(No) reasons to be so negative?

Negative power prices continue to be a significant phenomenon on European power exchanges in 2025. In Germany, 445 hours with negative prices were recorded by August 12, while the Netherlands saw 463 hours and Spain 489 hours. These values are already close to or exceeding the records set in 2024. While low wholesale prices are beneficial for many electricity consumers, frequent negative prices pose problems for the power market.

In Germany, they particularly burden the “Erneuerbare-Energien-Gesetz (EEG)”-account (Renewable Energy Sources Act), as both the difference between guaranteed remuneration and market prices increases and marketing losses arise in direct marketing. In addition, regulatory adjustments such as the 1-h rule introduced in February 2025 by the ‘Solarspitzengesetz’ mean that revenues for new EEG-subsidised plants fall away during periods of negative prices and reducing the profitability of new projects.

The aim of this white paper is not to provide precise forecasts for the future frequency of negative prices, but rather to use Montel’s fundamental power market model Power2Sim to identify key influencing factors and sketch development paths. We consider three main dimensions: the regulatory environment and the resulting bidding behaviour of wind and photovoltaic plants, the degree of temporal flexibility of the growing share of flexible electricity demand, and the role of storage technologies, in particular large-scale battery storage (BESS).

The results are not exact forecasts but sensitivities that illustrate how these three factors can interact to reduce or even eliminate negative prices in the long term. The starting point of the analysis is a hypothetical “counterfactual” scenario, which is based on Montel’s “Central” scenario of European power price projections. In this hypothetical scenario, we simulate a situation without temporal flexibility of flexible consumers, without storage integration, and without regulatory interventions such as §51 EEG. Under these assumptions, the number of hours with negative prices in Germany rises to around 1,600 per year by 2030 and over 2,500 hours by 2038. This development is a direct result of the massive expansion of renewable energies in combination with temporally inflexible demand and thermal “must-run” capacities, which continue to feed in even at low prices.

However, the consideration of regulatory changes shows that the number of negative hours can be significantly reduced. The 1-h rule ensures that new plants no longer receive feed-in remuneration during hours with negative prices and therefore no longer bid below zero. While this effect is less pronounced for photovoltaics in isolation, wind power shows a particularly strong impact. The reason lies in its more even distribution of feed-in throughout the year, which also coincides with many hours of low demand, especially at night. When the rules for both wind and solar plants are combined, the effect intensifies: in this sensitivity, the number of negative price hours in Germany drops to just 20 hours in 2038.

Another crucial factor is the degree of temporal flexibility of electricity demand. The decisive point is not the absolute size of flexible loads, such as from e-mobility, electrolysers, or heat pumps but how much their consumption can be shifted in time over the day. The better these loads can be aligned with periods of electricity surpluses, the more strongly they contribute to reducing negative power prices.

In the sensitivity where consumer flexibility increases significantly by 2040 and a larger share of demand can be shifted, the number of negative price hours in 2038 falls from over 2,500 to under 2,000. And this without the 1-h rule, which, when combined with increased flexibility, eliminates negative prices entirely. Even with a slower development of flexibility potential, the number of negative hours declines continuously.

By contrast, large-scale battery storage has only a limited influence in the sensitivity on reducing negative hours. While they can smooth price peaks through arbitrage-oriented charging and discharging and improve the so-called capture prices for renewable producers, the projected capacity up to 2037 is not sufficient to make a significant contribution to reducing negative prices during periods of high summer feed-in. The limited storage capacity and the fact that negative prices often occur in consecutive hours further restrict the effect.

Interestingly, the core results remain robust even under different assumptions for the baseline scenario, such as in the more conservative “Tensions” scenario. Even with slower expansion of renewables and lower demand flexibility, regulatory adjustments and gradual temporal flexibilisation of demand in the 2030s still lead to the near elimination of negative prices.

In summary, the white paper shows that a combination of regulatory adjustments and increasing temporal flexibility of demand has the potential to significantly reduce the frequency of negative electricity prices in the coming years. While battery storage primarily contributes to optimising revenues, regulatory frameworks and the expansion.