Natural gas markets closed the week with a split personality: U.S. futures bounced off fresh lows even as milder weather forecasts capped upside, European prices ticked higher on weaker wind output, and Asian spot LNG fell to its lowest level since April 2024 as demand stayed soft.
The result is a global gas story defined by abundant supply, weather-driven volatility, and a growing debate over how profitable incremental LNG exports will be as price spreads narrow—all while major policy and project decisions reshape the outlook for 2026 and beyond.
Natural gas price snapshot: the key benchmarks traders watched on Dec. 19, 2025
Here’s where the most-followed gas markers stood during Friday’s session:
- U.S. Henry Hub (NYMEX front-month, January): settled at $3.984/MMBtu, up about 2% on the day, after a volatile week. [1]
- Europe TTF (front-month): around €28.05/MWh (about $9.63/MMBtu) in morning trade, lifted by lower wind output forecasts. [2]
- Asia spot LNG (February delivery into Northeast Asia): estimated at $9.50/MMBtu, down from $10 last week and the lowest since April 2024. [3]
Those headline numbers mask a crucial nuance: the market is being pulled in opposite directions. On one side, weather forecasts reduce near-term heating demand. On the other, LNG export feedgas remains near record highs, keeping a firm bid under U.S. supply-demand balances even when the forecast turns warm. [4]
U.S. natural gas today: why Henry Hub swung between “warm winter” and “LNG pull”
U.S. gas traders spent Dec. 19 wrestling with one dominant question: Is this winter demand going to show up in time to tighten balances—or will mild forecasts and record output keep the market comfortably supplied?
1) Weather forecasts cooled the bull case
Reuters data cited in market coverage showed forecasts for mostly warmer-than-normal U.S. weather through Jan. 3, which tends to reduce heating demand versus seasonal norms. [5]
That warmth showed up in projected demand: LSEG estimates referenced in the same reporting pointed to Lower 48 demand (including exports) falling from about 144.6 bcfd this week to roughly 127.5 bcfd over the next two weeks—a meaningful step down for mid-winter. [6]
2) LNG export feedgas stayed near record highs
Even with mild forecasts, U.S. export pull remained the market’s stabilizer. Reported flows to the eight major LNG export plants averaged about 18.5 bcfd so far in December, above November’s 18.2 bcfd record. [7]
This matters because LNG demand is sticky—term contracts, cargo scheduling, and liquefaction operations can keep feedgas elevated even when domestic weather turns warm.
3) Record output is still the market’s “gravity”
On the supply side, LSEG data cited in the same coverage pegged Lower 48 production at about 109.6 bcfd so far in December, matching November’s record pace. [8]
In other words, the U.S. market is balancing:
- near-record production, and
- near-record LNG feedgas,
with weather changes determining which side “wins” from day to day.
4) The day’s price action showed the tug-of-war in real time
Two separate intraday storylines captured the volatility:
- In one update, the January contract was described sliding to about $3.879/MMBtu, near a seven-week low, as warm forecasts dominated. [9]
- Later, the same contract settled higher at $3.984/MMBtu, helped by export flows and a technical rebound from oversold conditions. [10]
That kind of reversal is classic “weather + positioning” natural gas behavior.
Storage check: inventories tightened, but the market still looks “not worried”
If you want a single indicator of whether traders fear winter scarcity, watch the calendar spreads.
On Dec. 19, Reuters market coverage noted that the March-over-April 2026 spread was trading around a record-low ~1 cent, signaling traders were not paying up for late-winter risk versus shoulder-season supply. [11]
Storage data also helped frame the picture:
- The latest EIA-reported week referenced in market coverage showed a 167 Bcf withdrawal (week ending Dec. 12), leaving working gas at 3,579 Bcf—about 32 Bcf above the five‑year average for that date, but below year-ago levels. [12]
- Forward-looking estimates embedded in the same market reporting pointed to an additional ~154 Bcf draw for the following report week (week ending Dec. 19), which would pull storage closer to (or slightly below) the five‑year norm depending on outcomes. [13]
Bottom line: withdrawals have been meaningful, but not yet “scarcity signaling.” The curve is still telling you the market expects supply to be adequate—unless weather surprises.
Europe gas prices today: TTF rose on weaker wind, but storage and supply capped the move
European wholesale gas moved up modestly Friday morning, and the reason wasn’t a sudden supply shock—it was power-market physics.
The front-month TTF contract was up around €28.05/MWh as forecasts for lower wind generation implied higher gas burn for power. [14]
But the upside was limited by a familiar set of anchors:
- Solid supply, including stable Norwegian flows cited in the same update. [15]
- Comfortable storage for this point in the season, with Europe’s gas storage reported around 68.2% full. [16]
The key European takeaway for Dec. 19: power-sector swings (wind output) can move the prompt contract, but storage and pipeline supply have kept rallies contained.
Asia LNG today: spot prices fell to a 20‑month low as demand stayed soft
Asian spot LNG extended its downtrend, with Reuters-reported market estimates putting February Northeast Asia spot LNG at $9.50/MMBtu, down from $10 the prior week and the weakest since April 2024. [17]
Why the softness?
- Analysts cited weaker Northeast Asian demand, supported by firm pipeline gas flows into China and strong Japanese renewable generation, both of which reduce LNG call. [18]
- Import appetite from China was described as limited at current levels, with pricing commentary indicating some buyers would prefer mid‑$8/MMBtu as a more compelling threshold. [19]
A separate, highly relevant datapoint: S&P Global reported Chinese domestic LNG prices fell to five-year winter lows, highlighting oversupply and muted demand conditions inside the region that can blunt spot LNG buying. [20]
LNG shipping and arbitrage: freight eased, and Europe kept winning cargoes
Shipping economics quietly reinforced the global split:
- Atlantic LNG freight was cited around $92,000/day, with Pacific around $75,750/day, according to Spark Commodities commentary embedded in Reuters coverage. [21]
- The same update noted that U.S. arbitrage routes to Northeast Asia were effectively pointing toward Europe, reflecting where netbacks looked better after considering price differentials and freight. [22]
That matches the bigger theme of late 2025: Europe continues to act as the balancing market—absorbing flexible LNG when Asia demand is price-sensitive.
The headline project shift: Energy Transfer put Lake Charles LNG “on ice”
One of the most consequential pieces of Dec. 19’s natural gas news wasn’t a price tick—it was a project decision.
Energy Transfer said it would suspend development of the Lake Charles LNG export project, citing a mix of rising costs, global LNG oversupply concerns, and a strategic preference for pipeline investments. [23]
Why this matters for natural gas markets:
- It’s a reminder that even in a world of booming U.S. LNG exports, not every proposed terminal will reach final investment decision—especially when the market is staring at a future supply wave and thinner margins. [24]
- It also underscores a growing investor question: are LNG returns becoming more sensitive to spreads and costs, rather than just “export more volume”?
Profitability and spreads: the LNG margin squeeze is back in focus
A Dec. 19 analysis piece highlighted that the profit window for spot U.S. LNG cargoes has tightened, as U.S. gas prices rose while Europe and Asia LNG prices softened—compressing the spread exporters rely on. [25]
Reuters commentary earlier in December similarly pointed to the Henry Hub–TTF spread shrinking and warned that if spreads narrow enough, some LNG volumes could become uneconomic versus variable costs, particularly in a more oversupplied global market later this decade. [26]
This is the crucial “second layer” of today’s market:
- High LNG feedgas today can support Henry Hub,
- but compressed international prices can limit how high export demand can go before economics start pushing back.
Forecasts: what’s next for natural gas prices and LNG in 2026?
Forecasts published and referenced around this period converge on a clear near-term message: winter strength, then moderation—but with plenty of volatility risk.
EIA: higher winter prices, then easing in early 2026
EIA’s December Short‑Term Energy Outlook projected:
- Henry Hub averaging almost $4.30/MMBtu this winter (Nov–Mar),
- then moderating with milder-than-normal weather in early 2026 and rising output, with prices averaging about $4.00/MMBtu next year. [27]
EIA also projected the annual Henry Hub price at $3.56 in 2025 and $4.01 in 2026, alongside rising U.S. LNG exports (about 14.9 bcfd in 2025 and 16.3 bcfd in 2026 in the STEO overview). [28]
Goldman: higher U.S. gas prices to incentivize production; softer Europe later
A Reuters-cited Goldman outlook projected TTF around €29/MWh in 2026 and €20/MWh in 2027, while forecasting U.S. gas around $4.60/MMBtu in 2026 and $3.80/MMBtu in 2027—a framework aimed at balancing supply growth with rising LNG-linked demand. [29]
Geopolitics and policy: Europe’s Russian gas exit and a major Israel–Egypt export deal
Two structural stories continued to shape sentiment in the background:
- The European Parliament backed plans aimed at phasing out Russian gas, including Russian LNG and pipeline supply, on timelines extending into 2026–2027. [30]
- Israel approved what was described as its largest natural gas export deal, supplying Egypt from Leviathan under a long-term framework (through 2040 or until value thresholds are met), reinforcing the Eastern Mediterranean’s role in regional gas flows. [31]
These don’t necessarily move Henry Hub day-to-day, but they influence where LNG goes, how hard Europe competes for supply in cold spells, and how new supply projects are justified.
What to watch next week: the 5 catalysts that can move gas fast
- Weather model updates (especially any shift toward colder-than-normal in late December/early January). [32]
- LNG feedgas levels—whether flows stay near ~18.5 bcfd or soften on operational changes. [33]
- Next storage report expectations—the market has been pricing a sizable follow-on draw after the 167 Bcf withdrawal. [34]
- Europe’s wind generation and storage trajectory—a sustained wind lull can lift prompt gas burn even in a well-supplied system. [35]
- Asian demand signals—China’s domestic oversupply and price weakness remain a headwind to spot LNG buying. [36]
References
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