Natural Gas Futures Price Forecast: NG Slides to $2.6 Near Multi-Month Low; Storage Surplus 7% Above 5-Year Average

Natural Gas Futures (NG=F) are trading at $2.665 with a 0.97% to 1.20% loss on the session, sitting near the multi-month low of $2.649 reached last Friday and demonstrating the cleanest divergence between U.S. domestic pricing and global LNG markets that traders have witnessed across the entire Iran war cycle. The June front-month contract took over from the expired May contract on Tuesday and immediately rolled lower, signaling that the bearish supply structure has full control over the U.S. tape regardless of what is happening in Europe and Asia. The Henry Hub benchmark sits at roughly $3.00 per million British thermal units, with the June futures contract pricing significantly lower at $2.665 — a structural disconnect that captures the difference between physical spot demand and forward contract pricing in a market drowning in domestic supply. The 24-hour intraday range for NG=F has been compressed between $2.649 and $2.808, with the swing top at $2.808 acting as immediate resistance and the pivot at $2.777 sitting between current price and any sustained recovery. The 50-day moving average at $3.013 and the 200-day moving average at $3.503 confirm the intermediate and long-term trends are decisively lower, with both averages providing dynamic resistance overhead that any rally has to break to flip the structure bullish. The most striking data point underscoring the U.S.-Europe price divergence: European TTF (Title Transfer Facility) May futures climbed more than 8% to €47.2 ($55.1) per megawatt-hour today, while the Japan-Korea Marker (JKM) benchmark in Asia trades near $11 per MMBtu — both substantially higher than U.S. Henry Hub pricing because European and Asian buyers face the supply-shock channel that U.S. domestic producers do not. The Strait of Hormuz carries roughly 20% of global LNG trade, and the prolonged closure has tightened international supply meaningfully, but U.S. storage at over 7% above the five-year average and production near record 110 billion cubic feet per day is overwhelming the bullish global narrative inside the domestic futures market.

The Storage Glut Is the Single Variable That Defines the Bear Case

U.S. natural gas inventories sit more than 7% above the five-year average heading into the spring shoulder season, and that single data point drives the entire bear case for NG=F at current levels. The Energy Information Administration reported a 103 billion cubic feet build for the latest weekly storage report, well above expectations and substantially above the seasonal norm — a print that confirmed the supply glut narrative and provided the catalyst for the latest leg lower in June futures. The current week's storage inventory deficit had been around 6% below normal during the week ended February 13, but the surplus has flipped dramatically across the intervening months as winter heating demand wound down and production maintained record pace. NGI's storage projection sees a 73 Bcf storage increase for the most recent reporting week, which would extend the surplus further above the five-year average. The market is now heading into the seasonal "dead zone" for natural gas demand — winter heating is finished, summer cooling is still weeks away, and the gap between supply and consumption widens mechanically across the next 30 to 45 days unless an unusual demand catalyst emerges. The cold front that buyers tried to leverage on Tuesday gave the bulls a tactical opening with May contract pricing modestly higher into expiration, but the June contract immediately rolled lower because the cold snap is short-term noise against the structural supply backdrop. LSEG projected average gas demand in the Lower 48 states, including exports, would slide from 137.5 bcfd this week to 130.3 bcfd next week — a 7.2 bcfd decline that captures the seasonal demand softening underway. Average gas output in the Lower 48 climbed to 108.7 bcfd in February, up from 106.3 bcfd in January, and current production estimates put the figure near 110 bcfd. The monthly record of 109.7 bcfd hit in December stands as the cleanest benchmark of how aggressive U.S. producers are running into a supply-saturated market.

European TTF Surges 8% to $55 — The International LNG Story Tells the Other Half

The European energy market is telling a structurally different story than the U.S. domestic futures tape, and the divergence is the single most important dynamic for understanding where pricing power genuinely sits in the global LNG complex. TTF May-dated futures at the Dutch Title Transfer Facility climbed more than 8% Wednesday to €47.2 ($55.1) per megawatt-hour, supported by the lack of progress in reducing tensions between Washington and Tehran and the uncertainty about when energy flows through the Strait of Hormuz could normalize. Markets in Europe price the supply-security premium aggressively because the continent remains heavily dependent on imported LNG to replace the Russian pipeline gas lost since 2022. The Strait of Hormuz carries roughly 20% of global LNG trade, and any sustained closure mechanically tightens the supply available for European and Asian importers. Qatar LNG infrastructure damage and Strait constraints have already produced visible disruptions in tanker movements, with first LNG vessels reportedly retreating from the strait amid tensions and Asian LNG imports hitting a 7-year March low as the war choked Qatari supply. China's LNG imports collapsed to a 6-year low as prices surged, and Japan's top utility JERA has secured LNG supply through July but cancelled a long-term LNG deal with Commonwealth signaling a broader retrenchment from forward energy commitments at elevated prices. The U.S. became the world's biggest LNG exporter in 2023, surpassing Australia and Qatar, and that export-driven demand pull should mechanically support U.S. domestic gas pricing during global supply shocks — except that the production surge is matching the export pull pound for pound, leaving domestic storage saturated and futures pricing depressed. Average gas flows to the nine large U.S. LNG export plants have risen to 18.6 bcfd so far in February, up from 17.8 bcfd in January and on track to beat December's monthly record of 18.5 bcfd. QatarEnergy/ExxonMobil's 2.4-bcfd Golden Pass export plant under construction in Texas is taking in more feedgas as it prepares to produce its first LNG, which will add another structural demand layer once operational. LNG Canada's expansion is gaining momentum amid the Iran war, with the facility nearing full capacity as the global supply squeeze intensifies. Cedar LNG construction is advancing with the FLNG vessel nearing the completion midpoint. The pipeline of new LNG export capacity coming online across the next 24 months is the cleanest medium-term bullish driver for U.S. domestic gas pricing, but the timing mismatch between current oversupply and future export pull means the spot futures market has to grind through the surplus before forward demand provides relief.

The Waha Hub Negative Pricing Story — A Permian Basin Disaster

The most striking individual price data point in the U.S. natural gas market right now is the Waha Hub in the Permian Basin, where average prices have remained in negative territory for a record 12th consecutive day as pipeline constraints trap gas in the nation's biggest oil-producing basin. Daily Waha prices first closed below zero in 2019 — a freak event at the time — but the frequency has accelerated dramatically. Negative closing prices occurred 17 times in 2019, six times in 2020, once in 2023, a record 49 times in 2024, 39 times in 2025, and 21 times so far in 2026 across just four months. The Waha pricing average has been 76 cents per mmBtu year-to-date, compared with $1.15 in 2025 and a five-year average of $2.88 — meaning the regional pricing for one of the largest U.S. gas-producing areas is running 73% below historical norms. The mechanism is straightforward: associated gas production from oil drilling activity in the Permian has overwhelmed pipeline takeaway capacity, leaving producers to either pay buyers to take the gas (negative pricing) or shut in production. The Waha situation is structural rather than cyclical because the oil-driven production growth in the Permian compounds the gas oversupply regardless of what the dedicated dry-gas regions like Marcellus or Haynesville do with rig counts. The biggest movers on the spot price tape today reinforce the Permian dislocation — El Paso-Waha Pool, Waha, and El Paso-Keystone & Waha Pools are leading gainers in regional pricing as some short-term relief filters through, while NGPL Amarillo Mainline, Tennessee Zone 4 Marcellus, and Millennium East Pool are leading losers. TotalEnergies disclosed that approximately 15% of its oil and natural gas production in the Middle East remains offline indefinitely, with no timeline for restart — adding another layer of supply tightness to the global market that the U.S. domestic tape is structurally insulated from due to the storage glut.

Production at 110 Bcfd Is the Bullish Antithesis — And It's Not Slowing

The U.S. natural gas production figure sitting near 110 billion cubic feet per day is the single number that overwhelms every bullish argument for NG=F in the immediate term. The rig count has been grinding higher for 18 consecutive months, the EIA has already raised its production forecast to reflect the higher output trajectory, and there is no current catalyst that would force producers to throttle back. The supply-side resilience is structural: the Permian Basin is producing associated gas as a byproduct of oil drilling regardless of gas pricing, the Marcellus and Haynesville producers are running pipelines at near full utilization, and the Canada natural gas output has hit record highs as LNG Canada opens the door to global markets. Canadian production growth adds another structural overlay to the North American supply picture that historically would have provided import support to U.S. demand but now competes for the same export markets. Enterprise Products Partners posted record processing volumes in the supply-shock quarter, capitalizing on the natural gas price spread dislocations across regions. Ares is acquiring the Rover Natgas Pipeline stake from Blackstone in a transaction that signals continued institutional capital commitment to the U.S. midstream infrastructure. The EIA confirmed that U.S. oil stocks have plummeted and the country has become a net crude exporter on a weekly basis for the first time, which mechanically increases associated gas production from the same oil-drilling activity that is producing the crude exports. The supply backdrop has only one structural pressure release: a meaningful production curtailment from major producers, which is unlikely at current pricing levels because most producers can still maintain economics on associated gas even at depressed prices. The bear case for NG=F is fundamentally about the impossibility of clearing the storage surplus before summer cooling demand kicks in, given that production will not slow and demand has multiple weeks of softness ahead.

The Technical Map — $2.649 Floor, $2.777 Pivot, $3.013 Wall

The technical structure on NG=F has compressed into a setup where four price points define every meaningful trade scenario across the next two weeks. Primary support: $2.649, the multi-month low reached last Friday and the level any continuation move lower has to break cleanly to confirm the next leg of the bearish trend. Secondary support: $2.564, the deeper multi-month low that becomes the next downside target if $2.649 cracks. Structural floor: $2.442, the level that represents the broader corrective support and would mark a meaningful capitulation if reached. Primary pivot: $2.777, the near-term swing pivot that needs to be reclaimed for any sustained bullish reversal. First resistance: $2.808, the minor swing top that has capped recent rally attempts. Major resistance: $2.905, the recent swing top that needs to break for short-covering momentum to accelerate. Critical resistance: $3.013, the 50-day moving average that has acted as dynamic supply on every approach across the past two months. Long-term resistance: $3.503, the 200-day moving average that defines the structural ceiling for any genuine trend reversal. The near-term range sits between $2.649 and $2.905, with current price at $2.665 sitting at the lower band of that range and pressing toward the floor. Any rally from current levels is very likely to be short-covering rather than fundamental buying, which means the asymmetric setup favors selling rallies into resistance rather than buying weakness. The formation tells the story clearly — it is going to take a sustained move over the 50-day MA at $3.013 to get any genuine bullish conviction back into the futures market, and the production-storage backdrop makes that level structurally difficult to reach without a hard catalyst.

The LNG Export Pull and Why the Forward Curve Disagrees With Spot

The forward curve on NG=F tells a meaningfully different story than the front-month June contract is currently pricing, and the disconnect captures the genuine fundamental ambiguity in the U.S. natural gas market. The seasonal pattern combined with the LNG export expansion timeline supports higher pricing in the back half of 2026 and through 2027, but the immediate spot tape has to clear the current storage surplus before that forward demand provides upside support. Average gas flows to U.S. LNG export plants at 18.6 bcfd capture the current export pull, and that figure is on track to exceed December's record 18.5 bcfd as Golden Pass ramps up first feedgas and additional facilities approach commercial operation. The medium-term math is meaningful: every 1 bcfd of incremental LNG export capacity removes roughly 365 Bcf of annual U.S. supply availability, which over 24 to 36 months translates to a structural demand layer that current production growth may not be able to meet without higher pricing to incentivize additional drilling. The Strait of Hormuz disruption is providing additional support to the medium-term LNG export thesis because European and Asian buyers are signing longer-term contracts at higher prices to lock in supply security from non-Iran-exposed sources. Global gas trading near $11 per mmBtu at both TTF in Europe and JKM in Asia compared to U.S. Henry Hub at $3.00 represents a $8 per mmBtu spread that creates massive arbitrage incentive for U.S. exporters to maximize liquefaction utilization and pull more domestic gas into international markets. The U.S. has firmly cemented its position as the world's largest LNG exporter, and the export-driven structural demand growth provides the multi-year bull case that current spot pricing does not reflect. Anyone running a multi-year book on NG=F has to balance the immediate bearish setup against the medium-term structural demand inflection that will materialize as new export capacity comes online and existing facilities run at higher utilization rates through the global supply shock.