Weather risks and geopolitics continue to shape European energy markets

Analysis of European wholesale energy prices between 2024 and 2025 shows the broadly declining trend of recent years giving way to a more mixed and volatile performance, as weather-related factors and geopolitical developments emerged as decisive market drivers. The shift was evident at the start of 2025, when an unusually windless winter in Central and Western Europe weighed on wind output. Compounded by cold spells, this increased reliance on coal and gas-fired power generation. Faster gas storage withdrawals followed, prompting a rally in front‑month gas prices and reviving speculation over possible intervention in the following summer amid rigid winter inventory targets.

Any rally, however, proved short‑lived. Fears of a potential return of Russian pipeline gas amid shifting US–Russia relations, combined with regulators signalling greater flexibility, and later easing, gas storage targets, triggered a sharp correction. Meanwhile, lacklustre Asian gas demand following a warm winter sharply reduced Chinese LNG imports, down around 22% in the first half of 2025. At the same time, new supply sources, including the US Plaquemines LNG plant, added to global availability. These factors reinforced a bearish shift in market sentiment by the end of 2025, even as European gas storage failed to adequately refill ahead of the 2025/26 winter.

Power markets were strongly influenced by weather conditions amid ongoing renewable integration. Solar output rose by around 20%, while wind generation fell below 2024 levels despite capacity additions. This reflected persistently weak wind conditions, particularly in the first half of the year. Hydropower output fell year on year following record levels in 2024. French nuclear output rebounded to around 370 TWh, the highest since 2019, on improved reactor availability despite increased modulation. This, however, was more than offset by lower generation in Sweden, Great Britain, Switzerland, and Belgium, leaving European nuclear output marginally below 2024 levels. Power demand recovered by just 0.5% year on year, constrained by persistent industrial headwinds from global competition and high energy costs. European governments were thus prompted to roll out measures aimed at reducing electricity prices, which in most European markets increased year on year.

Despite a generally weak macroeconomic conditions, power-sector emissions remained broadly unchanged. Meanwhile, lower free allocation and auction volumes created a 40-50 Mt deficit in the EU carbon market, pushing EUA prices more than 20 EUR/tCO2 above 2024 levels and partly offsetting lower gas prices. This further eroded the profitability of coal and lignite generation, which became largely uncompetitive during 2025 despite coal prices falling by more than 23 USD/t amid subdued demand, particularly from China. While coal and lignite capacity closures continue across Europe, Germany signalled in late 2025 that it may temporarily pause further shutdowns until around 10 GW of new gas-fired capacity is in place.

On the geopolitical front, mid-year US military action against Iran, escalating tensions involving Israel, an intensifying US-led trade war, and ongoing Russia-Ukraine conflict–related strikes on energy infrastructure disrupted global commodity flows and heightened supply-side risks. Towards the end of 2025, the increased US naval presence off Venezuela led to President Maduro’s removal from power, though ample global supply buffers muted the structural market impact.

Looking ahead to 2026, geopolitical developments are expected to remain a key driver of European energy markets. Persistently strained Russia-Ukraine relations and renewed US geopolitical signalling, including potential tariffs on countries trading with Iran, could disrupt global trade flows, particularly affecting relations with China and India. On the fuels side, Europe will need to balance low gas inventory risks against timely new LNG supply additions and subdued Asian demand, while declining carbon certificates supply is expected to push EUAs closer to abatement costs, likely above 100 EUR/tCO2.

French nuclear output and renewable capacity additions are expected to remain strong and, along with lower gas prices, weigh on spot power prices, particularly in Western Europe. At the same time, continued solar growth is likely to increase negative-priced hours, although expanding battery deployment may limit price depth. In Eastern Europe, power prices should be supported by higher carbon prices and reduced imports from non-EU countries, due to CBAM-related costs. However, the latter impact is expected to be more limited following the shift to a less restrictive, grid-based emissions-intensity definition. We will continue to closely monitor these developments and assess their implications for European energy markets.

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