NG ($2.72) Down 15% in July With Storage 6.6% Above Normal and LNG Feedgas at 17.2 Bcfd — Upside Capped at $2.80

Natural gas futures extended their collapse Tuesday, trading around $2.72 per MMBtu after sliding roughly 3.5% to $2.786 earlier in the session — the lowest level in three months. The front-month contract settled Monday at $2.767, down 10.4 cents or 3.6%, having touched its weakest print since May 7 intraday.

The July damage is severe. Futures are down more than 15% across the month and more than 11% over the past four weeks. A contract that opened July above $3.20 is closing it beneath $2.80.

Monday's session was mechanically ugly. Price gapped sharply lower at the open, tumbling from the $2.950 region in a single move that erased nearly a month of consolidation gains and pressed straight through toward the $2.800 psychological level. That gap has not been filled.

The decline pushed the contract into technically oversold territory for the first time since mid-July. Composite technical ratings across moving averages now read a strong sell.

Three forces are doing the work simultaneously, and none of them is weather. Production is at record levels. Storage is running 6.4% above the five-year seasonal average and heading higher. LNG feedgas — the release valve for excess domestic supply — is running below capacity because of maintenance at a major Gulf Coast terminal.

The fourth force arrived Monday from outside the gas market entirely. Crude collapsed as the US-Iran pause held for a third session, with Brent falling 8.7% to $88.36 and extending lower Tuesday toward $87. Gas followed oil down across the curve, as it usually does when the entire energy complex reprices a geopolitical premium.

The context that makes the current level notable: futures tested a two-year high at $4.55 as recently as May. The subsequent decline has been roughly 40% in under three months, and it has happened during peak summer air-conditioning season — the period when gas is supposed to be tight.

Regional markets tell a different story. SoCal Citygate cash prices have more than doubled in July to around $4/MMBtu, making Southern California one of the most expensive gas markets in the Lower 48 as western heat drives demand and competition intensifies for regional supply.

That divergence between a $2.72 national benchmark and $4 western cash is the clearest evidence that this is a pipeline and storage story rather than a demand story.

Production Hit a Daily Record of 112.3 Bcfd on Sunday

The supply side is where the bear case originates, and the numbers are unambiguous.

Average dry gas output across the Lower 48 states has risen to 110.6 billion cubic feet per day so far in July, up from 110.0 bcfd in June and matching the monthly record high of 110.6 bcfd set in December 2025. Some estimates put the July average marginally lower at 110.4 bcfd, but the direction is not in dispute.

The daily figures are more striking. Output reached a daily record high of 112.3 bcfd on Sunday, topping the prior all-time highs of 112.2 bcfd on Saturday and 112.1 bcfd on December 21, 2025. Two consecutive record days in the middle of a price collapse.

Production is running 3.2% above year-ago levels. Official energy projections have been raised for 2026 to 110.61 bcfd, essentially ratifying the current pace as the new baseline rather than treating it as a peak.

The rig count is the detail that matters most for forward supply. The weekly count has held steady at 125 to 126, below February's two-and-a-half-year high of 134 but well above the 94-rig low from September 2024. Producers are not pulling back despite prices sitting below $3.

That is the critical asymmetry. In prior cycles, sub-$3 gas triggered rapid rig releases and shut-ins that tightened the market within a quarter. Earlier this year, production did briefly pull back to roughly 107 bcfd as some Permian producers reported price-related shut-ins. That discipline has not reappeared at current prices.

The reason is associated gas. A substantial share of Permian gas production is a byproduct of oil drilling, which means it arrives regardless of the gas price as long as crude economics work. With Brent at $87 — still 25% above July 1 levels despite the recent collapse — oil-directed drilling has no reason to slow. The gas comes out either way.

That structural feature is why record production is coexisting with a two-year price low, and why the usual self-correcting mechanism is not operating. Growth is led by the Permian region, and Permian gas is not price-responsive in the way Appalachian gas is.

Supply is not the problem the market can solve by waiting.

Storage Is 6.6% Above Normal and Thursday's Report Is the Session

The inventory picture has deteriorated steadily through the injection season, and it is the single number that has capped every rally since spring.

Working gas inventories stood 6.4% above the five-year seasonal average as of July 17 and are projected to have risen to 6.6% above normal for the week ended July 24. Analysts are waiting on the federal report Thursday for confirmation.

The trajectory tells the story better than any single reading. Inventories were 6% above the five-year average at the end of June. They were 144 Bcf above the five-year average of 2,339 Bcf back on May 22, at 2,483 Bcf. Every subsequent week has widened rather than narrowed the surplus.

Recent injection data has repeatedly surprised to the upside. A 61 Bcf net injection for the week ended July 3 was described as a bearish surprise that outpaced expectations despite record heat across key demand markets. An 87 Bcf build in a later week pushed the surplus to 6.4% and knocked 2.49% off the contract in a single session, erasing early-week gains built on heat forecasts.

The pattern has been consistent enough to become the market's operating assumption: heat forecasts push price up early in the week, the storage number knocks it back down on Thursday.

Official projections now forecast US working gas inventories reaching 3,966 Bcf by the end of October, 5% above the five-year average. Entering winter with a 5% surplus is what underpins the expectation that fourth-quarter Henry Hub averages $3.57/MMBtu — 5% below the same quarter last year.

The explanation for the surplus is straightforward and unhelpful for bulls. Mostly mild weather during the spring allowed energy firms to stockpile more gas than usual, and record production has kept the refill running above the seasonal pace even as summer demand arrived.

Bulls have needed a below-average build for weeks and have not received one. Injections have slowed from the spring refill pace, but not by enough to change the conversation.

Thursday's number is the session. A build meaningfully below the five-year average would be the first genuine bullish datapoint since spring. Anything at or above keeps sellers fading every push higher.

LNG Feedgas at 17.2 Bcfd Removes the Release Valve

The export channel is where excess domestic supply is supposed to go, and it is running below capacity at precisely the wrong moment.

Average gas flows to the nine large US LNG export plants have eased to 17.2 bcfd so far in July, down from 17.4 bcfd in June and well below the monthly record high of 18.8 bcfd set in April. That is a 1.6 bcfd gap between current flows and demonstrated peak capacity — roughly 1.4% of total Lower 48 production sitting idle relative to what the terminals can absorb.

The primary cause is scheduled maintenance at the Freeport LNG facility in Texas, and it is not resolving quickly. Flows are expected to remain low through late August, which means the release valve stays partially closed for the remainder of injection season.

With the mechanism for relieving the inventory surplus running below capacity, that surplus has no near-term path to correction. Domestic production at record levels plus constrained exports equals gas that has nowhere to go except into storage, which is already 6.6% above normal.

The longer-term picture is more constructive and entirely absent from current pricing. Damage at Qatar's Ras Laffan export facility has kept global LNG supply tight, and in principle should eventually pull more US gas into export channels. That is a multi-quarter story, and it is not showing up in feedgas numbers now.

The United States became the world's largest LNG exporter in 2023, surpassing Australia and Qatar, as elevated global prices drove demand for low-cost American gas. That structural position means US export capacity is the swing factor for global balances — and when it goes offline for maintenance, domestic prices absorb the entire adjustment.

European gas has moved the other way. Continental benchmarks hit a four-month high last week, with the forward curve sitting near the middle of the Bank of England's three energy scenarios. That divergence — European gas firm, Henry Hub at an 11-week low — is the arbitrage that export capacity is supposed to close.

It will close when Freeport returns. The question is whether it returns before the injection season ends and the surplus is locked in.

Above-Normal Heat Through August 8 Is Not Enough

The demand side has been the only supportive input all summer, and it has repeatedly proved insufficient.

Temperatures are forecast to remain mostly above normal through August 8, with some outlooks extending that to August 11. That should keep gas demand from power generators elevated to meet cooling needs. Average Lower 48 demand including exports is projected to rise from 110.8 bcfd this week to 113.3 bcfd next week.

The detail that undermines the bullish read: this week's demand forecast was revised lower from the prior Friday's outlook. Weather models have been trimming rather than adding.

Earlier in the month, forecasts called for upper-80s to above-100-degree temperatures across the northern half of the country, with major Midwest and East Coast cities pushing into the 90s. That heat arrived, and gas fell 15% anyway.

That is the most important fact in this market. When record heat produces record cooling demand and price still declines, the demand side is not the binding constraint. Production at 112.3 bcfd is simply overwhelming it.

The seasonal clock is now working against bulls. Traders have begun pricing a shrinking window for meaningful cooling demand as the end of peak summer approaches. August is the final month of the peak air-conditioning season, and after it the market transitions to shoulder-season demand with storage already 6.6% above normal.

Western heat is the exception and it is regional rather than national. Scorching temperatures across the West have driven SoCal Citygate cash prices to roughly $4/MMBtu, more than doubling through July. That reflects pipeline constraints and competition for western supply rather than any national tightness — a basis story, not a Henry Hub story.

The demand-side inputs that would actually matter from here are not weather. They are a return of Freeport feedgas, a production disruption, or an early cold snap that pulls forward heating demand. Hurricane season is the wildcard: Gulf storms can shut in production and lift prices sharply, and none has materially disrupted supply this year.

Absent one of those, above-normal heat through August 8 is priced and spent.

The September Premium Hit a Record for a Third Straight Day

The curve structure is delivering the clearest verdict available, and it is bearish.

The premium of September futures over August rose to a record high for a third consecutive day. That is the market stating explicitly that it has no concern about supplies meeting demand in August — the final month of peak summer air-conditioning season, and historically the period of greatest scarcity risk.

A widening contango into the front of the curve during peak demand season is unusual and informative. It says traders would rather own gas later than now, which only makes sense when current supply is abundant and storage capacity is available to carry it forward.

Positioning confirms the reading. Speculators boosted net short futures and options positions across the New York and Intercontinental exchanges to their highest levels since March 2024, according to the most recent weekly positioning report. That is a two-year extreme in bearish positioning.

The two facts together define the risk. A record calendar spread and record speculative shorts describe a market that is comprehensively positioned for continued weakness. That is usually correct — crowded positioning persists because the fundamentals justify it — right up until it is not.

The squeeze mechanics are worth understanding. Net shorts at a two-year high means substantial fuel for a violent upside move if a catalyst arrives. A Gulf hurricane, an unexpected Freeport restart, or a genuinely below-average storage build would force covering into a market where price has already gapped lower and liquidity has thinned.

The contract entering oversold territory for the first time since mid-July adds to that setup. Oversold conditions in a downtrend are not a buy signal on their own, but combined with two-year-extreme short positioning they define where the asymmetry sits.

The counterweight is that professional money is comfortable on the short side for good reason. An in-line storage number does nothing to change the supply cushion. Production is setting daily records. Feedgas is constrained through late August.

The market has been rewarding shorts for four straight weeks. Nothing in the current data argues that stops before Thursday.

Gas Followed Oil Down and the Correlation Is Doing Real Damage

Monday's decline was not purely a gas story, and separating the two matters for what happens next.

US natural gas futures slid more than 3.5% Monday tracking the decline in global energy prices as Middle East hostilities paused. Iran said Sunday it had halted retaliatory attacks against US allies in the region after Washington stopped its strikes since Friday. Brent crude fell 8.7% to $88.36 that session and extended lower Tuesday to around $87, with West Texas Intermediate near $81.59.

Gas futures declined across the curve on Monday as bearish production and LNG readings combined with the crude collapse.

The linkage runs through several channels. Global LNG contracts are frequently oil-indexed, so falling crude lowers the netback on international cargoes and reduces the pull on US export capacity. Fuel switching economics shift at the margin. And risk premium embedded across the entire energy complex deflates simultaneously when a geopolitical driver reverses.

There is a longer-term channel that cuts the other way and is worth flagging. Lower crude prices eventually slow oil-directed drilling in the Permian, which reduces associated gas production. That is the mechanism by which cheap oil becomes bullish for gas — but it operates on a lag of two to three quarters, not two to three sessions.

For now, the correlation is purely negative. Gas is absorbing crude's geopolitical unwind on top of its own oversupply problem.

The reversal risk is symmetrical. Tehran has rejected characterisations of a formal ceasefire, and the president has stated that strikes resume if negotiations fail. Houthi forces claimed attacks on Saudi Red Sea facilities over the weekend. If the pause collapses, crude reprices higher in a single session and gas follows.

That is a genuine tail risk sitting on top of a market with record speculative shorts.

The macro overlay adds another layer. A Federal Reserve decision lands Wednesday afternoon with implied hike odds near 36%, and traders were reported to be in no mood to hold long positions into it. Risk reduction across commodities has been broad, and gas — already the weakest energy contract — has taken the largest share.