Henry Hub Stuck at $3.20 as Record Supply Meets the Heat Wave — but December Above $4 Tells the Real Story

Natural gas is trading near $3.20/MMBtu into the July 4 weekend, having pulled back from a three-week high of $3.30 hit on June 25 as cooling forecasts trimmed air-conditioning demand before the heat returned. The front month is stuck in a soft summer, caught in a tug-of-war between two powerful forces: record domestic production and ample storage pressing down on price, and a severe mid-July heat wave plus record LNG export demand holding it up. The prompt contract is going nowhere fast, chopping in a tight band as each weather forecast and storage report nudges it a few cents either way.

The thesis is that the front month and the curve tell two different stories, and the curve is where the real bet lives. The prompt month sits subdued near $3.20, pinned by Lower 48 production running around 110 Bcf/d near record highs and storage sitting roughly 6% above the five-year average. But December 2026 futures trade above $4 and January 2027 near $5 — a steep winter premium that has nothing to do with the summer tape. The market is pricing pure seasonality: a soft summer giving way to a winter squeeze as record LNG feedgas demand draws down storage and tightens the balance. The front month is the tug-of-war; the curve is the structural bet.

That structural bet rests on LNG. Flows to US export terminals reached 17.4 Bcf/d in June, and three new facilities — Plaquemines LNG, Corpus Christi Stage 3, and Golden Pass LNG — are ramping toward the 20 Bcf/d mark. LNG exports are set to grow 9% in 2026 and another 11% in 2027, steadily linking US domestic gas to global demand and placing a firmer floor under Henry Hub than existed even two years ago. As that export demand pulls gas out of the domestic balance, the EIA expects storage to move below the five-year average over the forecast, and lower storage means higher prices. The winter premium in the curve is that expectation made visible.

Natural gas at $3.20 sits in a defined summer range. The $3.00 psychological level and the $2.83 EIA floor anchor the downside, while the $3.30 three-week high and $3.43 July-futures fair value cap the upside. Weather is the near-term swing factor — the mid-July heat wave supports the prompt month, cooler forecasts and the larger-than-expected 87 Bcf storage injection pull it back. Everything below builds that out.

The Heat Wave: NYC at 100°F and the Power Burn

The bullish force in the summer tape is heat, and it is intense right now. A severe heat wave is sweeping the country, forcing heavy reliance on air conditioning, with temperatures in New York City forecast to hit 100°F — threatening to tie a 1966 record. Meteorologists predict above-normal heat through mid-July, and that matters enormously for gas because gas-fired power plants provide roughly 40% of US electricity. When the country cranks its air conditioners, the power sector burns significantly more gas, and that cooling demand is the main source of seasonal demand growth in summer.

The power-burn mechanism is the summer equivalent of winter heating demand. As temperatures climb, electricity consumption for cooling surges, and gas-fired generation ramps to meet it — pulling gas out of the market and supporting the prompt-month price. The EIA noted that the season shifting into summer, with higher temperatures raising gas demand for cooling, drove Henry Hub above $3.00 toward the end of May. The heat wave now sweeping the country is that dynamic intensified, and it is the reason the front month holds near $3.20 despite the bearish supply picture.

The problem is that the heat is not consistent. The June 25 three-week high at $3.30 faded to $3.17 as cooling weather forecasts signaled a drop in air-conditioning demand, before warmer forecasts through mid-July reasserted. That choppiness is characteristic of summer gas — the price whipsaws on each shift in the temperature outlook, because cooling demand is the swing variable and the forecasts change constantly. The heat wave supports the price today, but a cooler-than-expected stretch would pull it back toward $3.00 fast.

For the forecast, the heat is the near-term bullish catalyst that keeps the front month from breaking down. Sustained above-normal temperatures through July would keep power-burn demand elevated and support the prompt month near or above $3.20, potentially challenging the $3.30 resistance. A shift to cooler forecasts would cut cooling demand and pull the price toward the $3.00 floor. Weather is the dominant near-term driver, and the mid-July heat wave is currently on the bullish side of the ledger — but it is the most volatile variable in the market.

The Record Production Wall: 110 Bcf/d

The bearish force pinning the front month is supply, and it is running near records. Production in the Lower 48 states averaged 110.0 Bcf/d in June, up from 109.7 in May and approaching record highs. That output is the wall the bulls have to climb — a market producing gas at near-record levels has ample supply to meet even the elevated summer cooling demand, which caps how far the price can rise on heat alone. The strong production is the single biggest reason the front month is stuck near $3.20 rather than rallying on the heat wave.

The production growth is structural. The EIA forecasts US marketed natural gas production to grow 3.3% in 2026, about 3.9 Bcf/d, and by an additional 2.5% in 2027, driven by output from the Permian, Haynesville, and Appalachia. Higher crude oil prices in the first half of 2026 encouraged additional oil drilling, which produces more associated natural gas as a byproduct — adding supply to the market independent of gas-directed drilling. The result is a supply picture that keeps pace with or exceeds demand growth through 2026, capping prices.

The supply strength is why the EIA lowered its price forecast. The agency raised its production forecast and, with more gas expected in storage throughout the forecast period, translated its price curve vertically downward — cutting its 2027 Henry Hub forecast by $1.13/MMBtu compared with the January outlook. More production means more gas available, which means lower prices and higher storage, and the EIA's June outlook now expects Henry Hub to average about $3.34/MMBtu in the second half of 2026, below its earlier forecasts. The production wall is the reason the near-term price outlook softened.

For the forecast, record production is the structural weight on the front month. As long as Lower 48 output runs near 110 Bcf/d, the market has ample supply to absorb summer cooling demand, capping rallies and keeping the prompt month range-bound. The bull case requires demand — heat, LNG exports — to grow faster than the supply, tightening the balance. The bear case is that the production keeps overwhelming demand, pressing the front month toward $3.00. The production trajectory is the supply-side variable, and at near-record levels it is currently the dominant force on the prompt contract.

The Storage Cushion: 6% Above the Five-Year Average

The second bearish force is storage, and the cushion is comfortable. National inventories sit roughly 6.2% above historical five-year averages, with the injection season on track to end 7% above that benchmark. Ample storage is a bearish signal — periods with higher-than-average inventories are generally associated with lower prices, because the market has a buffer against demand spikes and less need to bid up the price to secure supply. The storage cushion is part of why the front month is subdued despite the heat.

The storage build reflects the supply strength. With production near records and summer demand not yet enough to absorb it all, the market has been injecting gas into storage at a healthy pace, building the cushion above the five-year average. That storage acts as a shock absorber — even if the heat wave drives a demand spike, the ample inventories mean the market can meet it without a sharp price rally. The comfortable storage position caps the upside in the summer tape and keeps the prompt month anchored.

But the storage story shifts over the forecast horizon, and that shift is the key to the curve. The EIA expects storage inventories to gradually move below the rolling five-year average over the forecast as natural gas demand — driven mainly by LNG exports — outpaces supply growth. Storage levels that were 1.7% above the five-year average at the close of December 2025 are expected to tighten as the LNG export ramp pulls gas out of the domestic balance. As inventories move toward or below the five-year average, the EIA's forecasted Henry Hub price rises. The current cushion is a summer phenomenon that the winter is expected to erode.

For the forecast, the storage cushion is the near-term bearish weight that the structural LNG demand is expected to erode. The comfortable summer storage caps the front month near $3.20, but the projected move below the five-year average by winter is why the curve holds a steep premium. The bull case is that LNG demand draws storage down faster than expected, tightening the balance sooner. The bear case is that the cushion persists, keeping prices soft. The weekly storage reports are the highest-frequency read on which way the balance is tipping.

The 87 Bcf Injection and the Weekly Report

The most recent storage data reinforced the bearish near-term picture. Energy firms injected a larger-than-expected 87 billion cubic feet of gas into storage for the week ending June 26, keeping total stockpiles roughly 6.2% above historical averages. A larger-than-expected injection is a bearish surprise — it signals that supply is outpacing demand more than the market anticipated, and it pressed the front month below $3.20 as the data confirmed the comfortable storage position.

The weekly storage report is the single most important recurring data point for natural gas. Released every Thursday by the EIA, it shows how much gas was injected into or withdrawn from storage the prior week, and it is the market's primary gauge of the supply-demand balance. A larger-than-expected injection, like the 87 Bcf print, signals a looser market and pressures prices; a smaller-than-expected injection or a surprise withdrawal signals tightening and supports them. The report is the catalyst that moves the front month most reliably.

The 87 Bcf injection fits the broader pattern of a well-supplied summer market. With production near 110 Bcf/d and cooling demand not yet at its peak, the market has been injecting gas at a pace that keeps storage above the five-year average. The injection confirmed that even with the heat building, the supply is ample enough to keep adding to storage — a bearish signal for the front month. The size of the injection relative to expectations is what matters, and an 87 Bcf print that beat forecasts pressed the price.

For the forecast, the weekly storage reports are the near-term catalysts to watch. A string of larger-than-expected injections would confirm the loose summer balance and pressure the front month toward $3.00. A shift to smaller-than-expected injections — driven by the heat wave boosting power-burn demand — would signal tightening and support the price toward $3.30. The next report, capturing the heat-wave demand, is the test of whether the cooling load is finally outpacing the record supply. The storage trajectory is the scoreboard for the summer tug-of-war.

LNG Exports: The Structural Demand Engine

The force that transforms the natural gas outlook from soft to structurally bullish is LNG exports, and the ramp is powerful. Average flows to major US liquefied natural gas export terminals reached 17.4 Bcf/d in June, and the export base is growing fast. LNG exports are forecast to grow 9%, or 1.3 Bcf/d, in 2026, and another 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 LNG. This is the demand engine that pulls US gas into global markets and tightens the domestic balance.

The structural significance is that LNG links US gas to global demand, placing a firmer floor under Henry Hub than existed even two years ago. As Plaquemines and Corpus Christi Stage 3 ramp to full operations and Golden Pass begins operations in 2026, the feed-gas demand from these terminals grows steadily, pulling more gas out of the domestic market. That export demand is the reason the EIA expects storage to move below the five-year average over the forecast — the LNG ramp is the demand growth that outpaces the record supply and tightens the balance.

The LNG demand is why the winter premium exists. As LNG feed-gas demand peaks into the heating season and combines with winter heating load, the domestic balance tightens dramatically, drawing down storage and supporting prices. The EIA forecasts that in 2027, demand growth will rise faster than supply growth, driven mainly by more feed-gas demand from LNG export facilities, reducing storage and pushing the annual average price up 33%. The LNG ramp is the structural driver behind the curve's winter premium and the multi-year bull case.

For the forecast, LNG exports are the structural demand engine that underpins the bull case. The near-term summer softness reflects record supply meeting moderate demand, but the LNG ramp is steadily growing the demand side, and as it approaches 20 Bcf/d, it leaves little spare capacity in the system. The bull case is that LNG demand tightens the balance faster than expected, drawing storage below the five-year average and lifting prices. The LNG flow data and the ramp timelines of the three new terminals are the structural variables to track — they are the reason the back end of the curve holds a premium the front end lacks.

The Winter Premium in the Curve

The single most important feature of the natural gas market right now is the shape of the futures curve, and it tells the real story. While the prompt month trades near $3.20, December 2026 futures hold above $4 and January 2027 trades near $5.10 — a steep winter premium that reflects the market's expectation that winter will reassert the bull case. The curve is not pricing a year-round shortage; it is pricing pure seasonality, with soft summer pricing giving way to a firm winter as heating demand and LNG feed-gas demand peak together.

The curve shape is the clearest expression of the market's structural view. As of recent trading, the strip showed the front end soft, November above $3.80, December above $4, and January 2027 above $5 — a clear winter premium rather than a continuous squeeze. If the market expected a much tighter balance throughout the whole year, the front end would be stronger than it is. Instead, the curve prices seasonality: the record summer supply keeps the prompt month soft, while the winter demand peak plus the LNG ramp is expected to tighten the balance and lift prices sharply.

The winter premium is the trade the structural bulls are positioned for. The front month at $3.20 reflects the soft summer reality; the December-January premium above $4-5 reflects the expectation that the LNG-driven storage draw and winter heating demand will tighten the balance. The gap between the two is the seasonal bet — soft now, firm later. A cold winter would validate the premium and potentially push prices toward the $4-5 base case, while a polar-vortex repeat could revisit the $7+ range seen in January 2026, when Henry Hub averaged a record $7.72/MMBtu.

For the forecast, the curve's winter premium is the structural framework that separates the summer trade from the winter bet. The front month is a supply-vs-heat tug-of-war that keeps the prompt contract near $3.20. The curve is the market pricing the LNG-driven tightening into winter, holding December above $4 and January near $5. The bull case plays out in the back end as the LNG ramp and winter demand tighten the balance; the bear case is a warm winter that fails to draw down storage. The curve tells you the market expects the soft summer to give way to a firm winter — the question is the magnitude, which depends on weather.

The Oil Linkage and the Hormuz Effect

Natural gas caught a bearish crosscurrent from the oil market this week, and the linkage matters. Crude oil prices slid to prewar levels following diplomatic progress between the US and Iran regarding the Strait of Hormuz, and that decline dampened energy markets broadly — including natural gas sentiment. Cheaper oil affects natural gas because gas is positioned as a viable energy alternative to crude, and falling oil prices pressure the entire energy complex, weighing on gas even when its own fundamentals differ.

The oil linkage runs through several channels. Lower oil prices reduce the incentive for oil drilling, which over time could slow the associated-gas production that has added to supply — a marginally bullish long-term effect. But in the near term, the sentiment effect dominates: a broad energy-market selloff driven by the Hormuz reopening and the crude collapse to $68.50 WTI drags gas sentiment lower, reinforcing the soft summer tape. The oil crash to prewar levels this week was a bearish input for gas.

The Middle East conflict itself was never a major direct driver of US gas prices. The EIA noted that the Middle East conflict alone would not drive up US gas prices, because US LNG plants are already running near full capacity, leaving little room for near-term export growth to capture any global supply disruption. So while the Hormuz closure spiked global oil and European gas, US Henry Hub was relatively insulated — and now the Hormuz reopening and oil collapse are a modest bearish sentiment drag rather than a fundamental shift for US gas.

For the forecast, the oil linkage is a secondary bearish input in the near term. The crude collapse to prewar levels dampens energy-market sentiment and reinforces the soft summer gas tape, but it is not a primary driver of US gas fundamentals, which are dominated by domestic production, storage, weather, and LNG. The bull case is largely independent of oil — driven by the LNG ramp and winter demand. The oil linkage is a sentiment overlay that is currently mildly bearish, but the structural gas story runs on its own drivers.

The 2026 Round Trip: From a $7.72 Record to Sub-$3

To size the current setup, natural gas's wild 2026 needs context. Henry Hub hit a monthly average record of $7.72/MMBtu in January 2026 — the highest ever recorded — as a polar vortex drove record storage withdrawals of 2,020 Bcf over the heating season, 4% above the five-year average. That winter spike was a demand shock of historic proportions, and it briefly sent prices toward $7/MMBtu as the cold drained storage. The market was as tight as it had been in years.

Then it crashed. Prices fell below $3/MMBtu by mid-March as mild spring weather returned, storage normalized through healthy injections, and the new LNG export terminals — Golden Pass and Corpus Christi Stage 3 — began adding capacity and reshaping the balance. Henry Hub fell from the $7.72 January record to $3.62 in February and below $3 by mid-March, a dramatic reversal driven by the return of mild weather and the recovery of storage. The round trip from a record high to sub-$3 in ten weeks captured the market's extreme weather sensitivity.

The 2026 path illustrates the market's core dynamic: weather-driven volatility around a structural range. The 52-week range spans roughly $2.62 to $7.83/MMBtu, showing the market's capacity for rapid repricing. The January spike was weather; the March crash was mild weather plus supply and LNG ramp; the current $3.20 is a soft summer with heat providing support. Each move was driven by the interplay of weather, storage, production, and LNG — the four variables that define the market.

For the forecast, the 2026 round trip shows what the winter premium is pricing. The January $7.72 record demonstrates the upside a cold winter can produce, and it is why December-January futures hold a steep premium — the market remembers what a polar vortex does to a tightening balance. The current $3.20 soft summer is the seasonal low, and the curve prices a firming into winter. The round trip is the reason the market is capable of the $4-5 winter base case and the $7+ polar-vortex tail — weather is the swing factor, and 2026 already showed both extremes.

The Technical Map: $3.00 Floor, $3.30 and $3.43 Resistance

The chart frames the summer trade around a defined range. The front month at $3.20 sits between the $3.00 psychological floor and the $3.30 three-week high set on June 25. Below $3.00, the EIA's Q2 forecast of $2.83/MMBtu represents the practical floor for this cycle absent extreme warm weather, and a drop below $2.50 is possible in a warm-weather scenario but viewed as unsustainable given the structural LNG export floor. Above, the $3.30 high and the $3.43 July-futures fair value cap the summer upside.

The near-term levels are well-defined by recent action. The prompt month hit $3.30 on June 25 before retreating to $3.17 on cooling forecasts, then stabilizing near $3.20 as the heat wave built. The $3.00 level is the key psychological support — a break below it would signal the soft summer is deepening toward the EIA's $2.83 floor. The $3.30 three-week high is the immediate resistance; clearing it on sustained heat would open the path toward the $3.43 July-futures level and confirm the cooling demand is outpacing supply.

The support structure has a hard floor rooted in producer economics. At $2/MMBtu, production curtailments and rig-count reductions would emerge within weeks, tightening the market faster than seasonal trends suggest — a self-correcting mechanism that puts a floor under the price. The $2.83 EIA Q2 forecast is the practical floor for this cycle, and the structural LNG export demand reinforces it. That means the downside in the summer tape is limited even in a warm-weather scenario, because low prices trigger supply response and the LNG floor supports demand.

For the forecast, the technical map is a summer range with a firm floor and a heat-dependent ceiling. Hold $3.00 and the soft summer continues; a sustained heat wave clearing $3.30 opens $3.43. Lose $3.00 and the $2.83 EIA floor comes into play, with $2.50 the warm-weather tail. The front month is likely to chop in the $2.83-$3.43 range through summer, driven by weather, while the curve holds its winter premium. The near-term trade is the range; the structural trade is the seasonal firming into winter that the curve prices.