Natural Gas Price Forecast - NG=F Steady Near $4 as TTF Jumps on Colder Forecasts and LNG Outage Risk

Natural Gas NG=F Around $4: Weather, LNG and Storage Pull the Market in Opposite Directions

Global Gas Benchmarks Split: Henry Hub Near $4, TTF Around €27, JKM Near $10

Natural gas prices on December 17, 2025 are sending a very specific message: the global market is no longer in panic, but the floor is not secure. U.S. Henry Hub front-month futures NG=F are trading just under the psychological $4.00/MMBtu line, with recent prints around $3.97/MMBtu, a prior close near $3.886, and an intraday range roughly $3.920–$3.994. That close at $3.886 marked the weakest settlement since late October and capped a sharp pullback from early-December spot prices that briefly traded above $5.00/MMBtu before weather models flipped warmer. In Europe, the Dutch TTF front-month benchmark sits near €27–€28/MWh (about $9.4/MMBtu), hovering around the lowest levels since April 2024 and down roughly 45% year-to-date, even as the curve edges higher on colder and less windy forecasts into late December and January. The current snapshot has TTF around €27.50/MWh, up from a previous close in the mid-€26s as traders reprice heating and power demand risk. UK NBP day-ahead prices are firmer as well, echoing the same regional story. In Asia, the JKM benchmark sits around $10/MMBtu, near multi-month lows, reflecting a slow start to winter and ample LNG availability despite Europe’s day-to-day swings. The result is a three-speed gas world: U.S. NG=F grinding around $4 with a recent downside test; Europe’s TTF cheap in historical terms but suddenly sensitive to every cold model and LNG headline; and Asia’s JKM subdued, acting as a pressure valve for the global LNG chain rather than a source of panic bids.

Fundamental Drivers in the U.S.: NG=F Balances Mild Weather With Record Supply and Heavy LNG Pull

Under the surface of NG=F near $4 sits a straightforward set of fundamentals. On the demand side, U.S. weather models have shifted warmer than seasonal norms into late December, especially across major heating load centers. Forecasts show that heating demand for the Lower 48 will underperform a typical December by a clear margin, with estimates from major data providers pointing to a notable decline in total U.S. gas demand, including exports, from this week into next. That demand softening is the main reason the front month was “repriced” sharply lower from early-December levels above $5 toward the high-$3s. Supply is still the big cushion. U.S. dry gas production remains near record territory, with daily output only modestly dented by localized freeze-offs in some producing regions. That strong supply profile has kept U.S. storage slightly above its seasonal five-year average, muting the winter risk premium that typically appears when inventories draw down aggressively early in the heating season. Elevated stocks mean that even as weather turns colder later in the winter, the market does not yet feel like it is running on fumes. At the same time, LNG is now central to the NG=F story. Average feedgas flows to U.S. LNG export facilities are holding near record highs so far in December, with total U.S. LNG exports expected to reach around 14.9 Bcf/d this year, roughly 25% higher than 2024. That structural pull effectively transfers a growing share of U.S. surplus into Europe and Asia, tightening the domestic balance and putting a floor under Henry Hub that would not exist if the U.S. market were closed.

Freeport LNG and Outage Risk: Bearish for NG=F, Bullish for TTF and JKM at the Margin

The wildcard for both NG=F and TTF is operational risk at key LNG terminals. The shutdown of one liquefaction train at the Freeport LNG export plant in Texas immediately trims U.S. feedgas demand and temporarily leaves more molecules inside the U.S. grid. For Henry Hub futures, that effect is unambiguously negative: fewer cargoes leaving the coast remove some of the structural support that LNG normally provides at this time of year, especially when weather is mild. For Europe and Asia, the same event works in the opposite direction. If downtime persists, fewer U.S. LNG cargoes will be available to reload European and Asian buyers in peak-winter months, tightening the LNG supply stack and increasing the value of alternative sources such as Norwegian pipeline gas, Qatari volumes, and spot cargoes from other Atlantic Basin exporters. That is why TTF has firmed even while U.S. NG=F trades heavy: a single train outage is not a global crisis, but when EU storage is under 70% and winter has not peaked, any reduction in flexible supply is amplified in forward curves and options pricing.

Europe’s TTF: Cheap on a One-Year Chart, But Storage at 69.9% and Lower Wind Raise Upside Risk

European gas looks calm on the surface but is less comfortable on the fundamentals than headline prices suggest. TTF around €27/MWh is near the bottom of its 2025 range and roughly 45% lower than where it started the year, helped by high Norwegian pipeline flows and strong LNG imports. Norwegian nominations are running near 347 million cubic metres per day, the highest since August 2024, providing a reliable backbone to European supply. At the same time, U.S. LNG exports are at record levels, pushing molecules into European terminals and capping panic. The pressure point is storage and weather. EU gas storage is reported around 69.9% full, versus about 77.9% at this time last year, a meaningful gap heading into the coldest part of winter. As forecasts shift toward colder and less windy conditions into January, that storage deficit becomes critical. Less wind means more gas-fired generation, while lower inventories mean each cold spell triggers larger percentage draws. Spec positioning adds fuel: investment funds have built heavy gross short exposure in TTF, betting that mild weather and steady LNG flows will keep prices pinned. This creates a classic short-squeeze setup where even modestly colder revisions, a persistent Freeport outage, or unexpected noise in Norwegian flows can force rapid short covering, turning today’s €27 handle into a starting point for sharp upside spikes back into the €30s or beyond, even if the broader oversupply story remains intact.

Asia’s JKM and the Global LNG Chain: JKM at $10 Anchors a Soft Ceiling for NG=F and TTF

The JKM benchmark around $10/MMBtu tells you why neither NG=F nor TTF is exploding despite structural tensions. Asia entered winter with comfortable storage, diversified supply and a muted power-demand profile. That has kept JKM in a low double-digit range rather than the elevated teens that characterized earlier energy crises. As long as JKM trades near $10, global LNG buyers can arbitrage flows between Atlantic and Pacific basins without offering extreme premiums for spot cargoes. For NG=F, this means U.S. LNG exports can run near capacity without Asia bidding Henry Hub into a new regime. For Europe, it means TTF remains anchored by JKM: if European prices run too far above Asian levels, cargoes swing into the Atlantic; if TTF sinks too low, marginal Atlantic cargos are pulled back toward Asia. This three-way balance limits the upside on all benchmarks in the absence of a major supply disruption or an extreme cold shock.

Regional Cash and Basis: PNGTS, New England Volatility and Canadian Flows Show How Local Weather Still Bites

While front-month NG=F and TTF dominate the headlines, local basis markets remind you that physical gas remains intensely regional. In New England, cash prices along the Portland Natural Gas Transmission System (PNGTS) have whipsawed violently. After spiking on an earlier cold blast, PNGTS day-ahead prices have collapsed by about $9.20 to average roughly $8.095/MMBtu as a milder forecast into the rest of the week cut heating demand. At the same time, pipeline imports from Canada into the Northeast have been running above last year’s levels, while occasional Everett-area LNG cargoes continue to backstop the region. This combination of stronger import flows and softer local demand drives large day-to-day swings in cash prices even when NG=F looks tame. The message for broader Henry Hub pricing is clear: regional spikes can still occur, but with continental supply abundant and cross-border flows robust, these episodes are localized and increasingly fail to pull the entire U.S. curve dramatically higher.

Technical Structure in NG=F: Oversold Snapback Around $4, With $3.60 as a Deeper Accumulation Zone

Technically, NG=F is attempting to stabilize at a critical pivot. The January contract is trading around the $4.00/MMBtu level that has been discussed repeatedly by traders as a key psychological and chart area. The recent slide from above $5 into the high-$3s pushed short-term oscillators into oversold territory, prompting a modest rebound as short-term bears take profits. However, the market does not yet show a clean V-shape reversal. The classic ingredients of a strong bounce—decisive reversal candles, volume expansion and a break back above short-term moving averages—are still developing rather than fully present. As the January contract approaches its roll into February in roughly twelve days, open interest and liquidity will gradually migrate, often amplifying volatility around this price zone. From a pure support-resistance perspective, the $4.00 line is the first major test. If that level fails convincingly, the next area many desks are watching is around $3.60/MMBtu, which has been flagged as the next attractive accumulation zone for seasonal buyers. That $3.60 band aligns with earlier consolidation areas and would represent a sizeable discount relative to early-December highs, making it a natural level for utilities, hedgers and funds with a constructive 2026 view to re-enter.

Seasonality and Weather: Why Few Professionals Want to Aggressively Short NG=F Into Peak Winter

Seasonality remains the main reason you do not see deep institutional enthusiasm for shorting NG=F aggressively at $4. Natural gas is one of the most cyclical commodities in the market, with winter demand still dominating the annual profile. Colder temperatures are already back in parts of the United States and Canada, and the risk is that December’s relatively mild stretch gives way to a more severe pattern in January and February. Early-season cold snaps have already demonstrated how quickly storage draws can accelerate when heating load arrives on top of structural LNG demand. This is why, despite warm forecasts today, many traders prefer to treat current weakness as an opportunity to scale in rather than to chase the downside. Weather models for key hubs—Boston, New York, Philadelphia, Pittsburgh, Ottawa, Quebec City and other major demand centers—remain the intraday steering wheel for NG=F. Any abrupt shift to a colder pattern across those regions can quickly force shorts to cover and drive the front month sharply higher, particularly when the market has just been “repriced” lower on the assumption that warmth will persist.

Structural Demand: Power Load, LNG Growth and Data Centers Raise the Long-Term Floor for NG=F

Beyond this winter’s noise, the longer-term demand profile for NG=F is steadily gaining strength. On the power side, rising electricity consumption driven by electrification and steady economic growth is increasing gas-fired generation needs in multiple U.S. regions. Coal retirements and uneven renewable build-out mean that gas remains the marginal fuel in many grids. At the same time, the buildout of AI and cloud data centers adds another structural leg to long-term gas demand, even if it is not the primary driver of this winter’s pricing. These facilities require reliable baseload power, and a substantial portion of that incremental load will be backed by combined-cycle gas plants in regions where renewables and storage are not sufficient on their own. Layered on top of this is LNG. U.S. export capacity is expanding, and the industry expects that by the end of 2026 the U.S. will be consistently shipping around the current 14.9 Bcf/d or more, with new trains and terminals coming online. Each incremental train locks in long-term offtake contracts that effectively transform Henry Hub from a purely domestic benchmark into a global gas anchor. That dynamic is exactly why multiple institutional research desks argue that the long-run floor for NG=F is rising, not falling.

Forward Curve and Forecasts: EIA, Enverus and Sell-Side Views Converge Around a $3.5–$4.5 Henry Hub Band

The forward curve and official forecasts put numbers on that structural view. The latest U.S. Energy Information Administration projections have Henry Hub averaging close to $4.30/MMBtu across this winter (November through March), then settling around $3.56 in 2025 and roughly $4.01 in 2026. Those figures imply that the EIA sees the current near-$4 pricing as broadly aligned with medium-term fundamentals, with mild downward pressure once winter risk fades and gentle upward pressure as LNG exports and power demand continue to grow. Independent research outfits are more cautious about the very near term. One detailed 2026 outlook described the recent surge toward the mid-$5 area as premature and expects Henry Hub to trade around $3.80/MMBtu through the rest of the winter, easing toward roughly $3.60/MMBtu in summer 2026 as Lower-48 supply growth persists and weather normalizes. The curve itself has already adjusted: calendar 2026 NG=F pricing recently touched a one-year low around $3.75/MMBtu, signaling that traders believe the combination of robust production and structural demand will keep prices in a mid-$3s to low-$4s band rather than launching into an extended spike. At the same time, an array of industry and bank research calls for firmer Henry Hub pricing into 2026, anchored on surging power demand, larger LNG exports and a deliberate push by producers to rebuild reserves after years of capex restraint. That cluster of forecasts effectively brackets a medium-term range where downside below the low-$3s looks unsustainable and upside into the high-$4s requires a material weather or supply shock.

Europe and Asia Forward Balance: How TTF at €27 and JKM at $10 Feed Back Into NG=F

Forward expectations outside the U.S. feed directly into Henry Hub’s equilibrium. In Europe, the combination of TTF near €27/MWh, record Norwegian pipeline flows around 347 mcm/d, high U.S. LNG imports and storage at 69.9% of capacity makes it hard to argue for sustained triple-digit prices, but equally hard to argue for a structural collapse below current levels when winter has not fully played out and Russian pipeline volumes remain structurally constrained. In Asia, JKM near $10/MMBtu creates a soft ceiling on how high TTF and NG=F can run without pulling additional supply or demand response into the system. If Europe faces a colder-than-expected January, the first line of defense will be drawing more U.S. LNG into Atlantic routes; if Asia unexpectedly tightens, some of that flow will be diverted east, putting fresh upward pressure on Henry Hub. Either way, the presence of cheap Russian-linked pipeline supply has been structurally reduced by sanctions and policy decisions, while incremental gas demand in power and industry continues to grow. This reinforces the idea that global benchmarks are more likely to oscillate within a moderate range than to revisit the ultra-low levels of past cycles, barring a severe demand shock.

Short-Term Trading Dynamics: NG=F Futures, Volatility and Why the Market Keeps Getting “Repriced by Weather”

From a trading perspective, NG=F remains a market where the next weather run can erase the last twenty-four hours of narrative. Recent price action shows this clearly. Futures have slumped below $4.00/MMBtu when models stripped out late-December cold, then rebounded on marginally less bearish updates despite supply–demand fundamentals changing very little. Technical support zones have been adjusted lower as the contract flailed, with earlier floors giving way and a new support hierarchy forming around $4, then $3.80, then $3.60 on many charts. Each time forecasts lean warmer, speculative shorts pile in, pressing prices down; each time a bit of cold returns to the models, those shorts partially cover, leading to sharp intraday reversals. The presence of heavy algorithmic and systematic participation around weather-linked signals amplifies this effect. Options markets reflect the same dynamic, with implied volatility elevated around key storage report dates and major model update windows. For discretionary traders, this creates an environment where patience and scale matter more than micro-timing: trying to capture every sub-dollar swing is less relevant than deciding where the structural value zones lie over the next six to eighteen months.

Natural Gas NG=F Stance: Bullish Bias, BUY on Dips With $3.60 as Strategic Accumulation and $3.00 as Tail-Risk Floor

Taking the entire data set together—Henry Hub NG=F hovering around $3.9–$4.0, early-December spikes above $5 already unwound, TTF near €27/MWh and down about 45% on the year, JKM around $10/MMBtu, record U.S. LNG exports near 14.9 Bcf/d, Norwegian pipeline flows around 347 mcm/d, EU storage at 69.9% versus 77.9% last year, strong U.S. production, a mild-but-changeable winter forecast, and forward expectations clustering around $3.5–$4.5 for Henry Hub—the balance tilts toward a bullish medium-term view with tactical downside risk rather than a structurally bearish regime. At current levels, NG=F does not screen as a Sell: the combination of rising structural demand from power and LNG, a gradually higher industry-perceived floor, and significant upside optionality if January–February weather turns colder argues against being aggressively short around $4. It is also not a neutral Hold, because repeated repricing episodes driven by transient warm forecasts are delivering entry points that line up with multi-source 2026–2027 fair-value bands. The cleaner stance is BUY on weakness, with a clear risk map. The first strategic accumulation zone sits around $4.00–$3.80/MMBtu, where oversold conditions and seasonal risk begin to favor the long side. A deeper structural buying area lies near $3.60/MMBtu, which multiple analyses identify as the next logical support if the current bounce fails. Below that, the low-$3s should be treated as tail-risk territory where aggressive production responses and structural LNG pull would likely emerge. On the upside, a return toward the mid-$4s is consistent with EIA winter averages, and a move back above $5 becomes plausible if late-winter cold, persistent LNG strength or an extended Freeport outage tighten balances further. Based on the current numbers, Natural Gas NG=F is a high-volatility BUY with a bullish medium-term bias, with positions sized to survive weather-driven swings down toward the $3.60 area while targeting a recovery into the $4.50–$5.00 zone as the 2026 demand story and LNG expansion reassert themselves.

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