Solar generation across the EU is reaching new highs, but the economics of that generation are becoming less straightforward. (European Commission)In the first quarter of 2026, the aggregate number of negative-price hours across EU-27 day-ahead markets reached 1,223, up from 593 a year earlier. Spain recorded 347 of those hours, while several Nordic markets saw fewer negative prices than before. (pv magazine)
The headline is easy to read as another story about renewable oversupply. That is only part of it. Negative prices usually appear when several things coincide: strong generation, weak demand, limited ability to move electricity across borders or through the grid, and not enough flexibility elsewhere in the system. Solar is often involved because its output is concentrated in the middle of the day, but it is rarely the only reason prices fall below zero.
For solar projects, the more important issue begins before prices actually turn negative.
When More Solar Means Lower Capture Value
The average wholesale price does not necessarily reflect the market value of a solar plant’s output. Solar generation is concentrated during daylight hours, and those are increasingly the same hours when large volumes of PV power are entering the market at once. As midday supply rises, the price during those hours can fall even if the broader market average remains relatively strong.
This is what capture price is meant to show. The solar capture price is the generation-weighted wholesale price during the hours when solar is producing. The capture rate compares that figure with the average market price over the same period.
The difference is becoming harder to ignore. LSEG data cited by Reuters showed that average solar capture prices across Germany, France, the Netherlands, Belgium, Italy and Spain in the first half of 2026 were about 42% lower than in the same period of 2023. (Reuters)
Kpler has also reported unusually weak solar capture rates in several European markets during spring 2026, with large differences between countries and seasons. (Kpler)
That matters most immediately for merchant projects, which are directly exposed to wholesale prices. PPAs, CfDs and other support mechanisms can soften or reshape that exposure, but they do not make the underlying market signal disappear. Lower capture values can still influence how future contracts are priced and how new projects are financed.
France shows how quickly this can move from market pricing into plant operation.
By the end of 2025, mainland France had 30.4 GW of installed solar capacity, after adding 5.9 GW during the year. RTE reported about 1.6 TWh of solar output modulation in 2025, roughly two and a half times the level recorded in 2024. (RTE)
During negative-price periods specifically, RTE estimates that around 3 TWh of wind and solar generation was not produced in 2025. About 1.6 TWh came from solar and roughly 1.3 TWh from onshore wind. RTE links the increase to more frequent negative prices, rising solar generation in France and neighbouring markets, and the growing share of renewable capacity able to reduce output in response to market conditions. (RTE)
Policy is moving in the same direction. A French order dated July 20, 2026 lowers the size threshold for installations covered by these shutdown provisions from 10 MW to 1 MW. Projects above 5 MW, or 5 MWp for photovoltaic installations, are covered from December 1, 2026. Projects between 1 MW and 5 MW, or 1 MWp and 5 MWp for PV, follow from March 1, 2027. (Légifrance)
Where Batteries Fit
Once renewable plants are being asked to respond more actively to low or negative prices, the question naturally turns to storage.
If part of the problem is that electricity is arriving at the wrong time, a battery can move some of it.
A solar-plus-storage project can charge when midday prices are weak and discharge later, rather than exporting every available megawatt-hour as soon as it is generated. The IEA identifies energy shifting as one of the main roles batteries can play in systems with high shares of wind and solar, particularly when renewable output is strong and demand is low. (IEA)
The IEA’s 2026 mid-year electricity update also points to wider intraday price spreads in several European markets and the value those spreads can create for flexible resources such as batteries and demand response. (IEA)
For a solar plant, that can improve the timing of sales. Electricity that would otherwise be exported during a weak-price period can be held for later. Some energy that might have been economically curtailed may instead be stored. The project is not generating more solar electricity; it is changing when part of that electricity is exposed to the market.
There are obvious limits to how far that can go.
A 1 MW/2 MWh battery can discharge at full rated power for about two hours. If surplus solar generation lasts five or six hours, the battery cannot absorb all of it. If it enters the low-price period already partly charged, the available headroom is smaller again.
The commercial calculation is also more complicated than buying electricity at the lowest price and selling it at the highest. Round-trip losses, degradation, cycling strategy, grid constraints and battery availability all reduce the neatness of that spread. A battery may also be earning revenue from ancillary services or other markets, which means using it for one opportunity can carry an opportunity cost elsewhere.
This is why modeled arbitrage revenues need to be treated carefully. A negative midday price followed by a high evening price can show that a valuable spread exists. It does not tell you what every battery project will actually earn.
Low midday prices can reduce the opportunity cost of charging, while higher prices later in the day may support discharge revenues.
Storage Is Only One Part of the Flexibility Problem
The same limitation appears at system level. Batteries are useful when the problem can be shifted across hours, but they cannot eliminate a transmission bottleneck. Whether storage can ease congestion depends on where it is connected, when it charges and discharges, and the specific constraint on the network.
Some flexibility problems also last longer than the few hours for which lithium-ion batteries are typically best suited. Others arise from inflexible demand, generation constraints or market design rather than from a simple shortage of short-duration storage.
The IEA’s own framework reflects that. Storage sits alongside demand response, more flexible generation, controllable distributed solar, stronger price signals, grid expansion and interconnection. (IEA)
Finland and Sweden are interesting in this respect. Both recorded fewer negative-price hours in 2025, and the IEA points to several possible contributors, including changes in cross-border market coupling, additional storage and more price-responsive generation and consumption. (IEA)
Solar Value Is Becoming More Time-Dependent
What is changing is the way solar value needs to be understood. Producing more electricity is still important, but annual megawatt-hours tell less of the story once large amounts of generation arrive during the same narrow window.
The price attached to those megawatt-hours depends increasingly on timing.
Battery storage gives solar projects some ability to change that timing, which is why its value rises as midday prices weaken and intraday spreads widen. But batteries can only move the electricity that fits inside them, and only across the time horizon they are designed to serve.
Europe’s solar market is therefore moving into a phase where low-cost generation alone is no longer enough to describe project value. What matters increasingly is when that generation reaches the system, what the market is willing to pay for it, and how much flexibility exists to move it somewhere else in time.
