On a sunny, breezy midday, panels and turbines run at peak. The sun and wind don't slow down when prices fall.
When the sun is high in one country, it's high in its neighbours too. Wind is patchier, so a windy hour in one country might not show up next door.
Nuclear stations and large coal plants need many hours to throttle down. They keep producing straight through the surplus.
On a weekend or holiday with mild weather, factories are quiet and offices are empty. Demand drops far below normal, and no large buyer is around to soak up the surplus.
When wholesale prices crash, household bills don't move. Most retail tariffs are flat across the day, so the price signal never reaches the consumer.
Cables to neighbouring countries are full, and the neighbours are often flooded with surplus too. The extra power has nowhere to go.
Storage charged up earlier and is now full. The fastest exit is closed, so there's nowhere left to put the extra power.
11 GW of coal plus biomass and district-heating co-generation (CHP) that run for non-electricity reasons.
Subsidy-era solar from 2010–2014 (built under the EEG feed-in tariff) still pushes prices well below zero early in an event; Germany's 2025 solar peak-cap law (Solarspitzengesetz) applies to new plants only.
Wind concentrated in the northern states, demand in the industrial south, cross-border lines fill up when neighbours share the same continental sun.
~63 GW installed, ~40–50 GW typically running, that operators are reluctant to cycle daily for fuel-cycle and capacity-payment reasons.
Only 17% of the mix is solar+wind (nuclear 66%, hydro 11%); solar peaks trigger an event but don't drive prices very far below zero.
The price has to fall toward the floor before a flexible plant on the grid (usually a German coal plant connected by cable) agrees to switch off instead.
Most negative hours come from North Sea offshore wind; the rest involve solar alongside a ~15 GW rooftop and small-scale fleet.
Coal phased out in 2024, leaving ~30 GW of gas plus ~6 GW of older UK nuclear that's designed to cycle rather than run flat-out.
UK Contracts for Difference don't pay during sustained negative prices, so subsidised plants curtail at zero rather than let prices fall further.
Italy's wholesale market historically had a €0 floor. It is being lifted to align with EU practice, but no negative prints have appeared yet.
47% of generation is gas; the fleet absorbs surplus before prices fall far below zero. Gas also sets the marginal price most hours, leaving Italy with some of the highest wholesale prices in Europe.
17% solar and 8% wind nationally — just 0.3% wind in the industrial north — well below Germany's or Spain's mix.
Italy is split into multiple market zones; this page shows the northern one, the country's largest by load and most cross-border traded. The southern zones have different solar and wind mixes, but the €0 floor applies nationally, so none of them have produced negative prices either.
~3–4 GW interconnector to France against 70 GW peak load. When Spain is in surplus, neighbours usually are too — exports don't help.
16% of the fleet pumps when prices touch zero, draining surplus before prices fall far below zero.
Solar built post-2018 isn't on a fixed subsidy, so it shuts off rather than letting prices fall further; clearing rules at the Iberian wholesale exchange (OMIE) limit how far prices can fall too.
Negative prices are no longer an oddity. By 2026 they're a recurring feature of every European spring, getting deeper year by year.
What looks like a renewables glut is a coordination failure. Across the system, actors keep making decisions that each make sense on their own, but stack into surplus.
The fix is in the wiring between them. Until that catches up, every spring runs the same script.