Too Much Electricity, Not Enough Electricity: Europe's Renewable Grid Problem

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Europe is becoming good at generating renewable electricity. The harder task is getting it to the right place at the right time.

In March 2026, German solar developer Enerparc announced financing of up to €1 billion to support the expansion of its solar parks and battery-storage portfolio. Less than six months later, the company filed for insolvency.

At first sight, the contrast seems to tell a familiar story about renewable-energy economics. Enerparc was not a marginal developer caught on the wrong side of a speculative boom. It was a major European solar company, with 3.8 gigawatts of projects in operation and another 1.5 gigawatts under construction when the insolvency proceedings began.

Yet the available evidence points somewhere more specific. According to the provisional insolvency administrator, a separate project financing of around €200 million failed at the end of June. Enerparc was then unable to meet commitments associated with equipment it had ordered. The administrator also described a balance sheet carrying around €3 billion in liabilities and too little equity relative to debt. The administrator's account of the financing failure does not establish that solar power itself had become uneconomic.

Enerparc's operating solar parks continued to generate electricity. Its insolvency is therefore more useful as an entry point than as a verdict. The difficult questions in the energy transition are moving beyond the panels and turbines themselves towards the infrastructure, markets and financing around them.

Germany already experiences hours when electricity is so abundant that wholesale prices fall below zero, other hours when renewable production is weak and prices rise sharply, and still others when electricity can be generated but cannot be moved through a congested grid. The same electricity system can have too much power, too little power and power in the wrong place.

The constraint is no longer simply how much renewable capacity can be built. Increasingly, it is whether the surrounding system can move electricity across time and space cheaply enough to make that capacity useful. This is the practical version of an argument developed in an earlier Journal essay on the energy transition as a system problem: the value of a generating technology depends partly on what surrounds it.

The success that creates the next problem

In the public electricity data tracked by Germany's SMARD platform, renewable sources accounted for 58.8 percent of realised generation in 2025. Solar contributed 74.1 terawatt-hours, up from 63.2 TWh a year earlier. Bundesnetzagentur's 2025 market data show how far renewables have moved from being a supplementary source of power towards the centre of the system. Installed photovoltaic capacity separately reached about 117 GW by the end of the year, according to the regulator's renewable-capacity figures.

The expansion continued in 2026. During the first half of the year, renewables supplied 61.8 percent of Germany's net public electricity generation, while photovoltaic generation reached a record 43.2 TWh. Solar output across the EU also reached record levels. Fraunhofer ISE's analysis of the first half of 2026 records both the scale of that growth and some of the problems now appearing around it.

This is a real achievement. A solar panel or wind turbine does not need a continuous stream of imported fuel once it is operating. Its output is therefore much less exposed than a gas-fired power station to disruptions in pipelines, tanker routes or international fuel markets.

Wind and solar nevertheless differ from conventional dispatchable power stations in a basic way: their output follows weather rather than demand. A gas turbine can, within technical limits, be operated when electricity is valuable. A solar panel produces when sunlight reaches it. A wind turbine produces when the wind blows.

That difference becomes much more consequential once renewables supply a large share of the system. Adding the first few gigawatts of solar to a market dominated by dispatchable generation is comparatively easy because most of the output can be absorbed as it arrives. Add another hundred gigawatts and many of those panels begin producing at roughly the same time. Success changes what the system is short of.

Electricity at the wrong time

Germany recorded negative day-ahead wholesale electricity prices during 573 hours in 2025, up from 457 hours the year before. Yet the same market also experienced 40 hours in which prices exceeded €300 per megawatt-hour.

Those figures describe an electricity system in which the value of power depends increasingly on when it is available. High wind and solar output pushes wholesale prices down because the marginal operating cost of producing another unit of electricity from an existing turbine or photovoltaic panel is extremely low. Prices can become negative when supply remains above demand and too little generation, consumption or storage responds quickly enough to restore the balance.

Negative wholesale prices do not mean that solar electricity is literally free. Someone still financed the installation, acquired the land, built the grid connection, maintains the equipment and expects a return on the capital. Nor do most households receive the wholesale price directly. Network charges, taxes and retail contracts separate the exchange price from the bill arriving at the kitchen table.

What the negative price does reveal is that another megawatt-hour has very little value to the system at that particular moment. As more solar capacity enters the same market, more solar electricity arrives precisely when other solar installations are also producing. The technology may continue becoming cheaper while the market value of its output during those hours falls. The problem is not whether the electricity can be generated, but whether someone can make productive use of it when it appears.

The reverse can happen only a few hours later. Solar output declines towards evening while households and businesses continue consuming electricity. In the first half of 2026, Fraunhofer found many periods with prices close to or below zero during strong renewable production alongside sharp evening price increases.

The pattern is not uniquely German. The EU energy regulator ACER reports that renewables supplied about half of EU electricity generation in 2025 while daily wholesale price swings were around five times larger than in 2020. Rising solar output was pushing down daytime prices while increasing the difference between peak and off-peak hours. Germany is useful not because every European country has the same grid or generation mix, but because it is relatively far into a transition that much of Europe is also pursuing.

The obvious response to cheap electricity in the afternoon and expensive electricity a few hours later is storage. Germany is already adding batteries rapidly. Fraunhofer estimates that electricity-storage capacity increased from about 25.4 GWh to 29.3 GWh during the first half of 2026, with more large battery capacity commissioned in six months than during the whole of the preceding year. Even so, it still described a significant storage gap.

Batteries are particularly well suited to moving electricity across hours. A battery can absorb solar generation in the afternoon and release it after sunset. As the difference between cheap and expensive hours widens, the incentive to perform that shift strengthens.

But storage is not one problem with one technological answer. Moving electricity from 14:00 to 20:00 is very different from supplying an industrial economy through several cold winter days with little sun and weak wind. The quantity of stored energy required, and therefore the economics, changes sharply as the duration grows.

The broader requirement is flexibility. Electric vehicles can charge when power is abundant. Heating systems and some industrial processes can shift consumption. Pumped hydro can store energy where geography permits. Interconnectors allow countries experiencing different weather and demand conditions to support each other, although they help only when another region actually has spare electricity to send. Periods when these mechanisms are insufficient still require some combination of longer-duration storage, flexible generation, demand reduction and imports.

Nor should every negative-price hour be treated as evidence that something has gone wrong. A system containing large quantities of generation with near-zero marginal operating costs should sometimes produce extremely cheap electricity. Repeated periods of cheap electricity are also signals to investors: another unpaired solar installation becomes less attractive while storage, flexible consumption and processes capable of using surplus electricity become more valuable.

The difficulty is that those responses do not all arrive at the same speed. A battery can be ordered relatively quickly. A large transmission corridor may take many years to approve and build. Industrial demand cannot necessarily move simply because the market price tells it to. Generation technology can change faster than the physical and institutional system around it.

Electricity in the wrong place

Time is only half the problem. A megawatt-hour generated in northern Germany is not automatically available to a factory in Bavaria. Electricity networks have physical limits, and when transmission lines are already carrying as much power as they safely can, additional generation on one side of a bottleneck cannot simply be sent to demand on the other.

Germany manages these constraints through redispatch. Generation can be reduced in an area where the network is overloaded while other generators beyond the bottleneck increase production. Renewable installations may therefore be curtailed even while other power stations elsewhere in the system are being asked to produce more.

The scale should be kept in perspective. Germany is not routinely throwing away most of its renewable electricity. According to SMARD's congestion-management data, more than 96 percent of renewable electricity generated in 2025 was successfully transported to final customers.

But the remaining mismatch is neither trivial nor disappearing. Renewable generators accounted for about 9.4 TWh of downward redispatch during 2025. Curtailment of offshore and onshore wind fell compared with the previous year, while photovoltaic curtailment rose by 94 percent to 2.704 TWh. Total congestion-management costs were provisionally estimated at around €3.071 billion.

The two observations belong together. Germany successfully uses the overwhelming majority of the renewable electricity it generates, while grid congestion remains large enough to waste meaningful quantities of output and impose costs measured in billions of euros.

The response is physical infrastructure. Around 16,800 kilometres of new or reinforced power lines have been legally identified as necessary for Germany's grid expansion. The Bundesnetzagentur approved roughly 2,000 kilometres during 2025 alone, including completion of approval procedures for the major A-Nord, Ultranet, SuedLink and SuedOstLink north-south corridors. The scale of the planned expansion gives some indication of how much infrastructure sits behind the apparently simple act of adding another wind or solar farm.

Until more of that network exists, Germany also needs substantial grid-reserve capacity specifically to manage transmission constraints. The Bundesnetzagentur has confirmed a requirement of 7.407 GW for winter 2026/27 and 8.274 GW in its assessment for winter 2028/29. The regulator explicitly identifies further grid expansion as the main way to reduce that requirement.

A wind farm can therefore be capable of generating power while consumers elsewhere simultaneously need electricity, yet still be ordered to reduce output because the connection between them is insufficient. As generation becomes easier to add, scarcity shifts into the network that has to carry it.

What Enerparc does — and does not — show

Enerparc should not be made to prove more than the evidence allows. There is no public evidence that grid congestion, renewable curtailment or negative electricity prices directly caused its insolvency. The reported trigger was financial: a project financing failed, Enerparc could no longer meet commitments associated with equipment already ordered, and its balance sheet left little room to absorb the shock.

What the company does illustrate is the amount of infrastructure and capital surrounding modern renewable generation. Enerparc's activities extend beyond installing photovoltaic panels into project development, construction, grid connections, substations, operation, storage and electricity trading. Its own description of the business increasingly treats battery storage and grid integration as ordinary parts of developing large solar projects rather than optional additions.

The financing announced in March reflected that scale. The package of up to €1 billion combined a €500 million loan with a long-term project-financing framework initially worth €425 million and expandable to €500 million. It was intended to support further solar and battery development.

The subsequent failure of a different project financing does not establish that the wider renewable model is financially unsound. It shows something less dramatic but still important: cheap marginal electricity does not mean cheap infrastructure. Generation, storage, substations, grid connections and development pipelines require enormous amounts of capital long before the resulting electricity is sold.

The panels may continue getting cheaper while everything required to make their output useful becomes more consequential.

From generation independence to system resilience

This complicates the idea of renewable energy as a route towards European energy independence without invalidating it.

The strategic case for domestic renewable generation remains strong. Europe's experience after Russia's invasion of Ukraine exposed the vulnerability created by concentrated dependence on imported fossil fuels, a problem examined in an earlier Journal essay on how Ukraine and the Strait of Hormuz changed the meaning of European energy resilience. Wind and solar reduce one important form of exposure because they do not require a continuous imported fuel supply once they are operating.

Replacing imported gas with domestic electricity generation, however, does not complete the system. An electricity system with a large share of weather-dependent generation relies more heavily on transmission networks, storage, interconnection, flexible consumption, forecasting and markets capable of responding to rapidly changing conditions. It also needs resources capable of covering periods when renewable output is weak and short-duration storage or imports are insufficient.

This does not mean renewables simply replace one dependency with an equally dangerous one. The dependencies are different. A gas-fired economy may need fuel to arrive continuously. A solar panel does not. A transmission line, battery or interconnector is infrastructure rather than a resource that must be consumed and replaced every day.

But it does mean that installed generating capacity is becoming a less complete measure of energy security. A country can possess impressive numbers of gigawatts and still have a vulnerable system if too much production arrives at the same time, the network cannot carry it to demand centres, or prolonged periods of weak renewable output cannot be covered economically.

The relevant question is therefore not how much electricity the system could theoretically generate under favourable conditions. It is how reliably that system can deliver useful electricity where and when people need it.

The second phase of the energy transition

For much of the past two decades, the central renewable-energy challenge was relatively easy to describe: make wind and solar cheaper, then build more of them.

That work is not finished. Europe will need substantially more renewable generation if it is to electrify transport, heating and parts of industry while reducing fossil-fuel use. Germany alone still has a solar target of 215 GW for 2030, almost twice its installed capacity at the end of 2025. The first phase has not ended; it is increasingly being joined by another.

Generation can no longer be considered separately from transmission. Solar expansion cannot be separated from storage and daytime demand. Wind development cannot be separated from the geography of the grid. Reliability cannot be reduced to annual terawatt-hours when electricity has to be supplied continuously.

That also makes comparisons based only on the cost of individual generating technologies progressively less informative. The useful question is not whether a solar farm can produce a megawatt-hour more cheaply than a gas or nuclear plant under a particular set of assumptions. It is what combination of generation, networks, storage, flexible demand, interconnection and other resources can deliver electricity reliably at an acceptable total cost.

Enerparc's insolvency is only a small part of that larger story. Its operating solar parks continue to generate. Germany continues to add renewable capacity. Neither fact removes the harder problem becoming visible around them.

Europe's strategic energy asset will not be the solar panel, wind turbine, battery or transmission line in isolation. It will be the system capable of combining them well enough that electricity generated by the weather becomes power available when it is needed.

The first phase of the renewable transition was measured largely in gigawatts. The next will be measured by how much useful electricity those gigawatts can actually deliver.