Natural Gas Price Forecast: Henry Hub Drops to $2.788 as Production Glut Caps the Rally

Natural gas is changing hands at $2.788 per million British thermal units after settling 2.8% lower on the Tuesday session, snapping a six-day winning streak that had pushed front-month June Nymex Natural Gas Futures Price to its highest finish since April 7. The contract gave back 2.5 cents intraday to print at $2.842 before extending the slide into the close, with the day's range sweeping from $2.773 to $2.868 and the 52-week range stretching from $2.483 at the lows to $7.827 at the cycle peak. Monday's 3.13% rally pushed the contract to a four-week high, but the fundamental picture beneath the price action looks materially weaker than the chart suggests. Lower-48 dry gas output remains within striking distance of the December 2025 monthly record at 110.6 bcfd, storage sits 7.2% above the five-year seasonal average, and the LNG export channel is bleeding feedgas demand through the spring maintenance season. The bullish weather trade ran for three days. The bearish supply trade is structural.

The $2.749 Pivot Defines the Entire Setup

Working through the technical map, the near-term range is squeezed between $2.905 on the upside and $2.592 on the downside, with the pivot at $2.749 doing the heavy lifting as the level that determines the next directional resolution. The pivot read matters because it sits roughly halfway between the four-week high and the recent capitulation low, and it is the level where new buyers historically step in to defend a freshly formed bottom. A test of $2.749 that attracts fresh demand would set up a secondary higher bottom — the formation that typically precedes the second leg of a sustainable rally because it combines residual short-covering with genuine new buying. Above the immediate range, the first overhead test sits at $2.905, with the 50-day moving average at $2.987 acting as the structural ceiling that determines whether this short-covering rally extends into something larger. A break of $2.987 with volume opens the path toward the $3.107 intermediate retracement, and that is the level where the technical case actually starts looking constructive on a multi-week horizon.

The Short-Covering Rally That Is Not New Buying

The honest read on the three-day surge that preceded Tuesday's reversal is that it was driven by short-covering rather than fresh institutional accumulation. The selloff from January 30 to April 30 was prolonged in both magnitude and duration, and the first rally off a bottom of that scale almost always reflects bearish positions getting forcibly unwound rather than new capital entering. Smart money does not chase the first leg up. Smart money waits for the pullback into the pivot, watches for the secondary higher bottom to form, and adds size only after the structure confirms. The current setup is precisely that — a market that has rallied hard enough to flush out short positioning but has not yet shown the volume profile that would validate genuine accumulation. The next 5 to 10 sessions will determine whether the secondary higher bottom forms or whether the entire bounce gets retraced into a fresh test of $2.592.

Production Is the Headwind That Will Not Go Away

The supply side of the equation remains the structural problem the bulls cannot solve. Lower-48 dry gas output hit 110.1 bcfd on Monday, up 3.2% year-over-year and within striking distance of the December 2025 monthly record of 110.6 bcfd. The Energy Information Administration has lifted its 2026 production forecast to 109.59 bcfd. Average output across May has slipped slightly to 109.1 bcfd from 109.5 bcfd in April, with low spot prices forcing producers like EQT — the second-largest US gas producer — to temporarily reduce output as they wait for higher prices later in the year. The gas rig count has climbed to 130, only four rigs short of the 134 multi-year high set in February. Production is not rolling over in any meaningful way, and the current dip reflects price-driven discipline rather than structural decline. Until rig counts and output meaningfully retreat, the supply ceiling stays in place and the upside in Natural Gas Futures Price is mechanically capped.

Storage Is Sitting 7.7% Above the Five-Year Average

The inventory picture compounds the bearish supply story. Working gas in storage hit 2,142 billion cubic feet on the week ending April 24 — 7.7% above the five-year seasonal average and nearly 5% above year-ago levels. The latest weekly injection of 79 bcf came in below the 83 bcf consensus expectation but still ran well above the 63 bcf seasonal norm, confirming that the over-supply pattern is structural rather than transitory. The forecast for the week ending May 1 implies a 72 bcf build, modestly trimming the surplus to roughly 7.2% above the five-year baseline from 7.7%. That is a slight tightening, not a fundamental reset. The mild weather that defined the early spring allowed energy firms to inject more gas into storage than usual, and the cushion that built during that window now requires sustained demand or production declines to draw down. Neither catalyst is currently firing at scale.

The Waha Hub Disaster That Is Quietly Destroying Permian Producers

Buried in the supply story sits the Waha Hub pricing collapse that nobody outside the energy desk is talking about loudly enough. Daily Waha prices have averaged below zero for a record 62 consecutive days as pipeline constraints trap gas in the Permian region — the largest oil-producing shale basin in the country. The historical context is stark: Waha prices first averaged below zero in 2019. The negative-day count was 17 in 2019, six in 2020, one in 2023, 49 in 2024, 39 across all of 2025, and a staggering 71 days year-to-date in 2026 alone. The current Waha cash print sits at -$4.16 per mmBtu, with the year-to-date average running at -$2.22 against a positive $1.15 in 2025 and a positive $2.88 across the 2021-to-2025 five-year window. Producers are effectively paying counterparties to take gas off their hands, which mechanically destroys economics for any unhedged Permian operator and forces the kind of associated-gas production cuts that would normally support prices — except the LNG and pipeline takeaway capacity to absorb that gas does not currently exist where it is needed.

LNG Export Maintenance Is the Demand-Side Headwind

The other half of the bearish setup sits in the export channel. Average gas flows to the nine major US liquefied natural gas export terminals fell to 17.3 bcfd through May, down from a monthly record of 18.8 bcfd in April. The pullback reflects the standard spring maintenance cycle at major facilities, and the dip is seasonal rather than structural — but the timing matters because feedgas demand is the swing variable that determines whether the storage surplus can be drawn down through the summer. With LNG flows running 1.5 bcfd below the April peak, the demand side of the balance equation is materially softer than it needs to be to absorb the production surplus. Power burn is the offset that bulls are leaning on, with consumption at 65.5 bcfd on Monday, up 7% year-over-year as below-normal Midwest temperatures lift heating demand into the May 13 window. That single statistic captures why the rally got legs — but mild weather forecasts running near normal through May 20 cap the duration of that demand pop. Cooling demand is now expected to overtake heating demand for the first time this year, which provides a fresh demand pulse but only modestly offsets the LNG pullback.

The Hormuz Disruption Is Reshaping the Global LNG Map

The structural variable that is not yet fully priced into Natural Gas Futures Price is the impact of the Strait of Hormuz closure on global LNG flows. Middle Eastern gas supplies that historically reached European and Asian buyers have been substantially curtailed, and the global market is now scrambling for replacement volumes. US LNG exports sit in a stronger competitive position than they did three months ago because there are fewer alternative cargoes available. The Qatar disruption is the more consequential layer. Iranian strikes have damaged 17% of Qatar's Ras Laffan LNG export capacity, with repairs projected to take three to five years. Ras Laffan accounts for roughly 20% of global LNG supply on its own, which means the world is now operating with a structural LNG deficit that the market has not yet fully repriced. European storage at 32% full sits well below the 45% five-year average, which tells you exactly where the next wave of LNG demand is heading once the Hormuz situation resolves. That structural pull on US export capacity is the single most important medium-term catalyst for Henry Hub pricing — and it is being almost entirely overlooked in favor of the near-term storage and production noise.

International Benchmarks Tell the Real Story

The disconnect between US prices and the rest of the global gas complex is genuinely shocking. The Henry Hub front-month sits at $2.85, while the Title Transfer Facility (TTF) European benchmark trades at $16.57 per mmBtu, and the Japan-Korea Marker (JKM) Asian benchmark sits at $16.86 per mmBtu. That is a roughly 6x premium for international cargoes versus US domestic pricing — the kind of spread that creates massive economic incentive for additional US LNG export capacity. The TTF reading is up materially from $11.68 a year ago and well above the 2025 average of $11.94, while the JKM has surged from $11.83 a year ago to current levels. The five-year averages of $18.51 for TTF and $18.12 for JKM put current pricing meaningfully below the 2021-2025 baseline, but the absolute spread to Henry Hub remains structurally huge. As long as that arbitrage exists, every US LNG facility coming online over the next 24 months — including the Golden Pass project that just delivered first cargoes in late April — pulls bcfd off the domestic market and supports Henry Hub pricing structurally. The market is not yet pricing this transition aggressively, and that is the thesis that gets a holder of June 2026 contracts paid over a multi-year horizon.

Demand Forecasts Are Softening Modestly

LSEG projected average gas demand in the Lower 48 states, including exports, would hold near 97.8 bcfd this week and next — readings that have been trimmed lower from Monday's outlook. The total US demand picture for the current week reads 97.6 bcfd against 103.1 bcfd for the prior week, with next week pulling back further to 97.9 bcfd. Total US supply for the same windows runs 115.0 bcfd, 115.8 bcfd, and 117.0 bcfd respectively, leaving a roughly 18 bcfd surplus that needs to be absorbed by storage injections rather than burn-through demand. Power generation by fuel mix tells the same story — natural gas accounted for 32% of US power generation for the week ending May 8 versus 39% the prior week, with the offset coming from a 15% wind contribution (up from 12%) and a 12% solar contribution (up from 8%). Renewables continue to take share from gas at the margin during shoulder seasons, and that structural pressure compounds the near-term oversupply problem.