The Big Repricing: Europe's Clean Energy Markets face 5 Structural Shifts

The global clean energy sector reached a turning point in 2025 as record renewable deployment began to collide with power-system constraints. 

According to the Pexapark Renewables Market Outlook 2026, this collision has triggered what the report terms “The Big Repricing” — a structural reassessment of value, risk, and revenue across electricity markets rather than a cyclical correction

#1 Renewable Dominates, But Plants Now Earning Only Half the Value

Europe has clearly moved into a power system where renewables dominate. In 2025, renewable sources generated 47.8 percent of all electricity in the European Union. Solar power alone produced more than 340 terawatt-hours, accounting for 12.6 percent of the total electricity mix. 

Together, solar and wind generation has now overtaken fossil fuels and nuclear power, making renewables the largest source of electricity in Europe.

This rapid growth has changed how electricity prices behave. When many solar and wind plants generate power at the same time, especially during sunny or windy hours, supply often exceeds demand. As a result, the prices that renewable plants receive in the market have fallen.

In Germany, the average price earned by solar power dropped to about 53 percent of the normal baseload electricity price in 2025, compared with nearly 90 percent just a few years ago. Similar trends were seen in Spain and France, where solar plants earned only 51 percent and 58 percent of baseload prices. Onshore wind plants in Finland and Sweden also saw prices fall to around 52–53 percent of baseload levels. In simple terms, many renewable plants are now earning only about half the value of standard power prices when they sell electricity directly into the market.

Negative electricity prices have also become common. In 2025, Europe recorded more than 9,000 hours when power prices fell below zero. This happens when renewable generation is high but the grid and storage systems cannot absorb the excess power. Germany saw negative prices 6.6 percent of the time, followed by Spain at 6.3 percent, Belgium at 5.9 percent, and Finland at 5.3 percent. These conditions show that price drops, volatility, and forced shutdowns of renewable plants are no longer temporary issues, but are now built into how the system works, notes Pexapark.

#2 The Big Repricing of PPAs as Capture Expectations Collapse

As the value of solar and wind power in the market fell faster than expected, the way power purchase agreements (PPAs) are priced also changed in 2025. Buyers lowered their expectations of how much value renewable projects would earn in the future. This led to bigger discounts on pay-as-produced PPAs, which are linked directly to market prices, compared with fixed baseload contracts. At the same time, the value of baseload PPAs increased, while the value of solar PPAs fell as risks from oversupply and price swings were fully reflected.

This change created a wider gap between what buyers were willing to pay and what project developers needed to earn to make projects financially viable. 

In countries such as Germany and Spain, this gap became so large that it reduced or completely removed the price range where deals could realistically happen. As a result, fewer PPAs were signed, and deals only went through when very competitive projects matched buyers willing to take on higher risk.

Negative electricity prices also moved from being a rare issue to a key point in PPA negotiations. Buyers now clearly price the risk of negative prices into contracts and are willing to pay slightly higher PPA prices - ranging from about 1.5 percent to as much as 12 percent - to avoid being exposed to these losses. 

In 2025, around 24 percent of solar power generation in Germany and the Netherlands occurred during hours with negative prices, while in Spain the share was about 15 percent. Because of this, modern PPAs increasingly include rules for curtailing generation, compensation during price dips, and shared risk between buyers and sellers, instead of placing all the risk on one side.

#3 Capital Is Pivoting from Generation to Flexibility as BESS Scales Up

Even though fewer long-term power purchase agreements were signed, investment has not moved away from clean energy. Instead, money is shifting toward flexibility, especially battery storage. 

In Europe, long-term PPA volumes fell to 13.1 GW in 2025, compared with 15.3 gigawatts in 2024. At the same time, battery energy storage saw strong growth. Nearly 12 gigawatts and 24 gigawatt-hours of battery capacity were contracted through flexibility and optimisation agreements, which was three times higher than the previous year.

Battery storage is now operating at a commercial scale across Europe. Large battery installations reached around 16 GWh in 2025, and storage capacity has been growing very fast, at an average rate of about 92 percent per year over the last five years. 

Fixed-revenue flexibility contracts have become essential for making battery projects bankable. In 2025 alone, 6.5 gigawatts of battery capacity was secured under these contracts, almost double the amount signed a year earlier. 

While Great Britain remains the largest market, activity has spread to countries such as Germany, Italy, and the Netherlands, and newer markets like Poland and Bulgaria have signed their first battery storage contracts.

#4 Volatility Is Redefining the Roles of Utilities, IPPs, and Corporates

Ongoing price swings in electricity markets are changing how risk is shared across the power sector. 

Utilities are once again playing a central role in managing this risk. In 2025, utilities increased their power purchase agreement offtake by more than 200 percent compared to the previous year and accounted for 77 percent of all contracted flexibility agreements. Their large portfolios, strong financial position, and access to battery storage and other flexible assets allow them to handle price swings better than smaller players or companies that own only a few projects.

Independent power producers are feeling growing pressure as selling power directly into the market becomes less reliable. Higher imbalance costs and lower market prices for solar and wind are pushing them to change how they operate. Instead of relying mainly on generation, they are focusing more on managing revenues, structuring contracts, and optimising portfolios to reduce risk. 

Corporate buyers are also moving in different directions. Overall corporate PPA volumes fell by about 30 percent in 2025, mainly because the market has become more complex and buyers are more cautious, not because companies have abandoned their long-term climate goals. Large technology companies are increasingly seeking stable, round-the-clock clean power through utility-like contracts, while many other corporates are taking a more careful and selective approach to new power purchases.

5. United States: Record Buildout Meets Rising Policy Risk

In the United States, clean energy capacity grew at a record pace in 2025, but confidence in the market weakened because of policy uncertainty. Faster-than-expected changes to tax credits and uncertainty around tariffs pushed PPA prices higher. At the same time, fewer deals were signed, and many projects were delayed, showing that strong capacity additions were hiding underlying weaknesses in the market.

Energy storage played two different roles in the US. In some regions, too many storage projects started to reduce short-term revenues. At the same time, growing electricity demand made storage more important for keeping the power system reliable over the long term. This was especially clear in markets like ERCOT and PJM, where electricity demand is expected to grow strongly. In these regions, storage is increasingly seen as a critical reliability tool, not just a way to profit from short-term price differences.

Conclusion

The evidence from 2025 shows that clean energy markets have entered a structurally different phase. Capture erosion, negative pricing, volatility, and flexibility constraints now sit at the centre of renewable economics. The Big Repricing described by Pexapark is not a temporary adjustment, but a lasting recalibration of how value is created and sustained in a renewables-dominated power system.