The text below is an edited version of an insight originally published on CRU Online, dated 17 April 2026. For the full version, contact us here.
European electricity prices are well below the 2022 crisis peak, but the EU power market has not returned to its pre-crisis structure. For industrial buyers, looking at the annual average price is no longer enough. The critical risk now lies in the market’s behaviour under stress – the widening gap between negative prices during renewable surges and scarcity spikes when gas is required to meet demand.
Navigating this landscape requires managing three concurrent risks:
- The persistent influence of gas on prices during periods where demand cannot be met by renewables
- The volatility created by renewable capacity growth outpacing system flexibility,
- And a delivered-cost stack where network charges and levies keep bills high even when wholesale markets soften.
The post-crisis market has a new landscape
By 2025, average power prices had fallen substantially from the 2022 crisis. In Germany, the average day-ahead price fell from about €235/MWh in 2022 to around €89/MWh in 2025. Looking only at the average, one might conclude the crisis is over.
However, the distribution of those prices tells a different story. The range between 5–95th percentile of prices in Germany was still about €162/MWh in 2025, compared to just €48/MWh in 2019. We see the same pattern in Spain, where the price range was nearly four times wider in 2025 than in 2019. This wider dispersion is accompanied by a sharp rise in negative-price hours across the continent, highlighting a fundamental shift in market dynamics.
Renewables reduce fuel dependence but increase volatility
Growing wind and solar generation is key to this new reality. Higher renewable output reduces the number of hours that thermal generation is needed, weakening the pass-through from gas prices for long periods. In Germany, the wind and solar share of load rose from roughly 33% in 2019 to about 44% in 2025, with similar gains in Spain and France.
These changes are significant and help explain why power prices can now decouple from gas for longer periods. However, higher renewable penetration also creates more hours with very low prices and sometimes negative prices, when supply is abundant and demand is not flexible enough. This is exactly what we saw in 2025 – negative-price hours rose to about 6.6% in Germany, 6.7% in the Netherlands, 6.3% in Spain and 5.9% in France.
This is not a sign that renewables have failed, but rather that the market is now more dependent on flexibility. Without enough storage, demand response and grid capacity, the market oscillates between surplus and scarcity. When renewable output is strong, prices can fall to zero or below. When it is weak, the system still needs thermal generation, and prices can reconnect sharply to gas and carbon costs.
Country-level risks are diverging
The Hormuz gas shock of 2026, linked to recent disruptions in the Strait, demonstrates how the same event now produces very different outcomes. The shock lifted European TTF gas prices, but the impact on power prices was not uniform.
In Italy, which remains highly sensitive to gas prices, day-ahead power prices rose almost one-for-one with the gas move. By contrast, in Germany, Spain and France, average power prices in March and early April 2026 were actually lower than in the preceding two months, despite the higher gas price. This was because favourable renewable and load conditions reduced the need for gas-fired generation. The gas price shock was real, but it only hit hard where the power system needed it at the margin.
This divergence also applies to the all-in delivered cost of electricity. In markets like Czechia, Germany and Slovakia non-energy costs, such as network charges and levies, form a large and growing share of the final bill. This creates a structurally-high cost floor, meaning that even when wholesale prices are low, industrial users in these countries may face higher all-in costs than those in markets with higher wholesale price volatility but lower regulated charges.
For industrial buyers, managing power procurement is no longer just about the wholesale gas exposure. It is about understanding the complex interplay between spot price volatility, system flexibility and the persistently high non-energy components of the bill.
For businesses seeking to manage this shifting risk landscape, CRU’s Energy Transition and Decarbonisation service can help assess exposure, identify structural cost pressures and inform your business strategy as the EU power market continues to evolve. Contact us to discuss more.
