After years of high inflation, negative electricity prices might seem like a positive. However, the reality is more complex. Without adjustments to pricing structures and subsidy schemes, negative prices could slow down Europe’s energy transition.
In the past two years, the number of negative price hours on the European electricity market has increased significantly. Power consumers are now paid to use electricity for hundreds of hours annually in multiple countries. This is a phenomenon that was almost unheard of five years ago. Aurora’s analysis for 2024 shows that negative price hours are coming up across all of Europe. The Netherlands stands out through having one of the highest numbers of negative prices on the continent, with over 450 recorded negative price hours in 2024, and some of the most extreme negative price levels. This makes the Netherlands an appropriate case study to understand what is going on with negative prices in Europe and what might lie ahead for other markets.
Why do prices go negative?
Essentially, negative prices on the day-ahead market occur when electricity supply exceeds demand at a given moment. During these periods of surplus, electricity producers must pay to offload their excess power onto the market. So why not just stop producing?
One of the main drivers for negative prices is the inflexibility of solar energy systems, which continue to produce during periods with negative price hours. In the Dutch day-ahead market, negative price hours mainly occur during spring and sum-mer, between 9 am and 3 pm, when solar panels generate electricity on a large scale. Solar capacity in the Netherlands has quintupled in five years, from 5 GW in 2018, to 24 GW in 2023. On sunny days, the power production of solar energy often exceeds demand, which averages around 13 GW. Neighbouring countries such as Germany and Belgium face similar challenges with solar overproduction, which limits the Netherlands’ ability to export the excess power. In 2024, this led to prices as low as -€200/MWh during midday hours.
Dutch households lack incentives to stop producing during times with negative prices due to the net metering policy. Over 10 GW of solar capacity in the Netherlands is residential capacity installed behind the meter. Under the current net metering scheme, households can offset their annual generation against their annual consumption and they do not pay taxes or grid fees on this production. Moreover, if they generate more than they consume, they receive compensation for the surplus. This means that they will maximise their production, even when prices go negative.
Large scale installations have more incentives to curtail generation during negative price hours, but many installations either lack remote control capabilities or are bound by contractual obligations that prevent flexibility. Most large scale installations in the Netherlands are under the SDE++ subsidy programme, which provides a ‘feed in’ premium on top of the day-ahead market revenues. Under this framework, renewable energy producers do not receive subsidies during periods of negative electricity prices – a rule designed to discourage production during oversupply. However, many smaller parks lack the technology or expertise to be remotely controlled and to scale down production. As a result, these installations continue producing even when they do not receive subsidies. This contrasts some other markets, such as Spain, where large solar parks automatically shut down as soon as prices drop below zero. While prices in Spain only go a few euros negative at most, in the Netherlands they can drop to below -€100/MWh.
It is not just solar panels that contribute to negative prices. Between 2018 and 2023, wind power in the Netherlands increased from 4 GW to 12 GW, of which almost 5 GW is installed offshore. While wind generation alone is usually insufficient to push prices into negative territory, its relatively consistent output throughout the day, combined with high solar production during sunny periods, can result in an electricity surplus.
Thermal generation, including coal and gas generation, also adds to negative price hours because they operate based on must-run conditions and face ramping constraints. Currently, system flexibility in the Netherlands is mainly provided by gas and coal fired power plants. These plants traditionally operate at minimum output levels even during periods with low demand, to remain available for rapid deployment when solar and wind generation drop. These must-run conditions suppress power prices and contribute to moments of oversupply. When prices go negative, the high costs associated with shutting down and restarting thermal plants are an additional incentive to remain operational, even if this means paying to generate power. In the Netherlands, most gas and coal plants have been installed over the last 15 years and are more flexible compared to older plants. The plants have relatively short start up times and can ramp up and down quickly, but their operation still contributes to negative pricing. In countries with much older thermal fleets, like Poland, the impact of fossil generation on negative prices will be even larger.
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The first issue of 2025 is here! The Spring issue of Energy Global starts with a guest comment by Tim Reid from UK Export Finance about expanding operations overseas before a regional report from Aurora Energy Research no the effect of negative electricity prices in Europe. Other interesting topics covered in the issue include electrical infrastructure, sit surveys & mapping, developments in solar, and much more. Featuring contributions from key industry leaders such as EM&I, DeterTech, and Global Underwater Hub, among others, don’t miss the valuable insights available in the Spring 2025 issue.