Henry Hub natural gas trades down to $2.40/MMBtu by October 30, 2026 in the base case, $2.10 in the bear case and $3.30 in the bull case, driven by a record end-of-injection-season storage build that the Energy Information Administration itself now forecasts at 3,985 Bcf.

Henry Hub spot settled at $2.79/MMBtu on August 11, 2026, the most recent daily print in the Energy Information Administration (EIA) series released on August 12, 2026. Working gas in Lower 48 storage stood at 3,153 Bcf on August 7, some 198 Bcf — 6.7% — above the five-year average, on an injection of 36 Bcf. The case below argues that surplus does not clear before the injection season ends, and that the shoulder-season trough prints a new 2026 low.

Key Levels:

• Asset: Henry Hub natural gas spot — $2.79/MMBtu on August 11, 2026 (EIA daily series, released August 12, 2026); NYMEX front-month settled $2.73/MMBtu on August 14, 2026
• Base case target: $2.40/MMBtu by October 30, 2026 — implied by an end-October inventory of 3,985 Bcf, 5% above the five-year average (EIA Short-Term Energy Outlook, August 11, 2026)
• Bull case target: $3.30/MMBtu — requires an early-October cold intrusion plus liquefied natural gas (LNG) feedgas sustained above 18.0 Bcf/d
• Bear case target: $2.10/MMBtu — requires a mild October and end-season inventories above 4,050 Bcf
• Major support: $2.54/MMBtu — the April 24, 2026 daily spot low, the weakest print of the year in the EIA series
• Major resistance: $3.03/MMBtu — the EIA’s own forecast average for the remaining five months of 2026
• Invalidation level: a full calendar week averaging above $3.10/MMBtu on the EIA daily spot series

Methodology: what this call is built on and where it can break

Price anchors come from two EIA series: the daily Henry Hub spot price (series RNGWHHD, last observation August 11, 2026, released August 12, 2026) and the Weekly Natural Gas Storage Report for the week ending August 7, 2026, released August 13, 2026 at 10:30 a.m. Eastern. Forward assumptions come from the August 2026 Short-Term Energy Outlook (STEO), published August 11, 2026. Supply and feedgas figures are cross-checked against the American Gas Association’s Natural Gas Market Indicators of August 7, 2026. Two caveats apply. First, EIA daily spot publishes with a lag of roughly one business day, so the anchor is not a live tick. Second, Henry Hub is a weather-levered instrument: the model below assumes ten-year normal degree days for September and October and has no skill against a genuine cold anomaly.

The data: a 198 Bcf cushion that heat could not dent

The defining feature of this injection season is that the surplus has survived one of the hotter late summers on record. Working gas rose to 3,153 Bcf in the week to August 7, 2026, a 36 Bcf net injection against a five-year average stock of 2,955 Bcf. Inventories are 25 Bcf below the year-ago level but 198 Bcf above the five-year norm, and the surplus is broad rather than regional: the Mountain region sits 14.4% above its five-year average and the Pacific 13.6%, while the Midwest is 7.1% ahead and the East 5.0%. That distribution matters because a surplus concentrated in South Central salt caverns can be worked off quickly by Gulf Coast demand, whereas a surplus spread across the East and Midwest has nowhere to go until winter withdrawals begin. Supply is the reason. Lower 48 dry gas production averaged 112.2 Bcf/d in July 2026, 3.9% above July 2025, with the year-to-date average at 111.1 Bcf/d, 4.3% higher than 2025. The EIA’s August STEO carries 111.19 Bcf/d for full-year 2026.

Variable	Latest reading	Prior period	Five-year average / year ago	Gap
Working gas (Bcf)	3,153 (Aug 7, 2026)	3,117 (Jul 31, 2026)	2,955 (2021–25 avg)	+198 Bcf (+6.7%)
Henry Hub spot ($/MMBtu)	2.79 (Aug 11, 2026)	2.56 (Aug 7, 2026)	2.54 (2026 low, Apr 24)	+0.25 vs 2026 low
Dry gas production (Bcf/d)	112.2 (Jul 2026)	111.1 (2026 YTD)	108.0 (Jul 2025 implied)	+3.9% y/y
LNG feedgas (Bcf/d)	17.4 (Jul 2026)	17.6 (Jun 2026 implied)	16.5 (3Q26 STEO forecast)	−1.2% m/m
Gas-directed rigs	127 (Aug 7, 2026)	588 total rigs	+48 rigs y/y	+8.9% y/y

Sources: EIA Weekly Natural Gas Storage Report (August 13, 2026); EIA daily Henry Hub spot series (August 12, 2026); EIA Short-Term Energy Outlook (August 11, 2026); American Gas Association Natural Gas Market Indicators (August 7, 2026). Time window: January 1 to August 14, 2026.

“The unfolding LNG wave is set to have a central role in shaping global gas markets in the coming years, likely putting downward pressure on prices and improving liquidity.”

— Keisuke Sadamori, Director of Energy Markets and Security, International Energy Agency (International Energy Agency)

The mechanism: export capacity is fixed, production is not

The bearish mechanism is a plumbing problem, not a demand problem. American gas demand including exports ran above 118 Bcf/d through July 2026, 2.5% ahead of the same period in 2025. That is genuine growth. But the marginal outlet for surplus Lower 48 gas is liquefaction capacity, and liquefaction capacity is a fixed physical asset that cannot flex with the storage balance. Feedgas to the nine major American export terminals averaged 17.4 Bcf/d in July 2026, a 1.2% decline from June, and the August STEO assumes just 16.5 Bcf/d for the third quarter as terminals take maintenance outages. Production, by contrast, is not fixed: it rose 3.9% year on year in July with only 127 gas-directed rigs running. When the incremental molecule cannot be exported and cannot be burned, it goes into the ground, and the EIA now expects that process to end with a record 3,985 Bcf on October 31, 2026 — 5% above the five-year average.

Steelmanning the other side: the international price signal is loud. The Middle East conflict has kept Asian and European spot benchmarks far above American prices, and a wide Henry Hub-to-JKM spread is exactly the condition under which every available cargo gets lifted — the same dynamic driving the residual risk premium in Brent. If feedgas were unconstrained, that arbitrage would drain the surplus. The bull case therefore rests on whether new liquefaction trains can ramp faster than the STEO assumes between now and October — a question about commissioning schedules, not about price.

What the model misses

Three limits deserve naming. First, this framework has no skill against weather tails, and 2026 proves the point: the same EIA daily series that printed $2.56 on August 7 printed $30.72 on January 23, 2026 during the winter freeze. A shoulder-season call is a call about the median outcome, not the distribution. Second, the supply response bears normally rely on is not coming, because producers are already profitable here — EQT Corporation generated $330 million of free cash flow in the second quarter of 2026 on an average realised price of $2.89/MMBtu, below the level this call targets. Third, the analogue cuts both ways: a correct October call can look foolish by February. This is a 75-day view with a hard stop, not a structural thesis about American gas.

“I’d say what’s changed over the last three months, certainly our view coming into this pre-Iran war was that 2028, 2029 was going to be a little bit oversupplied. I think that’s gone away with Iran.”

— Toby Rice, President and Chief Executive Officer, EQT Corporation, second-quarter 2026 earnings call, July 22, 2026 (Investing.com transcript)

Rice is the sharpest counter-voice available, and he is worth reading precisely — his tightening argument is aimed at 2028 and 2029, not at October 2026. That distinction is the whole call. A structural bull case built on LNG trains that reach full rates two years from now says nothing about a storage cushion that has to be absorbed in the next eleven weeks.

What would invalidate this call

The base case to $2.40/MMBtu breaks if any one of these four signals fires:

• Three consecutive weekly injections below the five-year average, cutting the surplus under 120 Bcf before October 1. The entire thesis is the 198 Bcf cushion; a surplus that narrows that fast implies demand is running well above the STEO’s assumptions.
• LNG feedgas sustains above 18.0 Bcf/d for two consecutive weeks. That is more than 1.5 Bcf/d above the STEO’s 16.5 Bcf/d third-quarter assumption and would remove roughly 100 Bcf from the injection season, closing half the surplus without any weather help.
• Lower 48 dry gas production falls below 109 Bcf/d on a fourteen-day average. Production above 111 Bcf/d is the supply leg of the call; a genuine 3 Bcf/d decline would change the balance faster than storage can be filled.
• Henry Hub posts a full calendar week averaging above $3.10/MMBtu. That clears the EIA’s own $3.03 remaining-2026 forecast and signals the market has repriced the winter risk premium forward.

What to watch next

The Weekly Natural Gas Storage Report lands every Thursday at 10:30 a.m. Eastern, with the next release on August 20, 2026 — the injection number relative to the five-year average is the single highest-frequency read on this call. The September STEO, due in early September 2026, will update the end-October inventory forecast from 3,985 Bcf; a revision higher pulls the target toward the $2.10 bear case, a revision below 3,900 Bcf argues for patience. Baker Hughes publishes its rig count each Friday; a gas-directed count moving above 140 would confirm the supply leg. On the tape, $2.54 is the level that matters: the base case requires a decisive break of the 2026 low, and repeated failures there would argue the surplus is already in the price.

FAQ

What is the current Henry Hub natural gas price?

Henry Hub spot was $2.79/MMBtu on August 11, 2026, the latest observation in the EIA daily series released on August 12, 2026. The NYMEX front-month contract settled at $2.73/MMBtu on August 14, 2026. Both sit above the 2026 low of $2.54/MMBtu set on April 24, 2026, and well below the $3.34/MMBtu high recorded in the week to July 3, 2026.

How much natural gas is in American storage right now?

Working gas in Lower 48 underground storage totalled 3,153 Bcf as of August 7, 2026, following a 36 Bcf net injection. That is 198 Bcf, or 6.7%, above the 2021–25 five-year average of 2,955 Bcf, and 25 Bcf below the year-earlier level. The EIA forecasts a record 3,985 Bcf at the close of the injection season on October 31, 2026.

Why are American gas prices so much lower than international benchmarks?

Because export capacity is a physical constraint. Lower 48 production has grown 3.9% year on year, but liquefaction terminals can only lift a fixed volume — feedgas averaged 17.4 Bcf/d in July 2026 and the EIA assumes 16.5 Bcf/d for the third quarter. Surplus molecules that cannot be liquefied cannot reach the higher-priced Asian and European markets, so they go into storage instead.

What does the EIA forecast for natural gas prices?

The August 2026 Short-Term Energy Outlook puts the Henry Hub spot price at $2.87/MMBtu for the third quarter of 2026 — a 50-cent downgrade from the prior edition — and $3.03/MMBtu across the remaining five months of the year. The full-year 2026 average is $3.44/MMBtu, easing to $3.31/MMBtu in 2027 as production climbs to 116.04 Bcf/d.

What would make this bearish call wrong?

Four things: three consecutive below-average weekly injections cutting the surplus under 120 Bcf, LNG feedgas holding above 18.0 Bcf/d for two weeks, Lower 48 production falling under 109 Bcf/d on a fourteen-day average, or a full calendar week averaging above $3.10/MMBtu on Henry Hub spot. Any one of those would break the storage-surplus mechanism the call rests on.

How does this compare with previous coverage?

An earlier analysis argued Henry Hub could reach $3.20 by the end of the third quarter. The storage data published since has moved the other way: the surplus widened, and the EIA cut its own third-quarter forecast by 50 cents. Adjacent calls on the WTI Hormuz premium fade and dollar repricing share the same macro backdrop. Primary data: the EIA natural gas hub and AGA market indicators.

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