On a sunny May afternoon in Spain, the country often produces more electricity than it can use. The wholesale price then drops to zero - or goes negative, which means producers have to pay to keep generating. Hours later, when the sun sets and demand peaks, the same grid has to fire up gas plants to meet the evening load. That daily whiplash has two visible symptoms: curtailment (energy that could have been produced but was paid not to be) and negative prices (energy that was produced and was paid to stop). Both are expensive system problems. Both are also exactly the arbitrage window that batteries are being built to close.
Negative and zero-price hours are no longer rare
In 2024, Spain recorded 247 hours of negative day-ahead prices and around 470 hours at zero - together, more than 8% of all traded hours. By the first week of September 2025, negative-price hours alone had already doubled the full 2024 total, with the count rising past 600 by year-end. The depth deepened too: the average price during negative hours fell from roughly -€1.5/MWh in 2024 to -€6/MWh in 2025, meaning not just more frequent negative prices but also more punishing ones.
Wind, hydro and nuclear assets remained economic on average because they capture higher prices at other hours. Solar, which by definition produces almost entirely inside the zero/negative cluster, had a much harder year. OMIE-reported solar capture prices for 2025 have been tracked at around €34/MWh against a wind capture of roughly €62/MWh - nearly a 2× gap.
Curtailment is rising and will continue to rise
Curtailment - generation that is instructed or economically forced off - ran at around 2% of Spanish PV output in 2024. Research tracking the last two years together puts average PV curtailment at roughly 2.9%, with 2.5 percentage points receiving no compensation. Forward-looking analyses from Strategic Energy Europe and others project curtailment reaching 5% by 2027–2028 if the solar pipeline is built without parallel flexibility. In May 2025, pv magazine reported that 21% of PV energy offered that month did not clear, even with bids below €5/MWh - a volume constraint driven by lack of demand, not by grid limits.
Where BESS comes in
The arbitrage window is simple to describe. A battery charges during the zero/negative cluster between roughly 11:00 and 16:00 local, and discharges into the evening peak between roughly 19:00 and 22:00. Intraday opportunities layer on top. What matters for project economics is not the average spread but the distribution - a handful of very high-spread days per month can dominate the annual capture.
Quarter-hourly clearing in day-ahead, which took effect on 1 October 2025, has made that distribution more granular. Short, sharp 15-minute swings around the shoulders of the evening ramp now show up in the price curve instead of being averaged into an hourly block. A battery with accurate price forecasting and fast execution captures more of those 15-minute swings than one optimising against the old 24-block curve.
A note on PPAs
The spread between zero-floor and no-floor PPAs has widened sharply. Solar off-takers that agreed to pay a merchant-linked tariff in 2022–2023 are increasingly exposed to curtailment and negative-price risk; developers signing new PPAs in 2025–2026 are negotiating zero-floor clauses and co-located storage much more aggressively.
Where this goes next
Two dynamics matter for the next two years. On the supply side, another 10–15 GW of PV is expected to interconnect in Spain by 2027, deepening the midday trough before storage catches up. On the demand side, electrification of heat and transport, and the first batches of contracted industrial demand response, will begin to fill the trough. The gap between those two curves defines the headroom for flexibility, and by extension for battery revenue, through the late 2020s. Every published curtailment number is, in effect, a leading indicator of how much flexibility the system will reward.