In 2025, Ember reported that wind and solar generated 30% of EU electricity, overtaking fossil fuels at 29% for the first time. Solar alone supplied 13% of EU electricity and increased by more than 20% year-on-year for the fourth consecutive year. The shift is reflected in changing patterns of generation and pricing across European power markets.
EU generation milestone and implications for price formation
The same data point to solar becoming a major driver of wholesale price formation rather than a marginal technology. As solar output expands, it affects the hours when low-marginal-cost electricity is available to the system. That interaction influences how prices move throughout the day.
For Southeast Europe, the trend is linked to strong solar irradiation and demand growth for air conditioning. The region also has growing renewable pipelines alongside still-limited storage penetration. Greece, Bulgaria, Romania, Hungary and Serbia are described as facing a new daily pricing pattern.
Midday negative prices followed by evening price increases
The pricing pattern highlighted for the region features low or negative prices during sunny midday hours. Higher prices are then observed in the evening as solar generation declines. This daily shape is associated with how solar output ramps up and down over the course of the day.
The described mechanism matches the “duck curve” problem. Solar output rises quickly in the morning and reaches its peak around midday, when wholesale prices can fall sharply due to high volumes of low-marginal-cost generation. When the sun sets, solar output drops, and prices can rise if demand remains high and flexible resources are limited.
ACER findings on flexibility gaps and cross-border limits
The pattern is reported as already visible in Southeast Europe. ACER identified a lack of flexible resources to replace solar generation in the evening as a key driver behind 2024 summer price spikes. The agency also pointed to limited cross-border capacity affecting imports of lower-priced electricity during stress periods.
Those constraints affect how quickly lower-cost generation can be balanced when solar output falls. They also influence how regional markets respond during high-demand periods in the evening. The result is a pricing environment where midday conditions differ from later hours.
Solar capture prices under cannibalization pressures
The impact on project economics is described through how solar plants earn revenue based on hourly prices rather than an annual baseload level. As more solar enters the system, plants increasingly compete during the same production hours. That competition pushes down what is available for solar capture in those periods.
This dynamic is referred to as solar cannibalization. The first wave of solar benefits from higher daytime prices, while later waves reduce the value of those same daytime hours. The source links this to a merchant business case that becomes weaker for standalone projects as negative-price hours increase.
EU installation trends and curtailment-related business risks
SolarPower Europe warned that negative prices and curtailment are eroding business cases in the EU solar sector. The group reported that the EU installed 65.1 GW of new solar PV in 2025, slightly below 65.6 GW installed in 2024. This marked the first annual decline since 2016.
The same warning is framed as relevant for Southeast Europe, where solar is still expected to remain among the fastest-growing sources of new electricity. However, the commercial model is described as needing to evolve alongside market conditions. Standalone exposure to merchant pricing is presented as becoming riskier as negative-price hours expand.
Batteries, flexible offtake and intraday optimization options
The source lists project structures that may be better positioned under these conditions. These include adding batteries, using flexible offtake arrangements, entering corporate PPAs, providing curtailment protection, or applying intraday optimization. Industrial consumers able to shift load into midday hours are also described as potentially benefiting from lower daytime prices.
A separate constraint is identified on the grid side: solar growth can outpace transmission reinforcement. When grid capacity is limited, renewable output can become trapped in specific areas, leading to local congestion and curtailment alongside price separation. In Southeast Europe, interconnection and internal grid constraints are cited as already major issues.
Policy focus on flexibility rather than halting deployment
The political message described argues that negative prices should not be treated as evidence that too much renewable energy has been built. Instead, negative prices are presented as indicating insufficient flexibility to absorb renewable output efficiently. The source states that stopping solar is not framed as the solution.
The alternative measures listed include building storage, expanding demand response, increasing grid capacity and improving market signals with greater granularity. It also characterizes Southeast European power markets as being reshaped by solar generation growth beyond standalone capacity additions.
The source concludes that market outcomes will depend on understanding when electricity is valuable versus when it is not, including how value can be moved from surplus hours to scarcity hours.
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