EIA Hike, LNG Delays and Winter Gas Rally —US & EU

Introduction

Natural gas dynamics shifted noticeably over the past week. A revised U.S. Energy Information Administration (EIA) outlook raised expected spot prices into late 2025/early 2026, an LNG export project was suspended, and governments in Europe and Australia announced policies with tangible supply implications. Combined with a small uptick in domestic drilling activity and unusual weather swings, these developments materially affect short-term price formation for Henry Hub and liquidity in LNG-linked contracts.

Key Drivers This Week

EIA’s short-term outlook lifts price expectations

The EIA’s latest Short-Term Energy Outlook pushed winter prices higher, citing a colder-than-normal forecast for the heart of winter. The agency raised its Henry Hub estimates to about $3.87/MMBtu for late 2025 and roughly $4.35/MMBtu for the first quarter of 2026. Those increases reflect expectations for larger-than-average storage withdrawals — December withdrawals were projected near 580 Bcf, roughly 28% above the five-year norm — which tightens the margin for error if demand surprises to the upside.

LNG supply growth hit by project suspension

Energy Transfer’s decision to suspend development of the Lake Charles LNG export terminal removes a planned source of export capacity in the near term. That facility would have added meaningful tonnage to U.S. export capability; its suspension limits the pace at which U.S. gas can be exported as LNG. For traders and portfolio managers, this acts like a temporary supply curtailment to the international demand channel — supportive for domestic prices, all else equal.

Policy shifts tighten future exportable volumes

Two policy moves have medium-term implications. The European Parliament advanced a timeline to phase out Russian pipeline and LNG supplies by 2027, signalling sustained import demand for non-Russian suppliers through the transition. Meanwhile, Australia’s announcement of a domestic gas reservation scheme for 2027 — requiring exporters to set aside roughly 15–25% of production — points to reduced exportable volumes from a major LNG supplier. Together, these policies increase the probability that buyers will competitively chase the same non-Russian barrels and LNG cargos, supporting global price floors tied to U.S. export economics.

Operational and Weather Factors

Rig count and production signals

Baker Hughes reported a modest increase in the U.S. rig count last week (+3 rigs, total ~545), while gas-directed rigs remained around 127. The uptick was oil-led but the overall increase hints at renewed upstream activity. For natural gas, steady gas rig counts mean production growth is unlikely to accelerate sharply in the immediate term — a neutral-to-supportive factor for winter balances.

Weather whiplash: cold forecasts vs. southern heat

Weather was a mixed signal. Long-range models and the EIA’s analysis point to a cold snap boosting heating demand and storage withdrawals. But a mid-December storm produced record-warm readings across parts of the southern U.S. (Dallas–Fort Worth near 79°F), temporarily shifting consumption to cooling-related power demand rather than heating. The net effect is a more complex demand profile for gas-fired power generation: higher overall electricity burn even as residential heating patterns vary regionally.

What This Means for Prices and Positioning

Near term: elevated winter price risk. The EIA’s upward revisions and the prospect of larger-than-average withdrawals suggest upward pressure on Henry Hub through Q1 2026, particularly if cold anomalies materialize in the Northeast and Midwest. The suspension of a major U.S. LNG project and Australia’s reservation rules reduce available exportable volumes over the medium term, which can support domestic price levels by limiting the growth of the exported demand channel.

Medium term: structural reallocation of flows. Europe’s move away from Russian supplies increases competition for U.S. and other non-Russian LNG cargoes. This is likely to compress arbitrage flexibility and may keep Atlantic-basin prices elevated relative to previous cycles as buyers secure reliable supply.

Trading and investment implications: favor hedges and basis protection for winter exposures, and evaluate long-dated optionality for producers and midstream operators. Pipeline and storage operators with winter capacity will see a relative uplift in value if withdrawals run higher than typical. Conversely, developers planning new export capacity should stress-test projects against higher construction costs and policy risk.

Conclusion

Over the past week, concrete supply-and-demand developments pushed natural gas fundamentals toward tighter winter balances: a firmer EIA outlook, a pause in a large LNG export project, and policy decisions that will reshape trade flows. Add unpredictable weather swings and a small increase in upstream activity, and the result is asymmetric upside risk to winter prices and sustained support for Atlantic-basin LNG values into 2026. Active risk management and selective exposure to midstream capacity and short-term hedges should be considered by investors positioning for the next two quarters.