $7.72 in January 2026 during Winter Storm Fern, then $3.62 in February. It fell below $3.00 by spring and has been grinding sideways in the $2.70 to $2.90 band ever since. That is a 65% decline from the January peak inside eight months.

The structural reason sits in two numbers that define this entire market. Lower-48 production has averaged around 111.5 billion cubic feet per day so far in August, above July's monthly record of 110.7 Bcf/d. Flows to the nine major US LNG export facilities have averaged 17.2 Bcf/d in August, unchanged from July and slightly below June's record of 17.4 Bcf/d.

Supply is setting records monthly. The single largest demand growth channel is capped at a level it cannot exceed until new capacity arrives.

That mismatch is why a heat dome cannot move this market, why a bullish storage print gets ignored, and why $3.00 has become the level that decides whether the fourth quarter reprices or the front month grinds toward $2.45.

A 16 Bcf Injection Against a 29 Bcf Five-Year Average — the Bullish Print Nobody Bought

The most recent storage report was genuinely tight, and the market barely reacted.

US utilities added just 16 billion cubic feet of gas to storage last week — below both the 19 Bcf increase recorded during the same period a year earlier and the five-year average injection of 29 Bcf. That is a 13 Bcf undershoot against the seasonal norm, or 45% below the five-year pace.

In a balanced market, a print that far below expectations produces a sharp rally. Prices held, then faded.

The explanation is that inventories remain above the seasonal norm despite the small injection. Record production and relatively mild weather earlier in the year built a cushion large enough that a single week of below-average building does not change the year-end trajectory. Storage has stayed above the five-year average since March, through a summer of persistent heat.

That is the definition of an oversupplied market: the bullish data points arrive, they are real, and they do not matter because the starting inventory position absorbs them.

The comparison across the demand stack shows why. Gas output has remained strong enough to keep storage levels comfortable despite sustained summer heat. Cooling demand from the heat dome pulled the weekly injection to 16 Bcf rather than to a draw — meaning even at peak seasonal consumption, the market is still adding to inventory rather than depleting it.

The one qualification worth noting is regional. Maintenance at LNG export terminals has decreased feedgas demand, which left storage levels above the five-year average specifically in the South Central region at the end of July. That is where the excess concentrated, and it is the region that feeds the Gulf Coast export complex.

For the forecast, the storage picture argues that any rally requires sustained sub-20 Bcf injections rather than a single print. The next report lands Thursday, and it covers a week with continued heat and continued record output.

111.5 Bcf/d: Production Just Broke Another Record

The supply side is the reason every bullish argument in this market keeps failing, and the trajectory has been relentless.

Lower-48 production has averaged approximately 111.5 billion cubic feet per day so far in August, above July's monthly record of 110.7 Bcf/d. Each month this summer has set a new high. Marketed production in the Lower 48 reached a record 118.5 Bcf/d in November of last year, with winter output averaging an estimated 117.8 Bcf/d.

The growth is largely involuntary, which is what makes it so difficult to reverse. A substantial portion comes from associated gas — methane produced alongside crude oil in the Permian and elsewhere across the Lower 48. That gas gets produced regardless of the Henry Hub price, because the economics of the well are driven by the oil barrel rather than by the gas stream.

With WTI trading at $85.65 and Brent at $93.09 after two consecutive weekly gains above 5%, oil-directed drilling remains economic at prices far above where anyone would drill for gas alone. Elevated crude is therefore a bearish input for natural gas, not a bullish one — the exact inverse of the correlation most traders assume.

That relationship is the single most underappreciated dynamic in this market right now. The Middle East conflict that has crude near $93 is simultaneously ensuring that American associated gas production keeps setting records.

Robust output combined with relatively mild spring weather has kept inventories above the five-year average since March despite persistent summer heat. Supply growth has outpaced demand growth by roughly 0.5 Bcf/d across 2026 in official projections, with demand including exports increasing by less than 1% while supply including imports rose nearly 1%.

For the price to sustain a move above $3.00, either production has to roll over or a demand channel has to expand. Neither is happening in the third quarter.

LNG Feedgas Stuck at 17.2 Bcf/d — the Export Ceiling

The demand channel that was supposed to absorb record production has hit a physical wall, and it is the most important constraint in this forecast.

Flows to the nine major US LNG export facilities averaged 17.2 Bcf/d in August, unchanged from July and just below June's record of 17.4 Bcf/d. Third-quarter LNG exports are projected to average 16.5 Bcf/d, revised slightly lower than the prior month's estimate because of ongoing maintenance at one major Gulf Coast facility.

The ceiling is structural rather than commercial. Export terminals were already operating at high utilisation before global gas prices spiked, which limits the ability to export additional volumes in the near term regardless of how attractive international arbitrage becomes. There is no spare liquefaction capacity waiting to be dispatched.

That single fact explains why the global gas crisis has not lifted American prices. Reductions in LNG flows through the Strait of Hormuz have pushed European and Asian gas prices sharply higher. US prices have been relatively unaffected, because the physical link between the two markets — liquefaction capacity — is saturated.

The maintenance dimension makes it worse in the near term. Terminal outages reduce feedgas demand, which pushes molecules that would have been liquefied back into domestic storage. That mechanism is precisely what left South Central inventories above the five-year average at the end of July.

The flexibility that does exist sits in ramping projects rather than in existing trains. Corpus Christi Stage 3 completed a train earlier this year and Golden Pass has been coming online, but those additions arrive incrementally across quarters rather than in step changes.

Pipeline exports offer a secondary outlet. Mexico's new Energia Costa Azul terminal and increased use of US natural gas for power generation south of the border are driving pipeline volumes higher, with total US gas exports projected to rise through 2027.

That helps at the margin. It does not close a gap between 111.5 Bcf/d of production and a 17.2 Bcf/d export ceiling.

The EIA Just Cut Its 2026 Henry Hub Forecast to $3.44

The official forecast trajectory across 2026 is the clearest measure of how badly this market has disappointed, and the revisions have been one-directional.

The August Short-Term Energy Outlook lowered the 2026 Henry Hub spot price forecast by more than 6% from the July estimate, cutting it from $3.67 to $3.44 per MMBtu. That annual forecast has now fallen more than 20% since the February estimate of $4.31 — a figure that had been supported by sustained heating demand, record storage withdrawals and the temporary price spike during Winter Storm Fern.

The revision sequence tells the story. January projected just under $3.50 for 2026 with a sharp rise to just under $4.60 in 2027. February lifted the 2026 number to $4.31 on winter strength. March cut it to almost $3.80, a 13% reduction, citing milder-than-expected February weather leading to more gas in storage. July had it at $3.67. August took it to $3.44.

Five months, four downward revisions, and a cumulative 20% cut from the peak estimate.

At $2.73, the front month trades 20.6% beneath even the reduced $3.44 annual average — which is arithmetically consistent, since that average includes the $7.72 January print and the winter months still ahead. Strip out the first quarter and the implied path for the remainder of 2026 sits well below $3.44.

The 2027 picture is where the constructive case lives. Demand growth is projected at 2.5 Bcf/d against supply growth of 0.9 Bcf/d, reversing the current surplus into a 1.6 Bcf/d deficit and putting upward pressure on prices. Annual average spot prices are forecast to decline 2% in 2026 and then increase 33% in 2027.

That is a genuinely bullish structural forecast. It is also a 2027 forecast, and the front month has to survive four more months of record production before it gets there.

From $7.72 to $2.73: Reconstructing the 2026 Round Trip

The path this contract has taken through 2026 is worth mapping, because it establishes the range that defines every level in this forecast.

The Henry Hub spot price averaged $3.19 in October 2025, $3.79 in November and $4.26 in December as winter positioning built. January 2026 delivered the spike — a monthly average of $7.72, driven by sustained heating demand, record storage withdrawals and Winter Storm Fern. That is the highest monthly average since the 2022 energy crisis.

February collapsed to $3.62. A 53% single-month decline as the weather normalised and the storage draw stopped.

From there the descent continued. Prices fell below $3.00 by spring and have not sustainably recovered. The July 20 spot print was $2.80. August has traded between roughly $2.70 and $2.85, with the August 19 push above $2.80 marking the highest level since July 24.

The longer arc puts the current level in perspective. Henry Hub bottomed at $1.63 in June 2020 during the pandemic, spiked to a 14-year high of $9.85 in August 2022 on European supply fears, crashed back below $2.00 in early 2023, recovered through the 2024 LNG export ramp, then ran from below $2.00 in early 2024 to $7.72 in January 2026 before returning below $3.00.

Two complete round trips inside six years. This is the most violently mean-reverting liquid commodity market that exists.

The practical consequence for positioning is that $2.73 is neither extreme nor safe. It sits above the 2020 and 2023 lows but well beneath the level required to incentivise gas-directed drilling. Prediction markets covering the highest daily 2026 spot price already assign high probabilities to the $5.01 and $5.51 thresholds — because the January $7.72 print already cleared them. Those contracts are settled history, not forward expectation.

What matters forward is whether the winter of 2026-27 repeats the pattern.

Europe Is Paying Up and America Cannot Sell Into It

The most striking dislocation in global energy right now is that two gas markets sharing a supposedly integrated LNG channel have moved in opposite directions.

Reductions in LNG flows through the Strait of Hormuz have driven natural gas prices in Europe and Asia sharply higher. European gas has been climbing on supply shortages tied to the Middle East disruption, with those increases expected to maintain upside risk to eurozone inflation. Qatari output — the single largest LNG source transiting Hormuz — has been shut in for extended periods.

American prices have gone nowhere. Henry Hub trades at $2.73 while the international market pays a substantial premium.

The reason is capacity, not commerce. US LNG export facilities were already operating at high utilisation before the conflict began, which limits the ability to export additional volumes in the near term. A US producer cannot capture the international arbitrage without a liquefaction slot, and every slot is spoken for.

The global picture stands in stark contrast to the bearish domestic one: tightening supply-demand balances internationally against a well-supplied American market heading into the fall shoulder season with strong production continuing.

That divergence is not a temporary distortion. It is the structural condition of the US gas market until new liquefaction capacity comes online, and it caps how much any international event can lift Henry Hub.

The trade implication cuts against intuition. Escalating Middle East disruption is bullish for European TTF, bullish for Asian JKM, and roughly neutral-to-bearish for Henry Hub — because it does nothing to relieve American oversupply while keeping crude elevated enough to sustain associated gas production.

The one channel where it matters is 2027, when the incremental trains ramp and the arbitrage becomes physically capturable. That is the same year the supply-demand balance is forecast to flip.

Storage Above the Five-Year Average Since March

The inventory position is the anchor holding this market down, and it has been in place for five months.

Storage levels have remained above the five-year average since March, supported by record production and relatively mild spring weather. That cushion has persisted through a summer of sustained heat and a persistent heat dome across the South — conditions that in a tighter market would have drawn inventories back toward the norm by August.

The most recent weekly injection of 16 Bcf, while 13 Bcf below the five-year average of 29 Bcf, still built inventory rather than depleting it. At peak cooling season, with power burn elevated, the market added gas.

The regional distribution matters for basis and for the front contract. South Central storage sat above the five-year average at the end of July, driven by reduced feedgas demand from export terminal maintenance. That region delivers into the Gulf Coast liquefaction complex and into the Henry Hub delivery point itself, which means the excess is sitting exactly where it exerts maximum pressure on the benchmark.

The forward projection is where the picture eventually improves. Official forecasts expect storage inventories to gradually move below the rolling five-year average as demand outpaces supply — but that transition is a 2027 phenomenon driven by LNG feedgas growth, not a third-quarter one.

For comparison, inventories closed December 2025 at 1.7% above the 2020-24 five-year average. The current position is comfortably wider than that.

What would change the read is a run of sub-20 Bcf injections through the September shoulder season. Injection season typically ends in late October or early November. With roughly ten weeks remaining, a sustained pattern of injections 40% below the five-year norm would erase the cushion before winter.

That is the bull scenario, and Thursday's print is the first data point in testing it.

$3.00 Is the Line That Decides Everything

The technical structure reduces to a single round number, and the market has respected it since spring.

Natural gas broke below $3.00 during the spring collapse and has not sustainably reclaimed it. The August 19 push above $2.80 — the highest level since July 24 — represented the strongest attempt of the month and failed within days. At $2.73, the contract sits 9.9% beneath the $3.00 threshold.

A break and sustained close below $3.00 opens the path toward $2.00 per MMBtu, a level most assessments view as unsustainable given LNG export dynamics but achievable in a severe warm-winter scenario. That path has already been partially travelled — the market is below $3.00 and grinding.

The immediate reference points are tighter. $2.80 is the August high and the first genuine resistance, 2.6% above spot. Above it, $3.00 becomes the objective, and clearing that opens $3.10 and eventually the $3.44 annual average projection.

Beneath spot, $2.70 is the level the market has been defending through the month. A decisive break there exposes $2.45, roughly 10.3% down, which represents the summer floor zone. Below that, the market is in territory it has not visited since the 2024 lows.

The channel analysis points higher over a longer horizon. The mid-range of the multi-year channel sits around $4.00 per MMBtu, described as the most likely destination heading into winter 2026-27, with an upper boundary near $5.00 reachable only under a significantly colder-than-normal winter.

That is the tension in this chart. The near-term technicals point toward $2.45. The seasonal and structural framework points toward $4.00 within six months. Both can be right, and the resolution comes through the October-to-November contract roll.

The single level to watch this week: $2.80. Reclaiming it on a sub-20 Bcf storage print changes the near-term read.

The Winter Curve Says $4 — the Front Month Says $2.73

The forward curve carries a steep seasonal premium, and the size of that premium is the clearest expression of what the market actually believes.

Front-month gas at $2.73 sits against winter-dated contracts pricing substantially higher, with the December and January strips carrying the heaviest premium of the year. That contango is normal for natural gas — storage costs, weather risk and the seasonal demand profile all justify a winter premium — but the current width is doing something specific.

It is telling you the market has entirely written off the balance of injection season and moved its risk premium to the heating months.

The reasoning is defensible. Summer cooling demand cannot absorb 111.5 Bcf/d of production when LNG feedgas is capped at 17.2 Bcf/d. Winter heating demand can. Residential and commercial consumption is forecast at 22.1 Bcf/d for 2026 — a segment that essentially vanishes in August and returns in November.

The trap in that reasoning is storage. Every molecule that fails to find a buyer this summer goes into inventory, and every molecule in inventory is available to meet winter demand without a bid. A market that enters November with storage above the five-year average requires genuinely cold weather to justify the forward premium, not merely normal weather.

That is precisely what happened last winter and then reversed. Winter Storm Fern drove January spot to $7.72. February normalised to $3.62. The forward curve was right for one month and wrong for the next.

For a trader, the practical expression is that the front month is where the pain lives and the winter strip is where the optionality lives. Selling the front and owning the winter is the structurally correct expression of everything in this analysis — and it is also the most crowded position in the gas market, which limits how much further the spread can widen.

The roll into the October contract is when this gets tested.

Warmer Than Normal Through September 3: the Last Summer Catalyst

Weather is the only variable that can move this market before the shoulder season, and the current forecast is constructive without being decisive.

Forecasts point to predominantly warmer-than-normal conditions through September 3, which could support demand from power generators. That extends the cooling season by roughly ten days beyond the typical peak and represents the last meaningful power-burn demand of the summer.

Gas-fired generation has been the strongest demand component all year. New solar projects and increased use of natural gas-fired power plants have been the leading sources of generation growth, and gas demand for electric power averaged 45.6 Bcf/d during a comparable July week — more than 15% above the prior year.

The problem is scale. Even elevated power burn during a heat dome produced a 16 Bcf injection rather than a draw. Extending that condition ten days into September reduces injections at the margin without changing the trajectory.

What happens after September 3 is the more important question. The fall shoulder season — roughly mid-September through October — is the period of minimum demand, when neither cooling nor heating load is meaningful. Production does not fall during that window. Injections accelerate. The market is well supplied heading into it, with strong production continuing to support growing global demand that it cannot physically reach.

That sequencing argues for the path of least resistance being lower into late September, with the winter risk premium doing the work of holding the curve up.

The counter-scenario is an early cold snap in October or November. Gas is the only commodity where a two-week weather event can produce a 100% price move, and the January 2026 precedent is fresh. A market at $2.73 with storage 3% above the five-year average is not positioned for that, which is why the downside is capped in probability terms even where it is open technically.

2027 Is the Bull Case: Plaquemines, Corpus Christi and Golden Pass

The genuine constructive argument for natural gas is not about this quarter or even this winter. It is about liquefaction capacity arriving in 2027, and the numbers behind it are substantial.

LNG exports are forecast to grow 9% — roughly 1.3 Bcf/d — in 2026, and 11%, or approximately 1.7 Bcf/d, in 2027. That growth traces to three specific facilities: Plaquemines LNG, Corpus Christi Stage 3 and Golden Pass LNG. Plaquemines and Corpus Christi Stage 3 continue ramping toward full operations, with Golden Pass beginning operations across the current forecast window.

The balance shifts as they come online. Supply growth outpaces demand growth by 0.5 Bcf/d in 2026 but falls behind by 1.6 Bcf/d in 2027. Demand growth of 2.5 Bcf/d against supply growth of 0.9 Bcf/d flips the market from surplus to deficit, drawing storage inventories gradually below the five-year average and putting sustained upward pressure on price.

The price forecast follows mechanically: annual average spot down 2% in 2026, then up 33% in 2027 to somewhere between $3.90 and just under $4.60 per MMBtu depending on the vintage of the estimate.

That is a 43% to 68% advance from $2.73 across roughly eighteen months, driven by infrastructure that is already under construction rather than by weather or geopolitics.

The risk to that thesis is the same one that has undermined every gas forecast this cycle: production keeps beating expectations. Each incremental Bcf/d of export capacity gets partially absorbed by another record production month, and the Permian keeps producing associated gas as long as crude stays near $93.

The industrial side offers no offset. Consumption in the industrial sector is forecast to decrease across both 2026 and 2027 on closer-to-normal weather and reduced activity as measured by the gas-weighted manufacturing index. Residential and commercial consumption falls 4% in 2026 to 22.1 Bcf/d.

LNG is carrying the entire demand growth story. If those trains slip, the 2027 case slips with them.

Thursday's Storage Print and September 9's STEO

Two scheduled data points sit between now and the shoulder season, and one of them is weekly.

The Weekly Petroleum Status equivalent for gas — the EIA natural gas storage report — releases every Thursday. This week's print covers a period of continued heat, continued record production and continued flat LNG feedgas. The prior week delivered 16 Bcf against a 29 Bcf five-year average and a 19 Bcf year-ago figure.

The threshold that matters is 20 Bcf. A second consecutive injection beneath that level would establish a pattern rather than an anomaly, and it would begin eroding the storage surplus that has capped this market since March. An injection above 30 Bcf confirms the oversupply and sends the front month toward $2.45.

The September 9 Short-Term Energy Outlook is the larger event. The August edition cut the 2026 Henry Hub forecast from $3.67 to $3.44 — a more than 6% reduction and the fourth downward revision this year. The September release will incorporate August production data at 111.5 Bcf/d and the shoulder-season injection trajectory.

Given the pattern, another cut is the base case rather than the risk case. A revision beneath $3.40 would confirm that even the official forecast has abandoned any recovery within 2026.

The macro calendar interacts at the margin. The July PCE print lands Wednesday and the Federal Reserve Chair speaks Friday at Jackson Hole. Gas is less rate-sensitive than any other major commodity — it is a physically constrained, regionally isolated market — but a broad commodity repricing on a weaker dollar would lift it alongside crude and gold.

The dollar index at 98.723, its lowest since May 14, has provided a modest tailwind that the fundamentals have entirely overwhelmed.

Terminal maintenance schedules are the wildcard. A return of the Gulf Coast facility currently under maintenance would add feedgas demand immediately.

Verdict and Price Forecast: $3.10 on a Sub-20 Bcf Injection, $2.45 If $2.70 Breaks

Natural gas at $2.73 is an oversupplied market with a genuinely bullish 2027 structure sitting four months and one shoulder season away.

The bear case rests on five verifiable numbers. Lower-48 production averaged 111.5 Bcf/d in August, above July's record of 110.7 Bcf/d, with each month setting a new high. LNG feedgas has been capped at 17.2 Bcf/d, unchanged from July and below June's 17.4 Bcf/d record, with export terminals already at high utilisation before the global squeeze began. Storage has stayed above the five-year average since March despite a persistent heat dome. The 2026 Henry Hub forecast has been cut from $4.31 in February to $3.44 in August, a 20% reduction across four revisions. And the fall shoulder season — the annual demand minimum — begins in roughly three weeks.

The bull case rests on four equally verifiable numbers. Last week's injection of 16 Bcf came in 45% beneath the five-year average of 29 Bcf and below the 19 Bcf year-ago figure. Forecasts point to warmer-than-normal conditions through September 3, extending power burn. LNG exports are set to grow 1.3 Bcf/d in 2026 and 1.7 Bcf/d in 2027 as Plaquemines, Corpus Christi Stage 3 and Golden Pass ramp, flipping the balance to a 1.6 Bcf/d deficit in 2027. And the official price path calls for a 33% increase in 2027 toward $3.90 to $4.60.

The forecast: natural gas holds $2.70 to $2.85 through Thursday's storage print. A second consecutive injection beneath 20 Bcf reclaims $2.80 and opens $3.00, with $3.10 the target on a sustained sub-20 pattern — a 13.6% advance. Clearing $3.00 on a decisive basis puts the $3.44 annual average in play for the winter strip.

Downside: a print above 30 Bcf breaks $2.70 and targets $2.45, a 10.3% decline. A sustained close beneath $2.45 through the shoulder season opens the path toward $2.00, a level that is achievable but requires a warm start to winter.

The verdict is bearish through September, constructive into the winter roll, and genuinely bullish for 2027. Sell rallies toward $2.85 until $3.00 breaks, buy weakness at $2.45, and treat the December strip rather than the front month as the place to own the structural case.

That's TradingNEWS