Henry Hub ($2.72) Stabilises Below a Broken $2.801 Support Base as Production Hits 111.2 Bcf/d and Brent Rallies 7.4% Without It

US natural gas futures rose to $2.72 per MMBtu on Wednesday, up 0.68% from the prior session, in what looked like the first genuine stabilisation after four consecutive losing days. The front-month contract had been in freefall since the middle of last week.

The sequence that got it here was brutal. Prices slid more than 3.5% to $2.77 on Monday, the lowest level since May 8, tracking a decline across global energy as Middle East hostilities paused. Tuesday extended the damage, taking futures below $2.70 — a three-month low — weighed down by strong production, comfortable inventories and weak LNG feedgas demand.

The monthly damage is severe. Natural gas has fallen roughly 17% over the past month and sits about 10.7% below where it traded a year ago. Henry Hub spot printed $2.80 on July 20 and cash markets have been sliding since.

That is a market where the bearish case has been winning on every input simultaneously, which does not happen often and rarely lasts.

The context is worth holding. In mid-June, Henry Hub cash averaged $3.086 with the prior day's index at $3.315, against Permian benchmark Waha at $1.811 — the usual basis blowout that has become a structural feature of Texas gas. Prices have lost roughly 40 cents from those levels in six weeks despite peak summer cooling demand.

What broke this month was the pattern that had held all summer: a hot forecast lifts the bid, then the surplus and production bring sellers straight back. The July decline came when the weather leg failed alongside the geopolitical leg, leaving nothing to offset the supply argument.

Wednesday's bounce is thin evidence of anything. A 0.68% recovery after a 17% monthly decline is noise until it holds through Thursday's storage report, which lands at 10:30 a.m. ET and is the only scheduled catalyst in this market before August.

The Federal Reserve decision at 2:00 p.m. matters considerably less here than it does across the rest of the commodity complex. This is a domestic supply-demand market, and it is currently oversupplied.

Brent Jumped 7.4% and Gas Moved 0.68% — The Decoupling Is the Story

The single most instructive fact about this market today is what did not happen.

Brent crude gained 7.4% to $90.35 a barrel overnight after Iranian ballistic missiles targeted a US base in Jordan and US and Saudi forces struck sites in eastern Iraq. West Texas Intermediate advanced roughly 7.4% to $85.11. Crude reversed a three-session, 16% collapse in a single overnight window.

Natural gas moved 0.68%.

That divergence is the clearest possible statement about what drives Henry Hub in 2026. US natural gas is a domestic market with a domestic supply glut, and geopolitical risk premium does not transmit into it the way it transmits into a globally traded, waterborne barrel.

The transmission mechanism that exists — LNG exports linking US supply to international prices — is currently running below capacity rather than at it, which severs the connection precisely when a shock arrives.

There is one exception worth noting and it cuts the same direction. When Middle East hostilities paused earlier this week, natural gas fell alongside crude, sliding 3.5% on Monday. Gas participates in energy-complex selloffs but not in energy-complex rallies, which tells you the market is positioned short and treats geopolitical news as an excuse to reduce rather than as a reason to reverse.

The structural explanation is straightforward. The geopolitical risk-off unwind acted as the immediate trigger for the July decline, but it was the underlying supply glut — record domestic output, swelling inventories and softening LNG export throughput — that gave the selloff its depth and left the market with little near-term catalyst for recovery.

For traders, the practical read is that watching crude to trade gas has stopped working. The correlation holds on the downside and breaks on the upside, which is the worst possible configuration for anyone hedging a long position.

What matters instead is Thursday's storage number, daily production prints, and whether LNG feedgas recovers from its maintenance-driven dip.

The Support Base Broke: $2.823 and $2.801 Are Now Resistance

The technical structure gave way this week and the break was clean enough to redraw the entire map.

Through the middle of July, the market had been consolidating between the April bottom at $2.974 and a long-term low at $2.823. That range had held since aggressive sellers forced longs out roughly two weeks earlier, and the support base beneath it was identified as $2.857 to $2.801.

At $2.72, price sits below the entire structure. The $2.823 long-term low is gone. The $2.801 support floor is gone. Both are now overhead resistance rather than a base.

That distinction matters more than the price level itself. A market trading inside a defined range with a support base beneath it is a market where dip-buyers have a defined risk point. A market that has broken the base has no such reference until a new one is built, which is why the four-session decline accelerated rather than stalled.

The recovery path is now considerably longer. To repair the structure, futures need to reclaim $2.801, then $2.857, then re-enter the prior range at $2.823 to $2.974. Only above $2.974 — the April bottom — does the market return to anything resembling neutral.

Above that, the resistance targets identified are a pair of 50% retracement levels at $3.089 and $3.121, capped by the 50-day moving average at $3.146.

Technical screens have been uniformly negative across every timeframe, with hourly, five-hour, daily, weekly and monthly readings all registering as strong sell signals. That is unusual — most markets show at least one timeframe in disagreement — and it reflects a decline that has been persistent rather than sharp.

Below current price the map is thin. The three-month low set Tuesday is the first reference, then the May 8 level, then $2.60 as a round number with no particular structural significance. Beneath $2.60 there is very little until the spring lows.

Wednesday's 0.68% bounce is inside the noise band. It becomes meaningful only on a close above $2.801.

Production at 111.2 Bcf/d Is the Number That Caps Everything

The supply side is the reason every rally this summer has failed, and the numbers have been moving in one direction.

Lower-48 dry gas production has been running between 110.4 and 111.2 billion cubic feet per day depending on the measurement day. Average output rose to 110.4 to 110.6 Bcf/d so far in July from 110.0 Bcf/d in June, matching the monthly record high set in December 2025. One Wednesday print hit 110.9 Bcf/d, up 2.5% from a year earlier. Another reading put output at 111.2 Bcf/d, running 3.2% above year-ago levels.

The Energy Information Administration raised its 2026 US dry natural gas production forecast to 111.2 Bcf/d from a June estimate of 111.0 Bcf/d, which effectively ratified the market's own reading of the supply picture.

Record production growth is being led by the Permian region, where gas is an associated byproduct of oil drilling rather than a targeted output. That distinction is critical and underappreciated. Permian gas volumes are governed by crude economics, not by the Henry Hub price. A gas price of $2.72 does not slow a well drilled for $85 oil.

Which means the standard supply-response mechanism — low prices curtail drilling, output falls, prices recover — is partially disabled in the current market structure. The associated gas keeps coming regardless.

The supply side is not giving the bulls anything to work with, and it has not for months. Every weekly production print this summer has come in at or above the prior week, and each one has capped whatever rally the weather forecast had generated.

Wood Mackenzie's forward estimates have been running around 109.5 Bcf/d over rolling seven-day windows, slightly below the realised monthly pace, which suggests some near-term moderation. That gap has not been large enough to matter.

For the price to recover on supply, output needs to fall below roughly 108 Bcf/d and stay there. Nothing in the current data suggests that is coming before the shoulder season.

A Rig Count of 126 Says Producers Are Not Blinking

The clearest evidence that supply relief is not arriving comes from the drilling data.

The natural gas rig count held steady at 126 in the latest weekly reading, unchanged from the prior week. That is below February's 134-rig high, so the industry has trimmed activity — but it has not capitulated, and producers are not pulling back despite prices sitting under $3.

That combination is significant. A rig count that flattens rather than collapses at sub-$3 gas tells you the marginal producer is either hedged through the back half of the year, drilling for liquids with gas as a byproduct, or operating at a breakeven low enough that current strip prices remain economic.

All three are probably true simultaneously, and all three mean the same thing for price: no supply response.

The service sector data supports it. Management teams at the major oilfield services providers have been unanimously reporting increased activity and improved sentiment from their North American exploration and production customers. That is not the commentary you get from a sector preparing to cut.

The forward-looking read is worse for bulls than the current count suggests. Rig counts lead production by roughly six to nine months. A count that held at 126 through the spring implies production continues rising into the fourth quarter regardless of what happens to price between now and then.

What would change it is a sustained move below $2.50, which would push a meaningful share of dry-gas Appalachian and Haynesville production toward or below cash cost. That is roughly 8% below current levels and it has not been tested this cycle.

Even then, the response would arrive in 2027 rather than in this injection season.

The practical implication for positioning: do not model a supply-side rescue. The bull case in this market has to come from demand — either weather, LNG, or power generation — because the supply side has been answered and the answer is no.

Storage at 6.6% Above the Five-Year Average and Building

The inventory picture is the second half of the bearish case and it has been deteriorating steadily.

Gas inventories stood 6.4% above the five-year seasonal average as of July 17 and were expected to rise to 6.6% above normal for the week ending July 24. At the end of June the surplus stood at 6%. The direction is wrong and it has been wrong for a month.

The weekly builds tell the story. Operators injected 32 Bcf into storage for the week ended July 17, a result that modestly exceeded historical norms and landed within the range of major polls. Its initial impact on prompt-month futures was muted, which is itself a signal — a market that shrugs off an in-line print is a market where the surplus is already fully discounted.

For context, the week ended June 12 delivered a build that took stocks to 2,759 Bcf, 5.8% above the five-year average, and that print was considered bullish relative to expectations at the time.

The forward projection is the number that matters for the winter setup. The EIA forecasts US working natural gas inventories reaching 3,966 Bcf by the end of October, 5% above the five-year average. Entering the withdrawal season with a 5% surplus caps the winter rally before it starts, because the first cold snap draws against a cushion rather than against a deficit.

Injections during peak summer that exceed historical norms — while cooling demand is running near record levels — is the specific combination that indicates genuine oversupply rather than seasonal softness. If the market cannot draw or hold flat in late July, it will not do so in September.

One regional nuance is worth flagging. South Central storage flipped into deficit territory in the final week of May, and the combination of flat production and rising regional demand carries price implications that do not show up in the national number. Regional tightness in the Gulf is the mechanism by which a national surplus can still produce basis blowouts and localised spikes.

That is a spread trade, not a flat-price trade.

Thursday's Storage Report Is the Only Catalyst This Week

The weekly Natural Gas Storage Report publishes Thursday at 14:30 GMT — 10:30 a.m. ET — covering the week ended July 24, and it is the only scheduled event capable of moving this market before August.

The setup going in is unusual. Price has broken beneath its support base and is attempting a first bounce, which means the report lands into a market with no defined technical reference and light positioning after four sessions of liquidation.

That combination amplifies the reaction in both directions. A build materially above expectations confirms the surplus trajectory toward 6.6% and takes futures back through Tuesday's three-month low. A build meaningfully below consensus — particularly one that stalls the surplus expansion — hands the bounce a fundamental justification and opens the $2.801 to $2.857 recovery zone.

Historical precedent this summer suggests the muted outcome is most likely. The July 17 print exceeded historical norms and moved prompt futures almost not at all, because the market had already priced the direction.

What has produced genuine reactions has been surprise. A lean print in June for the week ended June 12 came in below the low-80s Bcf expectation and drove a midday rally, because it broke the pattern rather than confirming it.

The wider context for reading the number: record power burn has been supporting demand, gas-fired generation recently hit a nearly one-year high before slipping as wind and solar output increased, and ERCOT power demand has been approaching record levels amid scorching Texas heat.

Those are genuine demand-side positives that have failed to show up in the storage data, which is the clearest evidence available that production is simply overwhelming them.

Beyond Thursday, the next scheduled catalysts are the August 11 Short-Term Energy Outlook and the September expiry roll. There is nothing structural in between, which means August trades on weather models and daily production prints.

LNG Feedgas at 17.2 Bcf/d Has Stopped Being the Bull Story

The demand channel that was supposed to absorb the domestic surplus has been running below expectations, and its softness is the most recent addition to the bearish case.

Gas flows to major LNG export terminals have averaged 17.2 Bcf/d so far this month, slightly below June's 17.4 Bcf/d, with a separate weekly reading showing feedgas easing to 17.8 Bcf/d — down 3.3% week over week. Scheduled maintenance at the Freeport facility in Texas accounts for a meaningful share of the shortfall.

Set that against where the market expected to be. In June, LNG exports were projected to average 18.5 Bcf/d, not far from records north of 20 Bcf/d and more than 3 Bcf/d above year-earlier levels, with terminal feedgas consumption climbing as seasonal maintenance concluded.

The gap between 20 Bcf/d records and 17.2 Bcf/d actual is roughly 2.8 Bcf/d of demand that has not materialised — which is approximately 2.5% of total Lower-48 production going unabsorbed.

Physical markets have registered it directly. Gulf Coast cash prices retreated in late July as weaker feedgas demand weighed on regional hubs, with Henry Hub, Houston Ship Channel and Agua Dulce all losing ground amid the Freeport maintenance and concerns that former Tropical Storm Bertha could temporarily disrupt export activity.

The structural view remains constructive. Strong LNG exports could quickly erase the storage surplus by autumn if throughput normalises — that argument has been made repeatedly through the year and it remains arithmetically sound. Every 1 Bcf/d of incremental feedgas is roughly 30 Bcf per month of storage that does not get injected.

Longer-dated capacity continues expanding. Partners behind one Canadian project advanced its feedgas connection to the Western Canadian Sedimentary Basin, awarding a contract for a critical pipeline section.

But maintenance-driven softness now is real demand not showing up now, and this market has stopped paying for future demand.

Ras Laffan and the Global LNG Tightening Nobody Can Trade Yet

There is one genuinely bullish structural development sitting in the background, and the market has correctly declined to price it.

Damage at Qatar's Ras Laffan export facility could eventually tighten global LNG supply enough to pull more US gas into export channels. Qatar is among the largest LNG exporters on earth, and a sustained reduction in its output would redirect Asian and European buyers toward Atlantic Basin cargoes, lifting US feedgas demand and drawing down domestic storage.

That is a longer-term story and it is not showing up in current feed gas numbers. Which is precisely the right way to trade it — the mechanism requires months to transmit, and the transmission only occurs if US terminals have spare liquefaction capacity to absorb the redirected demand.

They currently do, given feedgas is running roughly 2.8 Bcf/d below record throughput.

International price references illustrate the arbitrage that would need to open. Front-month LNG cargoes into East Asia have historically traded at multiples of Henry Hub, and Dutch Title Transfer Facility futures likewise. Whenever that spread widens, US cargoes get pulled into the export channel and domestic prices firm.

The most recent widely available reference points for those benchmarks date to earlier in the year and should not be treated as current — international gas markets have moved substantially since, and readers should check live quotes rather than rely on stale weekly averages.

The Middle East escalation adds a second, distinct channel. Qatari LNG transits the Strait of Hormuz, which Iran has insisted on controlling unilaterally after rejecting Oman's shared-control proposal. A genuine Hormuz disruption would remove a substantial share of global LNG supply from the market simultaneously with the Ras Laffan damage.

That scenario would move Henry Hub. Nothing short of it will.

For now the market is pricing a domestic surplus and treating global tightening as a call option with no near-term expiry — which, given the feedgas data, is the correct assessment.

Weather Turned Against the Bulls and Renewables Made It Worse

The demand-side leg that had been supporting price failed in the last ten days, and it failed on two fronts.

The forecast picture deteriorated first. Prices were pressured by updated models pointing to cooler weather across the central and eastern US in coming weeks, reducing electricity demand for air conditioning. That reversal came after a genuinely hot stretch — one weather service had shifted hotter for July 27 through July 31 with above-normal temperatures across the central US, and forecasters were calling for widespread highs in the upper 80s to 100s with some 110-degree readings.

The broader seasonal outlook still leans warm. Temperatures are forecast to remain mostly above normal through August 8, which should keep gas demand from power generators elevated for cooling.

But warm is not the same as hot, and the market has been trading the second derivative.

The second failure is structural and it is the more important one. Natural gas-fired power generation slipped from a nearly one-year high during the latest storage week as wind and solar output increased. ERCOT power demand has been approaching record levels amid scorching heat, though rising wind generation is absorbing a growing share of it.

That is the mechanism that has broken the historical relationship between summer heat and gas prices. Record cooling demand no longer produces record gas burn, because renewable capacity additions are meeting the marginal megawatt-hour. Each successive summer, the heat threshold required to pull gas generation to record levels rises.

One hot run does not change the season. The central heat needs to hold into August and spread east for futures to build real follow-through. Without that, the market trades the same pattern it has been stuck in all summer — hot forecast lifts the bid, surplus and production bring sellers back.

That pattern has now repeated four times since June, and each iteration has produced a lower high.

The EIA Forecasts $3.70 for 2026 and the Market Is at $2.72

The gap between the official forecast and the traded price is the widest it has been this year, and it deserves attention.

The Short-Term Energy Outlook released July 7, with forecasts completed July 1, expects the Henry Hub spot price to average close to $3.70 per MMBtu in 2026 before declining below $3.50 next year. It specifically forecasts the fourth-quarter average at $3.57, which would be 5% below the same quarter last year.

Henry Hub currently trades at $2.72.

For a full-year average near $3.70 to hold with seven months of data already recorded at materially lower levels, the back half would need to run well above $4.00 — a scenario that requires either a supply disruption, a genuinely extreme winter, or an LNG demand surge that the feedgas data currently contradicts.

The agency's own reasoning acknowledges the pressure. It attributes the moderate downward pressure on prices to record US production helping meet rising demand, and expects inventories to remain above the five-year average through much of the forecast period, limiting upward price pressure.

The next outlook publishes August 11 and a downward revision to the 2026 average looks close to certain.

That said, the forecast is not obviously wrong on direction. The structural case for higher gas prices into 2027 rests on LNG export capacity additions outpacing production growth, and on data centre power demand adding a genuinely new load that did not exist in prior cycles. Neither is speculative — both are under construction.

The disagreement is about timing, and the market has voted for later.

Third-party modelling has been considerably more bearish still, with some short-horizon projections placing gas in the $2.46 to $2.51 range on one to three-month views. Those forecasts sit below the current price and below every technical support level, which is a reasonable expression of the momentum but not of the fundamentals.

Both extremes are probably wrong. The honest range for the rest of the injection season is narrower than either.

Producer Equities and the Trade That Is Not the Commodity

The equity complex attached to natural gas has been telling a different story from the futures curve, and the divergence is where the more interesting positioning sits.

Producers with Appalachian and Haynesville dry-gas exposure carry direct leverage to Henry Hub and have been marked down accordingly through the July decline. Their earnings power at $2.72 gas is materially different from their earnings power at the $3.70 the official forecast carries, and the equity market has been pricing somewhere in between — which is either an opportunity or a warning depending on where the strip settles.

The liquefaction and export names sit on the other side of the trade entirely. Their economics improve when domestic gas is cheap, because feedstock cost falls while contracted liquefaction fees hold. A supply glut that punishes producers subsidises exporters, and the current configuration — 111.2 Bcf/d of production against 17.2 Bcf/d of feedgas — is close to ideal for that business model.

Permian-weighted producers occupy a third position. Their gas is associated output from oil-directed drilling, which means Henry Hub weakness barely registers against $85 WTI. Waha basis at $1.811 against Henry Hub over $3 in June illustrates how little those volumes realise, and how little it matters to the parent economics.

The leveraged ETF products deserve a specific caution in a market like this. Daily-rebalancing instruments suffer severe decay in choppy, range-bound conditions, and natural gas has spent the entire summer in exactly that regime — a hot forecast lifts the bid, the surplus brings sellers back, repeat. Holding either direction through that pattern erodes capital regardless of whether the directional call was right.

The unleveraged tracking fund carries its own structural drag from contango roll costs, which have been persistent given the storage surplus.

For anyone expressing a view on gas over more than a few sessions, the producer equities and the export names offer cleaner exposure than the front-month contract, because they capture the structural story without paying the roll.

Forecast: $2.60–$2.98 Base Case, With $3.146 the Level That Changes the Trend

Three scenarios into August, with Thursday's storage print as the only near-term marker.

Base case, roughly 60% weight: Thursday's build lands near expectations and confirms the surplus trajectory toward 6.6% above the five-year average. Natural gas holds a $2.60 to $2.98 corridor through early August, with the broken support base at $2.801 to $2.857 acting as the first resistance and $2.974 — the April bottom — capping any recovery. Production stays above 110 Bcf/d, the rig count holds near 126, and LNG feedgas recovers only partially as Freeport maintenance concludes. Above-normal temperatures through August 8 support demand without producing the extreme heat required to draw storage. The same pattern that has held since June: a hot forecast lifts the bid, the surplus brings sellers back.

Bullish case, roughly 20% weight: a materially lean storage print stalls the surplus expansion, LNG feedgas recovers toward 18.5 Bcf/d as maintenance ends, and central heat holds into August while spreading east. Futures reclaim $2.801 and $2.857, re-enter the prior range, and challenge $2.974. Above that, the paired 50% levels at $3.089 and $3.121 come into play, capped by the 50-day moving average at $3.146. That level is the one that would genuinely change the trend — roughly 15% above spot and unreachable without both a demand surprise and a production stall. A Hormuz disruption that removes Qatari LNG from the global market is the tail that overrides everything.

Bearish case, roughly 20% weight: a build well above expectations, continued feedgas softness, and forecast models confirming the cooler central and eastern shift. Futures take out Tuesday's three-month low and work toward $2.60, then the $2.46 to $2.51 zone that short-horizon modelling already carries. Sustained trade below $2.50 would begin pressuring dry-gas producer cash costs — which is the only mechanism that produces a supply response, and it arrives in 2027 rather than this season.

Positioning framework: $2.801 decides whether Wednesday's bounce is real. $2.974 decides the month. $3.146 decides the trend. Below, $2.60 separates a range from a breakdown. Do not model a supply rescue — at 126 rigs and 111.2 Bcf/d, the bull case has to come from demand.

That's TradingNEWS