Hormuz LNG Flows Collapsed 95% and US Gas Still Trades Under $3 — 94% Terminal Utilization Is Why

September Henry Hub futures surged nearly 5% Monday morning after the contract broke above a monthlong technical pattern that had constrained its upside, putting the $3.00/MMBtu level in view. The contract had settled near $2.726 in the prior session against a previous close of $2.670, trading a $2.702 to $2.746 range. Weekend weather models added heat to the two-week outlook, and strong power-sector demand plus rising LNG feedgas provided additional support after five consecutive weeks of losses.

The move comes with a warning attached. Storage surpluses and heavy speculative short positioning raise legitimate questions about the durability of the advance. The 52-week low sits at $2.483, and over the past twelve months the contract has declined 7.72%.

The forecast here rests on the most counterintuitive fact in energy markets right now. LNG exports through the Strait of Hormuz have collapsed by approximately 95% — one of the most acute supply shocks in the history of global gas markets — and U.S. natural gas trades below $3.

That is not a market failure. It is a capacity constraint, and it is the single most important thing to understand about this contract.

The closure has affected over 10 billion cubic feet per day of global LNG supply, roughly 20% of the world total, mostly from Qatar's Ras Laffan facility. Qatar exported about 9.3 Bcf/d through the strait in 2024 and the UAE about 0.7 Bcf/d. The IEA calculates the disruption has removed over 300 million cubic metres per day since March 1 — a loss exceeding 2 billion cubic metres every week.

America cannot capture it. U.S. LNG terminals were already running at 94% of maximum approved export levels in March, exporting 17.9 Bcf/d against a December 2025 record of 18.4 Bcf/d. Operators run those terminals at high utilisation rates, which limits additional export growth and in turn limits the potential for significant price increases in the domestic market.

U.S. gas is cheap because it cannot get out. Everything below develops that thesis, including what changes when 2.4 Bcf/d of new capacity arrives.

Today's 5% Move Is Weather and Short-Covering, Not Geopolitics

Separating the drivers of Monday's advance matters because it determines whether the move holds.

The mechanics were technical and meteorological. Two-week weather forecasts trended meaningfully hotter over the weekend, and the September contract snapped out of a multiweek malaise to mount double-digit gains through midday. The break above a monthlong pattern that had capped the contract is what turned a weather-driven bid into a 5% session, because pattern breaks force positioning changes independent of fundamentals.

The positioning is where the fuel came from. Heavy speculative short positioning was in place going into the weekend after five consecutive weeks of losses. A market that has fallen for five straight weeks accumulates crowded shorts, and crowded shorts covering into a technical breakout produce exactly the kind of move that looks like conviction and is actually mechanics.

Note what did not drive it. The Hormuz escalation over the weekend — Iran reiterating six conditions, the Houthi strike on Saudi Aramco's Jazan refinery, both crude benchmarks reversing last week's 7% decline — sent WTI to $80.90 and Brent near $85. European TTF has previously jumped over 3% on comparable headlines. Henry Hub's response to the same news set was contained within a domestic weather story.

That divergence is the structural point. When the strait first closed, U.S. natural gas remained largely insulated from the overseas supply shock because domestic export terminals were already operating near full capacity. That insulation has held for five months.

The supporting demand factors are real but seasonal. Strong power-sector demand and rising LNG feedgas both contributed, and prior heatwave episodes have shown domestic demand jumping to three-month highs when air-conditioning load surges across two-thirds of the country. Those are weather variables that reverse when forecasts cool.

The forecast implication: treat $3.00 as the level that tests whether this is a breakout or a squeeze. A 5% move off crowded shorts into a technical break with a hotter two-week outlook is a tradeable rally. It is not a re-rating, and the storage picture below explains why.

The 33 Bcf Injection Confirmed Supplies Remain Ample

The fundamental counterweight to Monday's rally arrived last Thursday and it was bearish.

The EIA reported a 33 Bcf net injection into storage for the week ended July 31, landing on the heavier side of expectations. Futures slipped on the release, reinforcing the market's view that supplies remain ample despite easing production and strengthening LNG feedgas demand. Going into that report, the framing on the desk was explicitly about whether the data could reverse bearish momentum. It did not.

An injection during peak summer cooling season is the signal that matters. Late July should be the period when air-conditioning load consumes gas faster than producers can refill inventory. Adding 33 Bcf in that window says production is running well ahead of even peak seasonal demand.

Production supports that read. Lower-48 dry gas output has been running near 110 Bcf/d, up roughly 1.8% year-over-year. The EIA's January outlook forecast supply growth outpacing demand growth by 0.5 Bcf/d across 2026, with demand including exports increasing by less than 1% at +0.6 Bcf/d while supply including imports rose nearly 1% at +1.1 Bcf/d. More output was projected from the Permian, Haynesville and Appalachia, and management teams at the Permian's leading gas midstream firms have expressed a resoundingly bullish tone on the play's growth prospects this earnings season.

The regional pricing tells the same story more starkly. NGI's Waha daily price in the Permian has been holding steady above zero with an average of $1.595/MMBtu since June 15, enabled by added pipeline takeaway that can move more gas to demand centres. Waha at $1.595 against Henry Hub near $2.86 is a $1.27 basis differential, and the fact that holding above zero counts as an achievement tells you how much associated gas the Permian is producing.

Midwest physical prices pulled back notably early this month amid strong supply, breaks in summer heat and forecasts for a mild shoulder season ahead.

So the fundamental setup into Monday's rally was: heavier-than-expected injection, production near 110 Bcf/d, a storage surplus, weak regional basis and a mild shoulder season in the forecast. That is why the durability question is legitimate.

Why a 95% Collapse in Hormuz LNG Cannot Lift Henry Hub

This is the mechanism that defines the entire domestic forecast, and it deserves the numbers in sequence.

LNG exports through the Strait of Hormuz have collapsed by approximately 95% since U.S. and Israeli military operations against Iran began in late February 2026. In 2024, about 20% of global LNG trade transited the strait, with Qatar exporting roughly 9.3 Bcf/d and the UAE about 0.7 Bcf/d — nearly all Persian Gulf LNG flows. QatarEnergy declared force majeure on March 4. No laden LNG vessels are known to have crossed the strait between March 1 and April 24 according to Kpler tracking. Qatar's Transport Ministry issued a blanket suspension of maritime activity at one point, the first by a Gulf state during the conflict, with direct implications for Ras Laffan flows.

The obvious inference is that U.S. producers should be capturing that volume at premium prices. They cannot, and the reason is arithmetic.

The United States exported an estimated 17.9 Bcf/d of LNG in March, the second-highest monthly volume after December 2025's record 18.4 Bcf/d, at 94% of maximum DOE-approved export capacity. February ran 17.3 Bcf/d at 91% utilisation. The EIA's assessment is direct: operators already run U.S. LNG terminals at high utilisation rates, limiting additional export growth, which in turn limits the potential for significant price increases in the domestic market.

At 94% utilisation there is 1.1 Bcf/d of headroom against a 10 Bcf/d global shortfall. The Department of Energy has approved two incremental authorisations since February — Plaquemines LNG at 0.5 Bcf/d in March and Elba Island at 0.1 Bcf/d in April. That is 0.6 Bcf/d against 10.

The supply gap was filled elsewhere. The IEA calculates that around three-quarters of the losses since the beginning of March have been offset by a very strong increase in LNG supply from other producing regions. Asian buyers who import over 80% of Qatari gas were forced to compete for spot cargoes globally, and other suppliers responded.

So the shock was absorbed by non-U.S. producers with spare liquefaction capacity, while American gas stayed domestic and cheap. That is the structural reason Henry Hub sits near $2.86 with a 52-week low of $2.483 while the global market experiences its most acute supply disruption on record.

The 2.4 Bcf/d That Changes the Equation Between Now and December

The insulation has an expiry date, and it is the most important forward variable in this forecast.

The EIA expects approximately 2.4 Bcf/d of DOE-authorised export capacity to come online between April and December 2026 — Golden Pass Trains 1 and 2, plus Corpus Christi Stage 3 Trains 5 through 7. LNG exports are forecast to grow 9%, or 1.3 Bcf/d, in 2026 and a further 11%, or 1.7 Bcf/d, in 2027, driven by the ramp-up of three new facilities: Plaquemines LNG, Corpus Christi Stage 3 and Golden Pass.

Work through what that does to the balance.

The capacity constraint currently caps U.S. export growth at roughly 1.1 Bcf/d of spare terminal headroom. Adding 2.4 Bcf/d more than triples the available outlet. And the demand for that capacity is not speculative — it is a global market short 10 Bcf/d with Asian buyers paying spot premiums to replace Qatari contract volumes that remain under force majeure.

The EIA's own forecast captures the consequence. Henry Hub is expected to decrease about 2% to just under $3.50/MMBtu in 2026 before rising sharply to just under $4.60/MMBtu in 2027 — an increase of 33%. The driver is stated plainly: forecast supply growth outpaces demand growth by 0.5 Bcf/d in 2026 but then falls behind by 1.6 Bcf/d in 2027, putting upward pressure on prices. Demand growth of 2.5 Bcf/d in 2027 exceeds supply growth of 0.9 Bcf/d, driven mainly by feed gas demand from LNG export facilities, reducing storage.

That is a domestic market transitioning from surplus to deficit on export capacity alone.

The forward curve has been pricing seasonality rather than that structural shift. As of mid-March the strip showed April 2026 near $3.03, July near $3.43, November near $3.86, December near $4.70 and January 2027 near $5.10. That shape points to softer spring pricing, firmer summer demand and a clear winter premium — the market pricing seasonality more than a continuous shortage.

The trade in this market is not the front month. It is the 2027 strip against a Henry Hub forecast of $4.60 and a 1.6 Bcf/d structural deficit.

Tomorrow's EIA Outlook Is the Week's Real Event

A scheduled release deserves attention because the agency's price assumptions have already been overtaken by events once this year.

The EIA's next Short-Term Energy Outlook publishes August 11. Its January edition forecast Henry Hub decreasing about 2% to just under $3.50/MMBtu in 2026. The March edition revised that upward, projecting an average of $3.76/MMBtu for 2026 against $3.53 in 2025, with actual monthly figures of $7.72 in January and $3.62 in February.

Note the spread between those two forecasts and current price. January's outlook said just under $3.50, March's said $3.76, and the September contract is trading near $2.86 after touching a 52-week low of $2.483. The agency's full-year averages are being carried by a January spot spike to $7.72 that will not repeat, while the balance of the year has traded materially below both projections.

That matters because the same outlook will contain the agency's revised crude assumptions. Its July edition, completed on July 1, projected Brent averaging $74 in the third quarter on the assumption that the June 18 U.S.-Iran memorandum of understanding would reopen the strait. Brent trades near $84. Tomorrow's release is the first official revision incorporating the July re-escalation, and the gas assumptions rest on the same geopolitical premise.

The specific line to watch is whether the agency maintains its expectation that most crude production returns to near pre-conflict averages by year-end and that the majority of shut-in production comes back online in the first quarter of 2027. If it pushes those dates out, the LNG demand assumptions supporting the 2027 Henry Hub forecast of $4.60 get stronger, not weaker — because a longer Qatari outage means more sustained global demand for the 2.4 Bcf/d of new U.S. capacity.

The complication is that the same outlook will likely acknowledge the storage surplus and near-record production that produced last week's 33 Bcf injection.

Thursday's weekly storage report at 10:30 a.m. ET is the second scheduled event, and after a heavier-than-expected 33 Bcf build, another above-consensus injection would test Monday's breakout directly.

European Inventories Are Lagging and That Is the Bullish Tail

The one genuinely bullish structural datapoint for U.S. gas sits across the Atlantic and it is deteriorating.

European Union natural gas inventories continue to lag historical levels as summer nears an end and supply disruptions caused by the Iran war persist. Europe's gas market remains exposed to price volatility in the refilling season, which could prove more difficult and much more expensive to complete before the coming winter, because Asia now attracts the bulk of spot LNG supply.

Understand why that is the transmission channel. Europe fills storage during summer using LNG cargoes purchased on the spot market. Asian buyers replacing Qatari contract volumes under force majeure are bidding for the same cargoes, and 83% of Hormuz LNG went to Asia in 2024 with China, India and South Korea accounting for 52% of those flows. Asia's price advantage for flexible U.S. LNG has been preserved by hot weather across South Korea and northeast China.

So European storage enters winter below normal, into a market where Asia outbids it for marginal cargoes.

That creates a specific mechanism for a Henry Hub squeeze. If Europe arrives at November with inventories materially below the five-year average, it must bid aggressively for winter cargoes. Every cargo diverted from Asia to Europe raises the price both regions pay, and U.S. terminals — which will by then have Golden Pass and Corpus Christi Stage 3 capacity available — become the marginal supplier to both. Feed gas demand at those terminals draws directly on Henry Hub supply.

The curve already prices some of this: November near $3.86, December near $4.70, January 2027 near $5.10. The most plausible support for higher prices comes from winter seasonality and LNG demand rather than from sustained tightness across the whole year.

The counterweight is domestic weather. An El Niño winter ahead adds a bearish wrinkle, and a mild North American heating season would leave U.S. storage comfortable regardless of what Europe does.

That is the genuine two-sided setup for the winter strip: European scarcity and 2.4 Bcf/d of new export capacity against El Niño and 110 Bcf/d of domestic production.

The Industry Is Positioning for Elevated Prices Through 2030

Corporate behaviour is the most informative signal available on the medium-term outlook, because capital commitments reveal what management teams actually believe.

NextDecade's chief executive told analysts that the prolonged closure of the Strait of Hormuz has shifted the outlook of the global LNG market, keeping spot prices elevated through the end of the decade. That is an LNG developer making a decade-long call on structurally higher pricing, and it is the kind of statement that underwrites final investment decisions on multi-billion-dollar liquefaction trains.

Permian midstream firms have expressed a resoundingly bullish tone on the play's growth prospects this earnings season. That is the gathering and processing layer committing capital to move more associated gas to demand centres, and added Permian takeaway is precisely what has allowed Waha to hold above zero at an average of $1.595/MMBtu since June 15.

Upstream, Gulfport Energy's new chief executive launched a discretionary acreage acquisition programme committing $140 million to bolt-on assets in Ohio, aiming to grow its Utica Shale footprint through the remainder of 2026.

Read those three together and the industry is investing across the full chain — resource acquisition, midstream takeaway and liquefaction — on the assumption that global demand absorbs the volume at prices well above $2.86.

The bearish reading of the same evidence is straightforward and should not be dismissed. The single biggest bearish risk is higher-than-expected supply growth, and the agency specifically predicts more output from the Permian, Haynesville and Appalachia. Every dollar of Permian midstream capex and every acre Gulfport adds in the Utica increases the supply that has to clear before price advances. The industry investing into an expected bull market is how bull markets get capped.

The regional discount reinforces it. Western Canadian forward prices remain at a steep discount to Henry Hub even as structural demand drivers appear on the horizon, which is what a continent with abundant stranded supply looks like.

For the forecast: producer behaviour supports the 2027 case and simultaneously explains why 2026 has been a $2.48 to $3.50 market.

Speculative Short Positioning Is the Fuel and the Risk

Positioning deserves specific treatment because it explains both Monday's magnitude and the fragility beneath it.

Heavy speculative short positioning was in place going into this week, raising questions about the durability of the advance alongside storage surpluses. Those shorts accumulated across five consecutive weeks of losses, during which September futures fell toward a 52-week low of $2.483 and the twelve-month change reached negative 7.72%.

The mechanics of a crowded short in natural gas are worth spelling out. Speculators short the contract on bearish fundamentals — near-record production, heavy injections, mild forecasts. As price falls, the position becomes profitable and more participants join. That builds a concentration of one-directional risk. When a technical level breaks upward, stop-losses trigger in sequence, and each covering trade lifts price into the next stop cluster.

That is a mechanically precise description of what happened Monday morning. September broke above a monthlong pattern, and the gain reached nearly 5% within hours.

Two implications for positioning.

First, the move can extend further than fundamentals justify. With $3.00 in view and shorts still being squeezed, the contract can trade through the round number on momentum alone. Squeezes routinely overshoot by 10% to 15% beyond what the physical market supports.

Second, squeezes have no fundamental floor. Once the shorts have covered, the buying stops. If Thursday's storage report delivers another heavy injection, the contract retraces the entire move because the bid that produced it was mechanical rather than economic. The fundamentals that created the short position — 110 Bcf/d of production, a storage surplus, Waha at $1.595, El Niño winter — have not changed since Friday.

The tell is volume and follow-through. A close above $3.00 with sustained volume through Tuesday and Wednesday indicates fresh long positioning rather than covering. A fade back below $2.80 before Thursday means it was mechanics.

Trading discipline here: do not chase 5% into a round number on a squeeze. The reward is in fading strength that fails at $3.00 or in owning the 2027 strip where the structural case lives.

The Seasonal Calendar Works Against Bulls for Six More Weeks

Timing matters enormously in this market and the calendar is unfavourable near-term.

August is the tail of cooling season. Forecasts have pointed to a mild shoulder season ahead, and Midwest physical prices already pulled back notably early this month on strong supply and breaks in summer heat. Commodity Weather Group has repeatedly flagged cooler trends in the eastern half of the country as the driver of failed rallies, and cooler overnight forecast trends with abundant supply extinguished early-week momentum on prior attempts.

Shoulder season — roughly mid-September through late October — is structurally the weakest period for gas demand. Cooling load collapses and heating load has not started. Storage injections continue, and with production near 110 Bcf/d and a surplus already in place, that period is where the bearish case has its cleanest run.

The seasonal curve reflects it. November priced near $3.86 against July near $3.43 and April near $3.03 shows the market expects the trough before the winter premium.

Two offsetting factors deserve weight.

Hurricane season is in full swing and affects Gulf natural gas supply. Lower storage injections from production disruptions provide bullish fuel, and a storm track through Gulf production and LNG terminal areas can move this contract sharply in either direction — shutting production is bullish, shutting export terminals is bearish. Approaching typhoon activity in Asia has separately complicated the near-term shipping outlook for LNG cargoes.

LNG feedgas demand is rising and is a structural rather than seasonal input. Feedgas has been strengthening alongside easing production, and as Golden Pass and Corpus Christi Stage 3 trains commission through December, that demand grows regardless of weather.

The synthesis: the six weeks from mid-September carry the greatest downside risk in this contract, and the six weeks after that carry the greatest upside. Monday's rally arrives in the window before the weakest seasonal stretch, which is another reason to treat it as tactical.

The Basis Story: Waha at $1.595 Tells You Where Supply Is

Regional pricing is the most honest fundamental indicator in gas markets and it currently reads bearish.

NGI's Waha daily price in the Permian has held steady above zero with an average of $1.595/MMBtu since June 15, enabled by added pipeline takeaway that can move more gas to demand centres. Physical prices diverged Friday, with New England and California posting the session's strongest gains while benchmark Henry Hub weakened. On another recent session, sharp gains across the Northeast, Appalachia and East Coast pipeline corridors outweighed weakness in parts of California. Western Canadian forwards remain at a steep discount to Henry Hub.

Take Waha first. Permian associated gas is produced as a byproduct of oil drilling, so it arrives regardless of gas prices — producers drill for crude at $80 WTI and the gas comes with it. When takeaway capacity is insufficient, Waha prices go negative because producers pay to dispose of it. The fact that holding above zero at $1.595 counts as an improvement, achieved specifically through added pipeline capacity, tells you the Permian is generating gas faster than the market can absorb it.

That matters directly for Henry Hub. New takeaway capacity that moves Permian gas to demand centres is new supply arriving at the benchmark. The $1.27 basis between Waha and a $2.86 Henry Hub is the incentive to keep moving it.

The regional divergences — Northeast and East Coast strength, California weakness — are weather and constraint effects rather than national signals. New England and California trade at premiums because of pipeline limitations into those markets, not because national supply is tight.

Western Canada at a steep discount adds another supply source waiting on infrastructure, with structural demand drivers appearing on the horizon but not yet operative.

For the forecast, the basis picture argues that the domestic supply overhang is real and geographically distributed. It is not a single-basin phenomenon that resolves with one pipeline. Permian associated gas, Appalachian dry gas, Haynesville and Western Canada all have volume waiting for outlets, and the EIA's forecast of supply growth outpacing demand by 0.5 Bcf/d across 2026 is the aggregate of that.

Henry Hub cannot sustain a move above $3.50 while Waha trades at $1.595.

What the Curve Is Actually Pricing and Where the Mispricing Sits

Comparing the forward curve against the fundamental forecast identifies where the value is, and it is not in the front month.

The mid-March strip showed April 2026 near $3.03, July near $3.43, November near $3.86, December near $4.70 and January 2027 near $5.10. That shape reflects seasonality more than a continuous shortage — softer spring, firmer summer, clear winter premium. If traders expected a much tighter market throughout the year, the front end would be stronger.

Against that, the fundamental forecast for 2027 is a Henry Hub average just under $4.60/MMBtu, up 33%, driven by demand growth of 2.5 Bcf/d against supply growth of 0.9 Bcf/d — a 1.6 Bcf/d deficit created principally by LNG feed gas demand drawing down storage.

Now overlay the geopolitics. The Hormuz closure has removed 20% of global LNG trade and over 300 million cubic metres per day of Qatari and UAE supply. Iran's six conditions for reopening — ending the war, lifting the U.S. counterblockade, ending sanctions, releasing frozen assets, compensation, plus retaining control of the waterway and charging tolls — are structurally incompatible with Washington's insistence on unrestricted navigation without Iranian approvals or tolls. Direct talks are not occurring. An LNG developer's chief executive expects the shift to keep spot prices elevated through the end of the decade.

The mispricing follows. The front month is fairly valued or expensive at $2.86 given 110 Bcf/d of production, a storage surplus, Waha at $1.595 and a mild shoulder season approaching. The 2027 strip is arguably cheap against a $4.60 forecast, a 1.6 Bcf/d structural deficit, 2.4 Bcf/d of new export capacity commissioning, European inventories lagging into winter, and a global LNG market that may stay 10 Bcf/d short indefinitely.

That is a calendar spread rather than a directional trade. Short the front, long the deferred, and let the export capacity ramp close the gap.

The risk to it is a Hormuz reopening. Qatar restoring 9.3 Bcf/d floods the global market, collapses Asian spot premiums, removes the pull on U.S. cargoes and takes the 2027 case with it. That is the single scenario that invalidates the structure.

Levels, Scenarios and What to Watch This Week

The forecast resolves into three paths with defined triggers.

Base case, roughly 50%: Monday's squeeze fails at or just above $3.00 and September retraces into the $2.70 to $2.90 band. Thursday's storage report delivers another injection near or above consensus following the 33 Bcf build for the week ended July 31, weather forecasts cool from the current hotter trend, and production near 110 Bcf/d with Waha at $1.595 caps the advance. The contract trades $2.65 to $3.00 into shoulder season, with the 52-week low of $2.483 as the structural floor.

Bull case, roughly 30%: the technical break holds. September closes above $3.00 with volume confirmation, the two-week heat persists, LNG feedgas continues strengthening as Golden Pass and Corpus Christi Stage 3 trains commission, and the remaining speculative shorts capitulate. That opens $3.20 and then $3.43 — the level the curve had assigned to July. Sustained European inventory concern into the refilling season alongside a hurricane disrupting Gulf production would extend it toward the $3.86 November strip level. Tomorrow's EIA outlook pushing Qatari restoration dates further out supports this path.

Bear case, roughly 20%: the squeeze exhausts and shoulder season arrives with a surplus. September loses $2.70, then $2.60, and retests $2.483. An El Niño winter forecast firming through September, another heavy injection Thursday, and confirmation of a mild shoulder season would take the contract to new lows. A credible Hormuz reopening — Iran and Oman finalising transit lanes with U.S. acquiescence — collapses Asian spot premiums and removes the LNG demand pull entirely, which is the scenario that breaks $2.48 decisively.

Watch list, in order: Thursday's storage report at 10:30 a.m. ET, and whether it beats or misses the 33 Bcf prior build. Tomorrow's EIA Short-Term Energy Outlook and its revised Qatari restoration assumptions. Whether September holds above $3.00 with volume. Two-week weather model trends. LNG feedgas volumes as Golden Pass Trains 1-2 and Corpus Christi Stage 3 commission. EU storage fill rates against the five-year average. Hurricane tracks through Gulf production and terminal areas. Waha basis relative to Henry Hub.

Discipline: $3.00 is the line that separates a squeeze from a breakout, and $2.483 is the floor. Do not chase Monday's 5% — the position with an actual structural edge is long the 2027 strip against a $4.60 forecast and a 1.6 Bcf/d deficit, not long the front month into shoulder season.

That's TradingNEWS