The frequency of negative power prices is predicted to reach record levels across parts of Europe after solar output hit new highs in the second quarter this year. That was the key takeaway from a new report on the European electricity market from energy data analyst Montel Analytics.
The study “European electricity market summary Q2 2025” highlighted a growing trend of negative prices across Europe, with Sweden’s SE2 price zone recording the largest number (506 hours) in the six months to the end of June 2025.
This was driven by unusually strong hydro inflows, transmission bottlenecks, changes to flow-based market coupling, and the continued increase in renewable capacity.
Montel’s research also shows that the number of negative hours exceeded 300 in Spain (459), the Netherlands (408), Germany (389), France (363), Belgium (361), Finland (363), and Denmark 1 (326).
Almost all European countries are seeing an increased number of such hours this year, with this trend likely to continue into the future.
Record levels of solar PV
The trend of below-zero prices was driven primarily by rising levels of solar generation, which hit a record high in the three months to June 2025.
Total solar output for Q2 was 104.4 TWh, with Germany (29.0 TWh), Spain (15.8 TWh), and France (9.9 TWh) the largest contributors.
The largest increases versus Q2 2024 were observed in Germany (4.9 TWh, 20 percent) and the UK (2.1 TWh, 40 percent), with France, Switzerland, Romania, and Belgium seeing growth rates of 30 percent or more.
While solar output was high, coal/lignite sunk to a record quarterly low of 52.5 TWh, a 11 percent drop on Q2 2024.
The biggest contributor to the decline was Poland, which saw a 22 percent and 16 percent drop in coal and lignite generation, respectively, versus Q2 2024, while Italy, Spain, Romania, and Hungary also saw large falls in relative generation.
Negative power prices are forecast to reach record levels across parts of Europe in Q3. This trend is being driven by continued renewable capacity expansion, particularly in solar, without a commensurate increase in underlying demand. Central and Western Europe are expected to see the widest spreads between midday solar output and evening demand peaks. Germany, the Netherlands, and Belgium are likely to continue experiencing sharply negative prices in the afternoon, followed by high prices in the evening as fossil fuel capacity ramps up. A similar pattern is emerging in parts of southeastern Europe. However, limitations in grid infrastructure and cross-border interconnection capacity are expected to reduce this region’s ability to benefit from lower prices in neighbouring markets, said Jean-Paul Harreman, Director at Montel Analytics.
Regional stress points becoming apparent
The Montel report also highlighted regional stress points that were impacting hydro and thermal generation, with central, southern, and southeastern Europe currently experiencing lower reservoir levels compared to the same period in 2024.
If above-average summer temperatures persist, this could elevate the risk of supply tightness, both in terms of hydro generation capacity and river navigability.
Low reservoir levels may also translate into lower river flows, which would affect levels of thermal generation.
Continued geopolitical impacts
Geopolitical developments are expected to remain a dominant force in European power markets, with the ongoing conflict in Ukraine, instability in parts of the Middle East, and evolving energy policy positions in the United States contributing to continued volatility in global liquefied natural gas (LNG) and gas markets.
In turn, these factors are likely to place further upward pressure on European wholesale gas and electricity prices as countries take additional steps to secure gas inventories ahead of the 2025-2026 winter season.
For industrial buyers and large consumers, this quarter may be marked by significant price volatility. The simultaneous occurrence of extremely low and extremely high intraday prices, driven by solar output patterns, nuclear constraints, and infrastructure limitations, presents both operational challenges and procurement risks. Energy Intensive Industries are advised to monitor market developments closely and evaluate exposure to peak pricing events, particularly during late afternoon and early evening, said Jean-Paul Harreman.
Constrained outlook
Q3 2025 is also expected to be characterised by ongoing constraints in relation to the French nuclear fleet.
Corrosion-related outages remain a factor, with output management expected to involve ongoing modulation around demand and renewable supply.
One critical variable is water temperature. Restrictions on cooling water use, triggered by elevated river temperatures, may constrain nuclear output, particularly during peak afternoon heat.
Knock-on effects may be seen in the early evening ramp, where neighbouring countries reliant on French exports may be forced to activate more expensive domestic thermal generation as solar output declines.
The French nuclear issues, combined with negative prices, geopolitical risks, hydro constraints, and interconnection bottlenecks, create a challenging environment for European leaders as they attempt to transition to a net-zero future.
Together, these dynamics paint a complex picture: one in which record-low prices and record-high evening peaks may co-exist, underscoring the structural challenges facing Europe’s transition-era electricity system, concluded Jean-Paul Harreman.
