Natural Gas Price Forecast: NG=F Stays Pinned Near $4 as LNG Pull Beats Warm Weather

Natural Gas Price Forecast Hook: NG=F is pinned to the $4 strike—and the next $0.50 move is waiting on one catalyst

The $3.95–$4.11 pivot is the whole trade right now for NG=F

NG=F is behaving like a market with two competing truths that refuse to resolve. One screen says “winter is losing intensity” as forecasts tilt warmer into early January. The other screen says “the system is exporting like crazy,” with LNG feedgas running near 18.5 Bcf/d for December, above November’s record pace in the same flow-tracking commentary. That’s why you can see pricing clustered around the psychological $4.00/mmBtu line: $4.11 indicated with a prior close near $3.98, while intraday trade in the prompt month has been quoted around $3.950 (down 3.4 cents at 2:23 p.m. ET in the midday snapshot).

Supply still looks like a record machine, but the demand downgrade is the part that changed

Lower-48 output is being treated as effectively “ceilinged high,” cited around 109.6 Bcf/d in December. In a normal winter, that would be enough to lean bearish by default. The problem for bears is that weather-driven demand is the only lever that can overwhelm that supply quickly, and forecasts are doing the opposite in the near term. The same widely circulated projections described total U.S. demand (including exports) easing from roughly 144.6 Bcf/d this week toward 127.5 Bcf/d across the next two weeks as warmth trims heating loads. That step-down is the cleanest explanation for why rallies keep stalling even with winter on the calendar.

Storage is the scoreboard, and it’s giving bulls just enough oxygen

The U.S. storage number anchoring this setup is the 167 Bcf withdrawal for the week ended Dec. 12, leaving inventories near 3,579 Bcf. That level was framed as slightly above the five-year average but below year-ago. Translation: not a crisis, not a glut. Separately, a storage preview estimate flagged a ~170 Bcf withdrawal for the week ending Dec. 19, which matters because it implies the winter buffer can tighten fast if January delivers even a modest cold turn. In a holiday-thinned market, that’s enough to keep downside moves violent but short-lived.

The LNG pipe is the market’s “floor,” and the shipment math backs it

U.S. gas is no longer a closed domestic loop. Export pull is visible in both flows and shipping. One weekly update cited 33 LNG vessels departing U.S. ports in the week ending Dec. 17, totaling about 126 Bcf of capacity moved offshore. That same update also noted a tanker arriving at Golden Pass as an initial cool-down cargo, a commissioning step that signals incremental capacity is moving closer to service. When LNG feedgas holds near 18.5 Bcf/d, every warm revision needs to be larger to break NG=F decisively lower, because exports are absorbing molecules that used to drown domestic balances.

Europe is quiet today, but Europe is not “safe”—storage is the vulnerability

Europe’s benchmark pricing is telling a calm story on the surface. Dutch TTF front-month was cited around €27.95/MWh in early trade and around €27.86/MWh in another reference point, roughly $9.61/mmBtu by the cited conversion. The reason this matters to NG=F is not the day-to-day TTF tick; it’s Europe’s dependence on LNG when storage is thinner than the last couple winters. EU storage was cited near 67.24% and separately “about 67%” as of Dec. 20, versus roughly 95% at the same point in 2022. That storage delta is why Europe can look relaxed at €27–€28/MWh and still be one cold snap away from pulling harder on Atlantic cargoes, which tightens LNG netbacks and reinforces U.S. feedgas demand.

Asia is the soft side of the LNG equation, and that softness is pressuring global prices

Spot LNG in Northeast Asia was assessed around $9.50/mmBtu for February delivery, described as a 20-month low and the weakest since April 2024. That is a direct signal that Asian buyers are not bidding aggressively for marginal cargoes right now. When Asia is soft and Europe is merely steady, the market leans into the “2026 glut” narrative—and that narrative bleeds back into how traders cap rallies in NG=F near $4 unless weather forces them out.

Regional U.S. cash pricing shows why futures can look stable while the ground is moving

The cash market is still broadcasting localized stress and dislocations even while the futures strip tries to behave. Midday spot quotes showed Tenn Zone 6 200L North at 3.86, Algonquin Citygate at 3.63, and the same Algonquin price repeated for a non-G listing, while parts of the West Texas footprint showed negative prints like El Paso – Keystone Pool at -1.26 and Transwestern at -1.295 (including the W. TX listing). That spread profile tells you infrastructure and regional constraints remain powerful, and it also explains why headline futures can drift while certain hubs are effectively living in a different market.

Australia just injected a structural shock into the 2027 LNG balance

The most important policy item in today’s dataset is Australia’s east-coast gas reservation plan for 2027. The stated structure is to require LNG exporters to reserve 15% to 25% of gas for domestic use beginning in 2027, applying to new contracts. For global gas pricing, the key is not the headline politics; it’s the forward volume implication. Australia is a major LNG supplier into Asia, and anything that limits exportable surplus at the margin becomes a forward-support factor for LNG benchmarks if demand surprises higher or shipping constraints tighten. Even if the effect is delayed, traders model these rules early because LNG contracting is long-cycle.

Russia-to-China pipeline flows are rising, but the value gap keeps LNG relevant

Pipeline flows into China via Power of Siberia were cited as expected up roughly 25% in 2025, reaching about 38.6–38.7 bcm, slightly above the planned annual capacity. The market implication is nuanced: more pipeline gas can reduce China’s urgency for spot LNG, reinforcing the current softness around $9.50/mmBtu. But the same dataset also emphasized the revenue gap versus the lost European market and the pricing friction around future projects like Power of Siberia 2—meaning the pipeline story does not automatically translate into unlimited cheap gas for Asia. LNG remains the balancing instrument, and Europe remains the swing buyer when storage drops toward uncomfortable levels.

Sanctioned LNG volumes are reappearing at the margins, and winter is when margins matter

A tanker named Kunpeng was cited as loading LNG from Russia’s Portovaya LNG terminal under Western sanctions. The timeline given was arrival Dec. 18 and departure with cargo on Dec. 21, described as the first time that vessel lifted LNG from the designated project. This is not a giant volume event by itself, but winter markets price “marginal barrels.” Even small flows can influence prompt spreads if enforcement is uneven or if routing workarounds become more common. That uncertainty is a volatility premium for Europe—and by extension, it’s another reason U.S. LNG demand is treated as sticky.

The U.S. LNG growth pipeline just lost one future barrel, and that changes the 2026–2027 debate

Energy Transfer suspended development of its Lake Charles LNG project, with capacity cited around 16.45 million tonnes per annum, citing cost pressures and a strategic preference to focus on pipeline projects while remaining open to third-party discussions. When the market is already talking about a “global glut in 2026,” a high-profile pause matters because it forces traders to separate “paper supply” from “real steel in the ground.” If demand from power generation, industry, or data-center load surprises higher, delays like this can tighten balances faster than the consensus expects.

Inflation data is quietly tying natural gas back into macro risk—and it’s not hypothetical

One data point in your set that traders often underestimate is the consumer pass-through channel. U.S. inflation was cited as easing to 2.7%, while the commentary stressed that higher natural gas prices in November and early December can still feed into later readings. The macro significance is straightforward: if gas prices remain elevated into peak winter billing cycles, it keeps energy as a live inflation component, which can shift rate expectations at the margin—especially if cold weather hits and headline CPI energy re-accelerates.

Europe’s “lowest level in nearly two years” story is real, but it is built on U.S. LNG dominance

European coverage in your data framed prices as falling to their lowest levels since early last year, driven by surging LNG imports from the U.S. and expectations of a supply glut in 2026. Two numbers anchor that narrative: the U.S. is supplying roughly three-fifths of Europe’s LNG imports, and EU storage is around 67% now versus roughly 95% at the same point in 2022. That combination is the new European regime: lower prices because LNG is available, higher fragility because the region is structurally dependent on LNG and storage is not the fortress it was in 2022.

Poland is a useful case study: LNG infrastructure is now the strategic asset

Poland’s LNG terminal at Świnoujście is highlighted as critical to energy security, and that matters because it’s emblematic of Europe’s post-crisis infrastructure shift. Consumption is projected to peak around 2030 before declining, which tells you why Europe can simultaneously invest in LNG terminals and still see a long-run demand plateau. In pricing terms, it supports the idea that Europe wants optionality: enough infrastructure to survive shocks without overpaying for molecules in normal conditions.