Natural Gas Price Forecast: Henry Hub Holds Around $4 as EIA Draw Hits 167 Bcf

Natural Gas (NG=F) Price Snapshot Around $4.00–$4.12 On December 18, 2025

Front-month NYMEX Henry Hub NG=F (January 2026) is trading around $4.09–$4.12 per MMBtu after settling the prior session near $4.024. Price has bounced cleanly off the $4.00 area, which is acting as a tactical floor rather than giving way to a deeper flush. The recent tape shows a classic winter correction and rebound: an oversold slide on warmer forecasts, followed by a gap higher as buyers defend $4.00 into a large storage withdrawal. Volatility is elevated but contained inside a broad $3.80–$4.50 band, which reflects a market that fully prices winter risk but does not see a structural supply shock. In the global complex, Dutch TTF month-ahead trades near €27.57/MWh, roughly high-$9 per MMBtu, and Asia’s JKM benchmark sits around $9.5 per MMBtu, confirming that Europe and Asia are firm but not in 2022-style panic. Against that backdrop, Henry Hub near $4.10 is a mid-range winter price: high enough to ration marginal demand and reward producers, but not high enough to signal an emergency.

Seasonality, Technical Structure And Volatility In Natural Gas (NG=F)

Technically, NG=F has transitioned from a sharp selloff to a stabilizing recovery at a seasonal inflection point. The market gapped higher off the $4.00 region and is now testing the 50-day EMA from below, turning that moving average into the first serious line in the sand for short-term trend direction. The 200-day EMA around $3.60 sits as deeper structural support and marks the zone where medium-term bulls will likely defend aggressively if weather or sentiment deteriorate. The prior spike toward $5.50 showed how quickly natural gas can overshoot when winter risk reprices; that high remains the natural upside reference if a colder-than-normal pattern locks in while LNG flows stay near records. Short-term oscillators had reached oversold territory before the rebound, and positioning data indicated that speculative length had been heavily reduced, which is exactly the configuration that supports violent mean-reversion rallies into strong storage draws. The price reaction to recent news confirms this dynamic: futures bounced ahead of the EIA release on technical relief and winter anticipation, then pared gains when the draw came in strong but not at the top of the whisper range. The result is a chart that leans constructive above $4.00 but still respects the longer down-impulse from the $5.50 area, with daily volatility driven mainly by storage and forecast surprises.

Storage Dynamics: 167 Bcf Withdrawal, Regional Draws And Inventory Positioning

The latest EIA report is central to the current NG=F setup. Working gas in storage fell by 167 Bcf for the week ending December 12, 2025, taking inventories to 3,579 Bcf. That withdrawal is far above the five-year average near 96 Bcf for the same week and above last year’s 134 Bcf draw, confirming that early-December cold still bites hard when Arctic air aligns with demand centers. Even after this outsized pull, the national balance looks tight but not stressed. Inventories stand about 1.7 percent below the year-ago mark around 3,640 Bcf, yet remain roughly 0.9 percent above the five-year average of 3,547 Bcf. The big surplus that cushioned prices earlier in 2025 has largely disappeared, but there is no outright deficit. That middle ground is exactly what makes the tape hypersensitive to each new forecast run. Regionally, the Midwest posted a 64 Bcf withdrawal, leaving stocks near 966 Bcf, while the East drew 46 Bcf to roughly 797 Bcf. The South Central region, heavily influenced by LNG terminals and industrial load, saw a 48 Bcf draw and now sits around 1,242 Bcf. These numbers explain why basis volatility continues to flare in the core heating regions even when total U.S. storage looks “average.” A few more weeks of 160–180 Bcf withdrawals would compress the margin over the five-year average and force traders to reprice the tail-risk of a late-winter squeeze. Because the latest 167 Bcf draw landed slightly below the most aggressive expectations near 180–185 Bcf, futures initially faded part of the pre-report rally, but the structural message is unchanged: storage is no longer comfortably loose, and weekly weather surprises now have more leverage over price.

LNG Exports Versus Near-Record Production: Dual Engines Driving Natural Gas (NG=F)

The structural push-pull under NG=F is the combination of near-record LNG exports and still-elevated U.S. production. Feedgas to U.S. LNG plants is running around 18.5–18.6 Bcf per day so far in December, building on November’s record levels. That means roughly one out of every six cubic feet produced in the Lower 48 is being converted to LNG and shipped offshore. This export pull acts as a constant demand anchor that prevents domestic balances from loosening too quickly when U.S. weather turns mild. Even short-lived outages at key facilities such as Freeport LNG in Texas have shown up in price behavior, with mid-week reports of higher intake signaling a liquefaction train returning after disruptions and helping stabilize futures above $4.00. On the supply side, Lower-48 dry gas output is averaging about 109.5 Bcf per day so far in December, only marginally below November’s record pace. That production base is the main reason every rally toward $4.50–$5.00 faces heavy selling: as soon as heating demand drops back toward normal and export flows flatten, high output allows storage to rebuild rapidly. For NG=F, this creates a bounded range defined by LNG-driven support on dips and production-driven selling on spikes. The price around $4.10 reflects that balance almost perfectly: strong enough to justify robust drilling and LNG utilization, yet still consistent with a market that expects ample supply once winter passes.

Weather Outlook In The U.S. And Europe: Warm Bias, Cold Shots And Demand Risk For Natural Gas (NG=F)

Weather is the critical short-term wildcard for NG=F over the next two weeks. U.S. forecast models still lean warmer-than-normal into roughly January 1–2 across major demand regions, a pattern that suppresses heating degree days and reduces the urgency of storage withdrawals. Market commentary already anticipates a meaningful step-down in total U.S. demand, including exports, for the week following the 167 Bcf withdrawal, which explains why futures have struggled to extend gains beyond the low-$4 area despite strong recent draws. The December 12 data nonetheless prove how quickly balances can tighten when Arctic air penetrates the Midwest and East for several days, and this asymmetry keeps risk skewed to upside spikes on any colder turn. In Europe, the picture is similar but shifted to different benchmarks. Dutch TTF month-ahead near €27.57/MWh and firmer UK day-ahead prices show that colder short-term forecasts and modestly lower storage versus last year are adding some risk premium back into the curve, but the absence of major supply interruptions keeps prices in a controlled range. European storage sits around 68.75 percent of capacity compared with about 77.5 percent a year earlier, a gap that becomes more meaningful if late December and January bring sustained cold spells. For now, both U.S. and European gas markets are trading weather momentum rather than systemic scarcity, and each model update has the capacity to swing NG=F several percent in either direction.

Transatlantic Benchmarks: Henry Hub, Dutch TTF, UK Gas And Asian JKM For Natural Gas

The global benchmark structure confirms that Natural Gas is in a firm but not crisis regime. Henry Hub around $4.10 per MMBtu sets the anchor for U.S. pricing, while Dutch TTF in the high-€20s per MWh converts to roughly the high-$9 per MMBtu range. The UK day-ahead contract has also been trading firmer, in line with colder weather signals and ongoing dependence on LNG and Norwegian pipeline flows. In Asia, JKM continuous futures around $9.5 per MMBtu show that Pacific basin buyers are not being forced into extreme bids to secure winter volumes. Reuters reporting that benchmark spot gas in Europe and Asia has hovered near the $9 per MMBtu area for much of the early winter underscores this point: the world is tight enough to support current prices but not tight enough to generate 2022-style shock spikes. Asia’s reduced intake of U.S. LNG in 2025, driven primarily by lower Chinese buying amid trade tensions, has allowed more U.S. cargoes to compete for European destinations and other markets. This diversification moderates regional price blowouts but reinforces global interdependence: a sudden outage at major LNG export plants or a sharp, synchronized cold shot across Europe and Asia would transmit almost immediately into Henry Hub and NG=F via higher netbacks.

Pipeline Constraints And Basis Volatility In North American Natural Gas Hubs

Regional pipeline dynamics continue to generate localized price spikes even when national benchmarks look orderly. Near the U.S.–Canada border in western Canada and the Pacific Northwest, natural gas prices surged earlier in the week amid scheduled maintenance on the Westcoast Energy T-South system before easing back as flows adjusted. Northwest Sumas cash prices jumped by $1.26 from Monday to Tuesday, briefly topping out near $4.055 per MMBtu during a late November cold snap, before sliding back to about $2.34 per MMBtu as constraints began to ease. At Westcoast Station 2, Canadian hub prices ripped from only C$0.425/GJ on Monday to C$2.160/GJ by Wednesday, highlighting how sensitive constrained systems are to even planned inspections. The T-South line, roughly 570 miles long, moves about 1.8 Bcf per day from northern British Columbia toward the U.S. border, with Huntingdon throughput capacity around 2.02 Bcf per day. Recent inspection work trimmed actual receipts at Huntingdon to around 1.71 Bcf per day from 1.93 Bcf per day, translating into roughly 0.17 Bcf per day of gas that suddenly lacked its usual egress. With limited alternative routes—mainly eastward via NGTL and Foothills to Kingsgate, with capacity near 3.0 Bcf per day—the market reacted with outsized basis moves. For NG=F, these localized dislocations serve as a reminder that infrastructure constraints can produce sharp regional premiums even when national storage and production look comfortable.

Market Structure, Financialization And Growing Role Of TTF And JKM In Natural Gas Hedging

The financial structure around Natural Gas continues to deepen, particularly in Europe and the LNG-linked paper markets. Record volumes in TTF futures and options on ICE, alongside record trading in JKM LNG futures, show how benchmark contracts have become central tools for managing global gas risk. Higher liquidity in these contracts cuts both ways. On one hand, it improves hedging efficiency for producers, utilities and industrial buyers; on the other, it means price moves can accelerate when large positioning shifts collide with abrupt changes in weather models or supply news. The stronger link between Henry Hub, TTF and JKM via arbitrage and LNG flows also tightens the correlation between NG=F and global benchmarks. When European or Asian markets reprice significantly higher on weather or supply stress, U.S. exporters gain pricing power, and marginal North American molecules are pulled more firmly into the export channel. Conversely, if global prices stay anchored near $9 per MMBtu while U.S. production grows, LNG netbacks cap upside for NG=F, and domestic futures may struggle to sustain levels far above today’s $4–$5 band without a distinctly colder-than-normal winter.

Official Forecasts: EIA Outlook For Henry Hub And End-Of-Winter Natural Gas Inventories

The EIA’s Short-Term Energy Outlook frames the base-case trajectory for Natural Gas (NG=F) beyond the current weather noise. For the winter heating season (November through March), the EIA projects Henry Hub spot prices averaging around $4.30 per MMBtu, modestly above current levels and consistent with a market that prices some winter premium without assuming extreme scarcity. The agency’s assumptions include December heating degree days running above the 10-year average, which supports higher space-heating consumption and validates larger-than-normal early-winter withdrawals like the recent 167 Bcf draw. Even so, the EIA still expects end-of-winter storage around 2,000 Bcf, a figure that remains above the five-year average in its forecast tables and implicitly assumes that production growth offsets much of the weather-driven pull. For full-year 2026, the EIA projects an average Henry Hub price near $4.01 per MMBtu alongside rising U.S. output and continued expansion in LNG exports. That combination signals a structural view that higher production will ultimately contain prices once winter passes, barring a sequence of extreme cold events or major supply disruptions.

Short-Term Trading Drivers For Natural Gas (NG=F): Storage Prints, Weather Models And LNG Feedgas

Over the next 7–14 days, NG=F will remain dominated by three short-term levers: the weekly EIA storage data, high-frequency weather model updates and daily LNG feedgas flows. The December 18 storage report delivered a 167 Bcf withdrawal and pushed inventories to 3,579 Bcf, but the way futures reacted—initial strength, then partial fade—shows that price is driven as much by expectations versus actual prints as by the absolute numbers. The next report, scheduled around December 24 with holiday-adjusted timing, may carry outsized influence because liquidity typically thins into year-end, amplifying the impact of surprises. Weather models for the U.S. and Europe remain the most powerful volatility trigger, with even modest shifts toward colder patterns capable of adding or subtracting tens of Bcf from weekly demand forecasts and forcing rapid repricing. Meanwhile, LNG feedgas near record highs around 18.5–18.6 Bcf per day keeps a steady bid under cash demand. Any sustained decline in feedgas because of outages or unplanned maintenance would loosen the domestic balance quickly and pressure NG=F, whereas continued high utilization reinforces the floor under the $3.80–$4.00 region.

Medium-Term Risk Balance: Bullish Winter Case Versus Bearish Supply And Mild-Weather Scenario For Natural Gas (NG=F)

Medium-term, the risk balance for Natural Gas (NG=F) is defined by two opposing but credible narratives. In the bullish scenario, repeated cold shots across North America and Europe push weekly withdrawals consistently above average, driving U.S. storage meaningfully below the five-year line by late January. With LNG feedgas pinned near record levels and European storage already lower than last year, TTF and JKM benchmarks would likely grind higher, improving export netbacks and pulling Henry Hub and NG=F toward or above the $5.00 area. In that environment, producers gain pricing leverage, and any unplanned outages at LNG plants or key pipelines could add an extra volatility layer. In the bearish scenario, the current warm-leaning forecasts persist or strengthen, and U.S. degree days remain subdued through early January. Weekly withdrawals then normalize or undershoot expectations, storage tracks the EIA’s path toward roughly 2,000 Bcf with a comfortable margin, and record-near production keeps the system well supplied. Global benchmarks stay anchored near $9 per MMBtu, Asian demand for U.S. LNG remains soft, and European TTF trades sideways as LNG and Norwegian flows cover weather-adjusted needs. In that case, NG=F would struggle to hold above the low-$4 range and could test back toward the $3.60–$3.80 support band once winter premium decays.

Positioning View On Natural Gas (NG=F): High-Beta Winter Trade With Tight Stop Levels

Given today’s data, Natural Gas (NG=F) sits at an inflection that favors a cautiously constructive stance with tight risk controls. Henry Hub around $4.10 aligns closely with the EIA’s winter average projection, storage has shifted from surplus to near-normal with a 167 Bcf weekly withdrawal, LNG feedgas remains close to record highs near 18.5–18.6 Bcf per day, and U.S. production around 109.5 Bcf per day continues to cap runaway spikes. European TTF near €27.57/MWh and JKM around $9.5 per MMBtu indicate a firm but not panicked global market. Under these conditions, the asymmetric payoff for the next one to two months leans slightly bullish: a string of colder-than-expected weeks could lift NG=F back toward the $4.75–$5.25 zone, while a decisive warm continuation and soft storage prints could push prices down toward $3.60–$3.80. On balance, that distribution supports a tactical Buy bias on dips closer to $4.00 with clear invalidation below the $3.60 area, recognizing that this is a high-beta winter trade entirely dependent on weather, storage and LNG reliability rather than a structural multi-year investment case.

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