Natural Gas Price Forecast: Henry Hub Breaks Below $3 to $2.87 as 109.7 Bcfd Supply Overwhelms Iran War Premium

Natural gas futures (Henry Hub) settled Monday at $2.887 per million British thermal units — down 15.1 cents or 5% on the session — after touching their lowest level since February 27, a one-month low that came directly on the heels of the market's highest print since March 23 just the Friday prior. That whipsaw captures everything about the current natural gas market in a single week of price action: sharp spikes on Middle East war headlines, immediate reversals when supply fundamentals reassert themselves, and a market that keeps drifting back toward the same structural floor regardless of what is burning in the Gulf. Tuesday saw the May contract bounce slightly from the Monday low but remain mired in noise below $3, with the overall range continuing to compress toward the $2.70-$2.75 zone that represents the next meaningful technical floor.

The front-month is now the May contract — the first full month of the shoulder season, which is the single most reliably bearish period in the natural gas calendar. April and May represent the transition out of winter heating demand and before summer cooling load arrives, and the market is actively pricing that reality over the geopolitical noise. Thomas Saal, senior vice president for energy trading at StoneX Financial, stated directly: "The market's looking forward into the shoulder month period, which is a low demand period for April and parts of May. Prices could continue to trade a little bit below $3." That is not a bear case framing — it is the base case from a senior trading desk professional who is watching supply at 109.7 billion cubic feet per day and demand projections that show no stress.

The Supply Picture: 109.7 Bcfd and Rising — This Is the Story the War Cannot Override

U.S. Lower 48 natural gas output averaged 109.7 Bcfd so far in March, up from 109.2 Bcfd in February, according to LSEG data. That sequential production increase — small in percentage terms but significant in absolute volume — is the fundamental anchor suppressing Henry Hub prices regardless of what Iran does to LNG infrastructure on the other side of the world. LSEG projected average gas demand in the Lower 48 states, including exports, at 108.6 Bcfd for the current week and 110.3 Bcfd for the following week. Supply at 109.7 Bcfd against demand of 108.6 Bcfd is a market running a modest surplus — not a tight market, not a stressed market, and certainly not a market that warrants the kind of geopolitical risk premium that briefly pushed Henry Hub to its March 23 spike high.

Analysts at Ritterbusch and Associates captured the structural tension precisely: they believe "a significant decline in production or any unexpected supply disruption could prompt an outsized price response" but immediately qualified that observation by noting that "although export activity has ramped up in recent days, supportive impact has been largely offset by the increased output." That is the complete fundamental story in two sentences — exports are at elevated levels due to LNG demand from international buyers seeking alternatives to Middle Eastern supply, but domestic production is growing fast enough to absorb that export pull without tightening the domestic market meaningfully.

The NGI storage projection for the week ended March 27 shows an injection of 38 Bcf into underground storage. The timing of storage injections matters enormously for the shoulder season narrative. Injections in April and May build the storage cushion that determines winter pricing later in the year. A 38 Bcf injection in late March — as shoulder season demand begins its seasonal decline and production holds strong — is precisely the kind of build that suppresses prices during the injection season. If weekly injections continue at or above seasonal averages through April and May, the storage inventory that enters summer will be sufficient to cap any summer heat-driven rally, keeping Henry Hub anchored in the $2.50-$3.50 range through the injection season.

Why the Iran War Has Not — and Cannot — Rescue Henry Hub in the Near Term

The disconnect between Brent crude trading near $115-$118 and natural gas futures wallowing below $3 confuses casual observers who assume all energy commodities move together in a geopolitical shock. The reason they have diverged so dramatically is structural and worth understanding in full detail. Henry Hub prices the U.S. domestic natural gas market, which is driven by weather in the northeastern United States, domestic industrial demand, power burn, and the level of LNG exports leaving U.S. terminals. It is not directly driven by Middle Eastern LNG flows, Qatari production disruptions, or the Strait of Hormuz closure. The U.S. is the world's largest natural gas producer and a net exporter — meaning it is insulated from Middle Eastern supply disruptions in a way that Europe is not.

Qatar's Ras Laffan LNG facility was damaged in Iranian attacks, creating genuine supply anxiety for European and Asian buyers who depend on Qatari LNG. That damage is real and consequential for global LNG markets. But it does not reduce domestic U.S. gas supply by a single Bcf per day. The Qatari disruption creates incremental export demand for U.S. LNG terminals — specifically Sabine Pass, Corpus Christi, and Calcasieu Pass — as European buyers divert orders toward American supplies. That export pull is showing up in ramped-up LNG feed gas deliveries, which the NGI chart of Henry Hub and TTF futures alongside LNG feed gas deliveries shows approaching 18 Bcf per day. But as Ritterbusch noted, increased output is absorbing that export demand without creating domestic tightness.

The longer-term impact of the Hormuz closure on Henry Hub is real but distant. If Persian Gulf LNG infrastructure remains damaged heading into winter 2026-2027, Europe will need to draw more aggressively on U.S. LNG exports, which will pull more domestic supply onto tankers and gradually tighten the domestic market. That is the bull case for natural gas heading into late 2026. It is not the story for April and May 2026, when temperatures are warming, weather-driven demand is collapsing, and the market is building storage for winter.

European TTF's 8% Crash: What It Tells You About the War Premium Deflating

While the Henry Hub contract was grinding below $3, the European benchmark Dutch TTF fell more than 8% on Tuesday to approximately €50.6 ($58.3) per megawatt-hour — down sharply from the historic high of $78 per MWh hit earlier in March. That 25%-plus decline from the March high in a matter of weeks is the European gas market pricing exactly what the Henry Hub market is also pricing: the geopolitical spike premium is eroding as traders recognize that the near-term supply disruption, while severe, has not produced the complete European gas cut-off that the $78 high was briefly pricing.

Despite the 8% single-day collapse, TTF at $58.3 per MWh remains significantly elevated compared to pre-war levels. Before the Iran conflict began on February 28, European gas was trading in a fraction of the current range. The persistent elevation above pre-war levels reflects two genuine and ongoing risks: continued uncertainty about whether Qatar's Ras Laffan facility can resume full operations, and the longer-term energy security concern that Europe cannot quickly diversify away from the supply chains damaged by the conflict. These are structural premiums that will not disappear until either the war resolves completely or European storage reaches sufficient levels to buffer against a winter without restored Middle Eastern LNG flows.

The TTF crash on Tuesday coincided with reports that Iran's president signaled willingness to end the war — news that simultaneously drove oil prices sharply lower (Brent diving approximately 9%), gold higher, and natural gas lower globally. If peace talks gain traction and Hormuz reopens, TTF would likely fall sharply back toward $35-$45 per MWh. If the conflict persists through summer, TTF could retest the $78 high and beyond as the November-December pre-fill season approaches and European buyers face the prospect of insufficient storage for a winter without adequate LNG imports.

The Henry Hub Technical Structure: $3 Is the Ceiling, $2.50 Is the Floor

The Henry Hub natural gas futures technical picture is as bearish as the fundamental picture. Price broke below the $3 level again — a level that has repeatedly acted as resistance since the market sold off from the winter spike highs above $9.00 per MMBtu recorded in January 2026. That January spike — driven by a combination of polar cold snapping demand to near 70 Bcfd and Iran-war-related export pull — is the outlier that distorts the chart. Below the spike, the market quickly reverted to the $2.50-$3.50 range that characterized the bulk of 2025 trading, and that is where it sits again now.

The 50-day EMA sits between current prices and the $3.50 level — acting as a resistance ceiling on any short-term recovery attempt. A bounce from the current $2.87-$2.90 zone could technically reach toward $3.00-$3.50, but every approach to $3.50 and above should be treated as a selling opportunity rather than a breakout signal. The market has confirmed this pattern repeatedly since the January spike — each rally fades at the 50-day EMA or the $3.50 area, and the path of least resistance reasserts itself to the downside.

The immediate floor is $2.70-$2.75. A break of $2.70 on a daily closing basis opens the path toward $2.50 — a level that represents the lower boundary of the 2025 trading range and where the market found buyers during the pre-war period. If $2.50 fails, the next support is the low $2.00s, though reaching that level would require either a significant production increase beyond current levels or a warmer-than-expected spring that eliminates any residual heating demand before the summer air conditioning season begins.

April bidweek trading confirmed the bearish pressure — prices were described as "mixed" in a market dominated by weak demand expectations. The NGI Chicago Citygate bidweek chart shows prices that spiked above $9.00 per MMBtu in early 2026 before collapsing sharply back below $3.00 — a visual that perfectly illustrates the temporary nature of the winter spike and the market's rapid return to structural equilibrium once heating demand subsided.

The AI Data Center Thesis Is Not a Near-Term Catalyst

One of the persistent bull arguments for natural gas over the past two years has been the AI data center buildout — the idea that hyperscale computing facilities running around the clock would require massive amounts of natural gas for power generation, creating a structural demand floor that would keep prices elevated above historical ranges. That thesis is real over a multi-year horizon. It is not a 2026 catalyst.

The AI data center construction pipeline has slowed considerably from the 2024-2025 pace, partly due to capital cost concerns as energy prices rose, partly due to the Iran war disrupting financing conditions for large infrastructure projects, and partly because the euphoria around AI infrastructure spending has collided with realistic deployment timelines. Data centers that are contracted but not yet built do not generate gas demand. Data centers that are under construction generate construction-related power demand but not the sustained high-power computing load that drives the bull thesis. The demand that the AI narrative promised for natural gas has not materialized at the scale or speed that the market priced in during the 2025 bull phase.

Until the first summer heatwaves of 2026 test the power grid and the market can directly observe whether data center power demand is adding incremental baseload pull on top of normal cooling demand, the AI thesis remains a narrative rather than a data point. Trading a narrative against 109.7 Bcfd of production and weak shoulder season demand is a losing proposition. The summer will be the test. Until then, any rally fueled by AI demand optimism is a selling opportunity.

LNG Export Demand: The Medium-Term Bull Case Accumulating Beneath the Near-Term Bear

The genuine medium-term bull case for Henry Hub natural gas is accumulating in the LNG export data, even if it cannot overcome near-term supply abundance. U.S. LNG export capacity is approaching 18 Bcfd in feed gas deliveries — a level that represents a structurally different demand profile than existed even two years ago. The Cedar LNG build is moving ahead. Golden Pass LNG — the QatarEnergy (70%)/ExxonMobil (XOM) (30%) joint venture in Sabine Pass — produced its first LNG this week, bringing the 18 million tonne per annum capacity plant one step closer to full commissioning expected in April. That additional capacity will add directly to the feed gas demand pulling on domestic U.S. production.

Industrial natural gas buyers in the U.S. are already experiencing the early stages of a more globally linked pricing environment. With U.S. LNG exports near 18 Bcfd and growing, domestic prices no longer exist in the insulated regional market they occupied a decade ago. Every additional export terminal that comes online tightens the link between Henry Hub and international LNG prices — a relationship that currently means TTF at $58.3 and Henry Hub at $2.87 represent an extraordinary arbitrage that LNG traders are actively exploiting. The arbitrage will not close overnight, but the growing export infrastructure is slowly creating the conditions where a sustained TTF rally pulls Henry Hub higher than weather alone would justify.

The medium-term winter 2026-2027 story is straightforward: if Persian Gulf LNG infrastructure remains compromised, Europe needs U.S. LNG at maximum volumes, which means U.S. producers need to increase output and export terminals need to run at maximum capacity. The domestic storage build through the injection season becomes critical — if injections fall below the five-year average because exports are absorbing supply that would otherwise go into storage, the entry into winter storage will be lower than normal and Henry Hub will price a winter risk premium that could take prices toward $4-$6. That is the bull case for the back end of 2026. It is a conditional bull case, contingent on the Hormuz closure persisting and global LNG flows not fully recovering.

The Qatar Ras Laffan Attack and Why It Matters for Later, Not Now

Qatar's Ras Laffan LNG facility — the world's largest single-site LNG production complex — was struck in Iranian attacks, jeopardizing infrastructure that handles a significant portion of global LNG supply. The facility's damage is being addressed but the "number of weeks" timeline for full resumption mentioned by Chevron (CVX) regarding its Wheatstone facility in Australia — which was separately damaged by Tropical Cyclone Narelle — gives a sense of the restoration timeline for large LNG plants. Weeks, not days, and potentially months for full capacity restoration.

Every week that Ras Laffan operates below capacity is a week where Asian and European LNG buyers need alternatives. The alternatives are primarily U.S. export terminals, Australian projects that are not impaired, and whatever Russian LNG can reach markets despite Ukraine's drone campaign against Baltic Sea ports. The U.S. share of that alternative supply allocation is growing by design — Trump's administration is actively promoting U.S. LNG exports as a geopolitical tool, and the pipeline of new export capacity (Golden Pass coming online, Cedar LNG advancing) is expanding the physical ability to fulfill that political commitment.

For domestic Henry Hub pricing, the Ras Laffan damage is a Q3 and Q4 story — the period when European pre-winter storage filling begins in earnest and LNG demand competes directly with domestic storage injection demand for the same domestic supply. In April and May, that competition does not exist at a level that moves the market. The shoulder season fundamentals dominate. The Ras Laffan story is real and potentially very bullish for Henry Hub heading into late 2026. But acting on it now, when the market is trading the May contract in shoulder season conditions with production at 109.7 Bcfd, is premature.

The Bidweek Complexity: Some Points Fall, Others Rise — The Market Is Not Monolithic

Bidweek trading data shows a differentiated picture across different delivery points. Transco Zone 2 non-St. was up $0.05 in bidweek trading. Transco Zone 3 St. was up $0.035. Transco Zone 1 added $0.03. Meanwhile, Tenn Zone 6 200L North fell $0.845 and Transwestern dropped $0.85. Those movements reflect the regional supply and demand balances within the U.S. natural gas infrastructure rather than a monolithic national price signal. Zones with pipeline constraints or high-demand industrial clusters command premiums; zones with abundant local supply or weak heating demand trade at discounts. The divergence in bidweek pricing confirms that the market is functioning normally in its regional differentiation — no systemic supply stress, just the routine seasonal rebalancing that characterizes every shoulder season.

Henry Hub itself represents the liquid center of U.S. natural gas trading, and the NGI daily natural gas price average surged above $45 per MMBtu during the January 2026 cold-driven spike before falling back to the $2-$4 range. The speed of that reversion from $45 to below $3 demonstrates that Henry Hub is an extremely mean-reverting market — spikes generated by weather or geopolitical events are typically temporary, and the market gravitates back to the cost of marginal production plus a modest margin remarkably quickly. The current $2.87 level is not a stressed floor — it is approximately the cost of marginal supply from some of the most expensive U.S. production basins, which defines the structural floor under normal supply conditions.

The Verdict: Sell Rallies Above $3, Buy at $2.50-$2.70 for a Q3-Q4 Position

Natural gas (Henry Hub) is a sell on rallies in the near term. Any price recovery toward $3.00-$3.50 before the summer heatwave season demonstrates exhaustion should be treated as a distribution opportunity, not a momentum entry. The 50-day EMA between current prices and $3.50, the abundance of domestic production at 109.7 Bcfd, the weak shoulder season demand profile, and the market's repeated pattern of rejecting rallies above $3 since the January spike all support the fade-the-rally approach through April and May.

The $2.70-$2.75 zone is the immediate short-term floor. Below $2.70 on a daily close, $2.50 is the next target and a level where the risk-reward of adding long exposure for a Q3-Q4 position improves meaningfully. The medium-term bull case — LNG export pull tightening domestic supply, potential winter storage deficit from sustained Hormuz disruption, summer heat driving power burn above seasonal averages — all become relevant as the second half of 2026 approaches. Positioning for that bull case at $2.50 with a 12-18 month horizon is a defensible accumulation strategy. Buying at $2.87 into shoulder season weakness is not.

European TTF at $58.3 per MWh remains structurally elevated and is the better vehicle for expressing the medium-term war-risk premium on natural gas — it is directly exposed to the Ras Laffan and Hormuz disruption in a way Henry Hub is not. If the conflict persists through summer, TTF's path back toward $78 and higher is the more direct trade. Henry Hub follows with a lag of months, not weeks, through the LNG arbitrage mechanism.

Sell Henry Hub natural gas rallies above $3.00. Accumulate between $2.50-$2.70 for a Q3-Q4 position targeting $4.00+ if the winter storage deficit thesis materializes. The next six months will determine whether the Iran war permanently alters the global LNG supply chain in a way that eventually pulls Henry Hub meaningfully higher — or whether restored peace and Ras Laffan recovery send European TTF back toward $30-$35 and remove the one structural bull argument that could rescue domestic natural gas prices from their current range-bound malaise.

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