Solar power briefly became Europe’s largest source of electricity generation in June 2025. The milestone highlighted both the success of renewable deployment and the growing challenge of managing increasingly abundant electricity supply.

Solar photovoltaic (PV) capacity across the continent has expanded at extraordinary speed, and behind-the-meter installations on rooftops, car parks and commercial premises are now generating power on a scale few grid operators anticipated a decade ago. Much of this growth has been driven by households and businesses seeking lower energy bills, greater energy security and protection from volatile wholesale markets.

For policymakers and grid operators, the question is no longer whether solar can scale. That question has largely been answered. The challenge now is how electricity systems adapt to a future in which periods of abundant renewable generation are becoming increasingly common.

The paradox of abundance 
Solar generation peaks during midday hours when residential and commercial demand is often relatively low, particularly in spring and summer. Behind-the-meter systems first serve the homes and businesses where they are installed before exporting surplus electricity to the grid. When millions of systems operate simultaneously under clear skies, that surplus can overwhelm local distribution networks, depress wholesale electricity prices and force the curtailment of renewable generation because electricity networks are unable to accommodate the additional supply.

European power markets registered record negative-price hours in 2025 as solar generation outpaced available flexibility infrastructure. Germany alone recorded 573 hours of negative prices in 2025, compared with 457 hours in 2024, representing a roughly 25% year-on-year increase. Similar patterns are emerging across Belgium, France, the Netherlands and Spain, where prolonged periods of midday oversupply are becoming increasingly common.

In Spain, negative-price events accelerated sharply during the first half of 2025 as utility-scale and rooftop solar output combined with strong hydroelectric generation. France also experienced a sharp rise in zero and negative-price periods during 2024 and 2025, prompting grid operator Réseau de Transport d’Électricité (RTE) to warn that increasingly frequent episodes of abundant renewable generation were creating new balancing challenges.

Curtailment is also increasing. Analysts at Aurora Energy Research estimate that curtailment across the UK, Spain and Italy could reach 22TWh annually by 2030 unless grid reinforcement and storage deployment accelerate significantly. In practical terms, this means clean electricity that could otherwise displace fossil fuel generation is being switched off because electricity networks are unable to accommodate the additional supply.

Negative pricing, curtailment and local congestion are exposing weaknesses in market design and grid infrastructure that received less attention when electricity systems were dominated by centralised generation.

Reforming the rules for prosumers 
One of the most significant policy responses has been the reform of net metering schemes. These arrangements historically allowed households and businesses to receive credits for surplus electricity exported to the grid, helping accelerate rooftop solar adoption across many European markets. However, they were largely designed for an electricity system in which distributed solar generation represented a relatively small share of overall supply. As solar capacity has expanded, policymakers have become increasingly concerned that traditional net metering can weaken incentives to store electricity or shift consumption away from periods of oversupply.

In the Netherlands, net metering has historically insulated households from wholesale market signals, meaning households have continued exporting surplus solar generation even when wholesale electricity prices fall below zero.

Following parliamentary approval in late 2024, the country will abolish net metering from January 2027. Suppliers will instead determine export compensation rates, exposing households more directly to market conditions and encouraging investment in batteries, smart appliances and flexible consumption.

In Germany, the Solar Peak Act, which came into force in February 2025, suspends feed-in remuneration for new solar systems during periods of negative wholesale pricing. Smart meters are also becoming mandatory for larger rooftop systems, giving grid operators and aggregators greater visibility over distributed generation.

Greece has taken the process further by replacing traditional net metering for most new applicants with a net billing framework based on wholesale market prices settled at 15-minute intervals. Under the new system, the value of exported electricity more closely reflects market conditions at the time it is generated. The reform is intended to encourage households and businesses to use or store more of their solar generation during periods of oversupply while continuing to support investment in new installations.

After spending much of the past decade encouraging solar deployment, governments are increasingly focused on how that electricity is used once it is generated. Rather than rewarding households simply for exporting surplus power to the grid, new policies are designed to encourage consumption, storage and exports at times that better match the needs of the wider electricity system.

Battery storage moves into the mainstream 
Policy reforms can help reshape incentives, but they do not address the physical challenge of balancing supply and demand. Increasingly, that role is falling to batteries.

Germany remains Europe's leading residential storage market. By 2025, the country had installed more than two million home battery systems, with roughly four out of five new rooftop solar installations paired with storage. High retail electricity prices, combined with increasingly volatile wholesale markets, have strengthened the economics of self-consumption.

The benefits extend beyond individual households. Analysis by energy think tank Ember suggests that additional battery capacity in Germany could materially reduce fossil fuel generation during evening peak periods by shifting surplus midday solar generation into higher-demand hours. At a system level, this reduces reliance on gas-fired peaking plants while limiting the severity of negative-pricing events.

Grid-scale storage is also accelerating. Italy has introduced a major storage procurement mechanism expected to support several gigawatts of new battery and pumped hydro capacity. Similarly, Greece and Spain have expanded storage auctions to improve renewable integration and reduce curtailment risk.

According to industry association SolarPower Europe, EU battery storage capacity increased by 45% in 2025 to more than 77GWh installed across the bloc. Yet industry groups argue that deployment still needs to accelerate significantly if Europe is to integrate the scale of renewable generation expected by 2030.

The rationale is increasingly economic as well as technical. As periods of very low daytime pricing become more common, the commercial value of shifting electricity into evening demand peaks is rising sharply. Batteries are therefore no longer viewed purely as resilience assets. They are increasingly becoming part of the core infrastructure needed to manage electricity markets with large volumes of solar generation.

The rise of virtual power plants 
Beyond standalone batteries, European grids are increasingly turning towards aggregation technologies to manage behind-the-meter solar more effectively.

Virtual power plants (VPPs) use software platforms to coordinate thousands of distributed energy assets, including rooftop solar systems, batteries, electric vehicle (EV) chargers, heat pumps and industrial loads, as if they were a single dispatchable power station. The concept is moving from pilot projects towards wider commercial deployment.

German residential energy company Enpal and optimisation platform Entrix launched one of Europe's largest VPP initiatives in 2025, integrating household batteries, EV chargers and heat pumps into a coordinated flexibility platform. The objective is not simply to optimise household energy use, but to provide balancing and ancillary services to the wider electricity system.

Denmark is another leader in flexibility innovation. Vehicle-to-grid aggregators are now participating in frequency response markets operated by Energinet, the national transmission system operator, allowing EVs to export power back to the grid during periods of system stress.

These developments illustrate how Europe's electricity system is becoming increasingly decentralised, digitised and data intensive. Managing millions of distributed assets requires a fundamentally different operating model from the traditional top-down architecture built around large thermal power stations.

Without greater regulatory consistency, however, the growth of cross-border flexibility markets will remain constrained by fragmented national frameworks. In early 2025, the EU Agency for the Cooperation of Energy Regulators proposed a new network code on demand response intended to harmonise rules governing demand-side participation and aggregation across member states.

Solar as part of the demand solution 
Much of the debate surrounding behind-the-meter solar focuses on volatility and oversupply. But distributed solar is also becoming an increasingly important tool for managing rising electricity demand. Electricity consumption across Europe is expected to increase significantly over the next decade as transport, heating and industrial processes electrify. Data centres, heat pumps and EVs are all adding new load to networks that were originally designed around very different consumption patterns.

In this context, behind-the-meter solar offers a distinct system benefit because it serves part of that demand locally, reducing pressure on transmission infrastructure and lowering peak imports from the grid.

The impact is particularly significant in the commercial and industrial sectors. Factories, warehouses, logistics centres and supermarkets often have daytime demand profiles that align relatively well with solar generation. When paired with batteries and energy management systems, these installations can substantially reduce both grid imports and peak-demand charges.

The electrification of transport and heating further strengthens the case for flexible self-consumption. Home energy management systems are increasingly coordinating rooftop solar, batteries, heat pumps and EV charging around dynamic electricity prices.

In practical terms, this means a household may charge its car, heat water or pre-cool a building during periods of abundant solar generation rather than exporting electricity into an already saturated market. What was previously unmanaged surplus generation becomes productive local consumption.

Dynamic retail tariffs are helping drive this behavioural shift. Across several European markets, consumers are increasingly exposed to time-of-use pricing or real-time wholesale-linked tariffs. This is gradually transforming households from passive electricity consumers into active market participants.

The road ahead 
Across much of Europe, renewable deployment has outpaced investment in electricity networks, storage and other forms of flexibility. As solar capacity continues to expand, the challenge of integrating growing volumes of distributed generation is becoming increasingly acute.

According to European Commission estimates, hundreds of billions of euros will need to be invested in transmission and distribution infrastructure over the coming decades to modernise ageing networks, connect renewable generation and accommodate rising electrification demand.

The first half of 2026 will almost certainly bring further records for negative pricing and renewable curtailment. But it will also provide an increasingly important test of the policies, technologies and market reforms now being introduced across Europe.

The challenge facing European grids is no longer whether solar can scale. That question has largely been answered. The focus is increasingly on how networks, markets and consumers evolve to make effective use of growing volumes of distributed renewable generation.

Success will depend not only on deploying more solar capacity, but on building the networks, storage and flexibility needed to support it. Europe has made significant progress in developing those capabilities, but the next phase of the energy transition will be shaped as much by integration as by generation.

• Further reading: ‘Europe’s solar dilemma: competing with China while securing energy independence’. Since 2011, China has invested over $50bn in new PV supply capacity – 10 times more than Europe. Making a dent in China’s production monopoly will be immensely challenging, but the EU could maintain leadership in solar installation and technology by strategically directing funding and diversifying supply chains.
• ‘Turning point for power: record solar growth across Europe and Great Britain in 2025.’ Europe’s electricity transition gathered pace in 2025, driven by record solar growth that curbed emissions and fossil fuel exposure, although weak demand and volatility persisted, according to sector trade association Eurelectric. In parallel, analysis of provisional data from the National Energy System Operator shows Britain also hitting renewable records, with solar surging, while gas still played a significant balancing role.