What is the H2 2026 Henry Hub price forecast?

The EIA's May 2026 STEO forecasts Henry Hub averaging about $3.50/MMBtu for full-year 2026. Quarterly guidance points to ~$3.26/MMBtu in Q3 and ~$4.28/MMBtu in Q4 as winter heating demand returns. Our base case is $3.00–3.50 for Q3, $3.50–4.50 for Q4. A bull case above $5 requires an extreme winter event or sustained LNG supply disruption, while a bear case below $2.50 would need record production growth coinciding with a mild winter.

Will the US natural gas market be in surplus or deficit in H2 2026?

The market is broadly balanced. EIA projects Lower-48 marketed production at 118.9 Bcf/d in 2026, up 3% year-over-year, driven by associated gas from the Permian. LNG exports are the marginal demand driver at ~16.7 Bcf/d, essentially running at full capacity. Storage is forecast to end October at 7% above the five-year average — a comfortable buffer, but not enough to prevent price spikes during extreme cold.

How will LNG export growth affect Henry Hub in H2 2026?

LNG feedgas demand is the single largest source of demand growth in the US gas market, projected at 16.7 Bcf/d in 2026 (up from 15.1 Bcf/d in 2025). Plaquemines LNG and Corpus Christi Stage 3 are ramping, and Golden Pass LNG is expected to begin operations in 2026. US LNG terminal utilization is near maximum capacity. The Strait of Hormuz disruption has widened TTF-Henry Hub spreads, making US exports even more attractive.

How does the Iran conflict affect the US natural gas market?

The Strait of Hormuz disruption has directly reduced global LNG supply, sharply widening the spread between Henry Hub and European/Asian import prices. This makes US LNG cargoes more valuable and pulls incremental feedgas demand into export terminals. While Henry Hub itself is insulated from direct supply disruption, the indirect effect is stronger LNG demand that tightens the US balance in H2 2026.

What is the storage outlook entering winter 2026-27?

EIA forecasts storage to end the injection season on October 31 at 7% above the five-year (2021-25) average. This is a moderate buffer — sufficient to anchor prices and reduce volatility risk in the base case, but not so large that a cold snap can't burn through it quickly. In January 2026, Winter Storm Fern erased what had been a comfortable surplus in a matter of weeks.

Natural Gas H2 2026: Balanced Market, But LNG and Weather Hold the Key

Q: What are the key risks to the natural gas outlook in H2 2026?

Three risks dominate. First, weather: Winter Storm Fern erased a storage surplus in January 2026, forcing EIA to raise its annual price forecast 40% overnight. Second, geopolitical: the Iran conflict and Strait of Hormuz disruption have reduced global LNG supply, and any escalation would widen Atlantic Basin spreads. Third, production surprises: Permian associated gas is sensitive to WTI prices, and a sustained drop below $65/bbl would slow associated gas output.

The US natural gas market enters H2 2026 in a state of uneasy equilibrium — rising production at 118.9 Bcf/d meets surging LNG demand at 16.7 Bcf/d, with storage on track to end injection season 7% above the five-year average. But equilibrium is fragile: the asymmetric risk to the upside was proven by Winter Storm Fern, which erased a storage surplus and raised annual price forecasts 40% in a single STEO revision. Our base case: Henry Hub at $3.00–4.50 in H2 2026, with the bull case above $5 requiring just one catalyst.

Price Outlook: Base, Bull, Bear

Scenario	Q3 2026	Q4 2026	Key Driver
Bear	$2.50–3.00	$2.75–3.25	Record production growth, mild winter, full LNG flow restoration
Base	$3.00–3.50	$3.50–4.50	Rising supply matching LNG + power demand; normal weather cadence
Bull	$3.75–4.50	$4.50–6.00	Harsh winter, Hormuz escalation, LNG terminal outages

ESTIMATE: Rzzro base case aligns with the EIA trajectory — Q3 averaging $3.00–3.50 as injections keep pace, Q4 rising to $3.50–4.50 as winter demand and LNG exports tighten the balance. The bull case is where past precedent (Winter Storm Fern, 2021 Texas freeze) shows that tail risks in natural gas are real and large.

Supply: Permian Growth as the Anchor

Lower-48 marketed production averaged 117.2 Bcf/d in Q1 2026, up 4% year-over-year. EIA projects steady growth through H2, averaging 118.9 Bcf/d for 2026 and rising to 124.0 Bcf/d in 2027.

The growth is driven disproportionately by associated gas from the Permian Basin, sustained by elevated crude oil prices. Key structural factors:

Rising GORs: Wells in the Permian are producing increasing gas-to-oil ratios, meaning even flat oil-directed drilling yields more associated gas over time. EIA increased its production forecast by 1% in the May STEO versus April, citing exactly this trend.
Haynesville: The pure-play dry gas basin is running near current capacity but showing marginal decline without a sustained price above $3.50 to justify incremental drilling.
Appalachia: Takeaway constraints persist, capping Marcellus/Utica growth to ~1–2 Bcf/d annually, mostly via new pipeline capacity into the Southeast.

FACT: EIA increased its marketed production forecast by 1% in the May STEO versus the April outlook, citing rising gas-to-oil ratios in the Permian — a structural trend, not a one-time revision.

Demand: LNG Is the Marginal Driver

US natural gas demand splits into three categories: power generation, industrial/residential/commercial, and LNG exports. Each has a different trajectory in H2 2026.

LNG Exports — The Structural Bull

LNG gross exports are forecast at 16.7 Bcf/d in 2026, up from 15.1 Bcf/d in 2025 and the largest single source of demand growth. Three facilities define the ramp:

Plaquemines LNG (Venture Global): Continuing commissioning ramp toward full 2.0 Bcf/d nameplate capacity
Corpus Christi Stage 3 (Cheniere): ~1.5 Bcf/d of additional liquefaction capacity reaching full operations
Golden Pass LNG (ExxonMobil/QatarEnergy): Expected to begin operations in 2026, adding ~0.5–1.0 Bcf/d by year-end

The Strait of Hormuz disruption has created extraordinary TTF-Henry Hub spreads. One US export terminal operator is reportedly deferring planned maintenance to maximize throughput — a strong signal that the economics favor running flat out.

Power Generation — The Seasonal Swing

US electricity demand is projected to rise 1.3% in 2026. Utility-scale solar capacity expansion continues to erode the thermal share of generation, but natural gas remains the swing fuel in most regional grids. During summer heat waves, gas-fired generation can spike by 10–15 Bcf/d above baseline.

Residential/Commercial — Weather Dependent

Space-heating demand accounts for roughly 30% of total US gas consumption during peak winter months. The 2025-26 winter was mild from February onward, which helped rebuild storage after Winter Storm Fern. Any colder-than-normal H2 2026 winter would materially increase this demand category.

Storage: A Buffer, Not a Shield

Storage entered the 2026 injection season (April 1) at ~1.9 Tcf, approximately 3% above the five-year average. With production growth and moderate shoulder demand, EIA forecasts end-October storage at 7% above the five-year average.

This is comfortable — but not complacent. In January 2026, Winter Storm Fern drove withdrawals of unprecedented magnitude, erasing a storage surplus in weeks. The lesson of 2026 Q1 is that buffer margins shrink fast when weather turns extreme.

Geopolitical Risk: The Iran Wildcard

The conflict in Iran and the Strait of Hormuz disruption have reduced global LNG supply since late February 2026. While the direct impact on Henry Hub is limited (the US is not a significant LNG importer), the indirect channel is powerful:

Wider TTF-Henry Hub spreads make US LNG cargoes more valuable, pulling stronger feedgas demand and tightening the US balance
European storage refill demand for winter 2026-27 will prioritize LNG imports as Russian pipeline flows are now negligible
Asian spot LNG prices (JKM) have surged, pulling US cargoes toward the Pacific basin

ESTIMATE: If the Hormuz disruption persists into H2 2026, expect an incremental 0.5–1.0 Bcf/d of US LNG feedgas demand above baseline as global buyers compete for Atlantic Basin supply. This alone could shift the US balance from "above-average storage" to "normal storage" — eliminating the buffer.

Key Metrics to Watch

Weekly storage injections (EIA): Every Thursday, 10:30 AM ET. A sustained below-average month would signal tighter balances.
LNG feedgas (S&P Global, Platts): Daily flows to US LNG terminals. Currently ~13.5–14.0 Bcf/d gross. Any sustained drop below 13 (outages) or rise above 14.5 (new train ramp) is material.
NOAA winter outlook (October): The single most important non-price data point for Q4-Q1 pricing. La Niña winters tend to be colder in the northern US.
Brent crude: Sustained crude above $90 supports Permian associated gas production. A crash below $65 would slow drilling and reduce associated gas volumes by a lagged 6–9 months.
TTF-Henry Hub spread: Currently elevated due to Hormuz disruption. A narrowing spread signals global LNG supply loosening; a widening spread pulls more US gas into export.

Scenario Analysis

Base Case (55% probability)

Production grows at ~2–3% through H2. LNG exports run at or slightly above capacity. Storage ends injection season near 3.8–3.9 Tcf. Henry Hub averages $3.00–3.50 in Q3 and $3.50–4.50 in Q4. Weather is normal — no repeat of Fern. This is the EIA central path and our base case.

Bull Case (25% probability)

A colder-than-normal winter arrives early. The Hormuz disruption extends into Q4, keeping global LNG tight. One or more US LNG trains experience unplanned outages. Henry Hub could reach $4.50–6.00 in Q4. Storage draws early in the heating season above the five-year average trigger price acceleration. The market reprices risk upward, pulling forward prices above $5 for peak months.

Bear Case (20% probability)

Production surprises to the upside (Permian GORs rise faster than modeled). The Hormuz situation is resolved, releasing Qatari LNG back into the Atlantic Basin. The winter of 2026-27 is mild. US storage ends winter well above the five-year average. Henry Hub averages $2.50–3.25 across H2. Forward prices for 2027 contract toward $3 or below.

FACT vs ESTIMATE

EIA published projections are labeled FACT. Rzzro scenario probabilities (55/25/20) are ESTIMATES based on historical weather frequency, current geopolitical risk assessment, and production trajectory analysis.

What This Means for Procurement

For natural gas buyers, H2 2026 presents a hedging dilemma. The base case suggests adequate supply and moderate prices. But the bull case path is short and has recent precedent. Key actions:

Layer Q4 2026 hedges now: Forward prices in the $3.50–4.00 range for December delivery offer reasonable protection against a $5+ winter spike. Waiting for a better entry is a weather bet.
Evaluate fixed-price vs. index-linked contracts: With storage above average but LNG demand structural, the decision hinges on winter weather risk appetite. Buyers with low tolerance should fix Q4 volumes now.
Monitor weekly storage reports: If injections fall behind the five-year average for 3 consecutive weeks by August, the base case is breaking down. Hedge additional volumes at that signal.
Watch LNG terminal flows: A sustained drop in feedgas due to unplanned maintenance, combined with elevated TTF spreads, signals tighter domestic balances ahead.

The natural gas market has delivered a surprise in each of the last three years — the 2021 winter freeze, the 2023 storage rebuild, the 2025-26 Fern shock. The safest forecast for H2 2026 is that it will also deliver a surprise. The only question is the direction.