Negative electricity prices: what they mean for solar and storage investors

Around noon on a sunny summer Sunday, something happens on the German power market that runs against every commercial instinct: whoever generates electricity does not get paid for it, but pays for someone to take it. In 2025 this was the case in 573 hours, more often than ever before. For household customers it is a footnote; for investors in energy infrastructure it is a hard economic variable that works in opposite directions depending on the asset profile. This article explains how negative prices arise, what they mean for solar park revenue, and why battery storage is one of the few assets that profits from exactly these hours.

What are negative electricity prices and how do they arise?

Negative electricity prices arise on the power exchange when more electricity is offered than can be consumed at that moment: the price falls below zero, and generators pay for their electricity to be taken. This is traded primarily in the day-ahead market, the auction in which electricity for the following day is priced the day before. That a price below zero comes about at all has three causes working together:

• High feed-in at low demand: in sunny midday hours, especially on weekends and public holidays, full solar generation meets little consumption. The oversupply pushes the price down, in the extreme below zero.
• Inflexible conventional generation: part of the power plant fleet keeps running even during oversupply, for instance because of heat supply obligations or because shutting down and restarting would cost more than a few hours of paying to generate. This must-run generation deliberately accepts negative prices.
• The remuneration logic of renewables: plants with a feed-in tariff or market premium long kept feeding in even when the market price was negative, because the subsidy offset the loss. This is exactly where the legislator has now intervened; more on that below.

For scale: in 2025 the day-ahead price was negative in 573 of 8,760 hours, which is 6.5 percent of the time and a new record after 457 hours in 2024. The lowest value was around −250 €/MWh. For comparison: in all of 2016 there were 97 such hours.

Why are negative electricity prices increasing?

Negative electricity prices are increasing because photovoltaics is growing faster than the system's ability to shift its output in time. By the end of 2025, around 117 gigawatts of PV were installed in Germany; on clear days, solar generation at midday regularly exceeds what the market and the grid can absorb. Storage, flexible consumers and export capacity are growing too, but more slowly. As long as that gap persists, hours of oversupply keep accumulating; for 2026, analysts expect 700 to 900 negative hours. Whether growing demand from data centres closes that gap is a separate question: their load profile is even across the year and only partly coincides with the midday hours (Data centres and AI: what the new electricity demand means for solar and storage investors).

Important for context: negative hours are not a market malfunction, they are its clearest price signal. The system has too little flexibility, and it now pays for it to be provided. Which side of that signal an investment sits on determines whether it loses or gains from it.

What do negative prices mean for solar park revenue?

For new solar parks, negative prices first of all mean: no remuneration. Since the so-called Solar Peaks Act (Solarspitzengesetz), plants commissioned since 25 February 2025 lose their EEG payment claim in periods with a negative exchange price, from the very first negative quarter-hour (§51 EEG); the earlier grace period of several consecutive negative hours no longer exists for new plants. This hits exactly the midday hours in which a solar park produces the most. Milder transitional rules apply to older existing plants.

How does the compensation under §51a EEG work?

The hours are not entirely lost: under §51a EEG, the periods without remuneration are appended to the end of the 20-year support period; at today's levels of negative hours, this adds up to an extension of several months over the lifetime. Economically it is still not full compensation: the revenue arrives years later, in a phase when the plant has already aged, and the time value of money is lost. For project calculations this means the pure midday peak is worth less than it used to be, and projects that can steer their feed-in or combine it with a storage system have the advantage. What to consider when investing in solar parks in the first place is covered by Investing in solar parks: revenues, costs and tax leverage at a glance.

What is the solar capture price and why is it falling?

The solar market value (Marktwert Solar) is the volume-weighted average exchange revenue of a kilowatt-hour of solar power; the transmission system operators publish it monthly on netztransparenz.de. It is falling relative to the general price level because all solar plants feed in at the same time and thereby depress their own price; the technical term is cannibalisation. In numbers: the annual solar market value was 4.62 ct/kWh in 2024 and 4.51 ct/kWh in 2025, even though the general price level rather increased. The capture rate shows it more clearly, the ratio of the solar market value to the average exchange price: it fell from 0.84 in 2023 to around 0.5 in 2025. A kilowatt-hour of solar power is thus worth only about half as much on the market as an average kilowatt-hour. The value also swings enormously across the year: in 2025 it ranged from 1.8 ct/kWh in June to 11.5 ct/kWh in January. How award value and market value combine into a solar park's market premium is shown step by step in Direct marketing and the market premium: how a solar park earns its money.

Why are negative prices an opportunity for battery storage?

A battery storage system gets paid for charging during negative hours: it absorbs the electricity the market is currently paying to have taken, and sells it again when electricity is scarce and expensive. What is a revenue risk for inflexible generators is a source of income for flexibility. Concretely, this works through three channels:

• Paid charging: in the 573 negative hours of 2025, a charging storage system received money instead of paying it. That directly lowers the purchase cost of the arbitrage.
• A widening spread: the average daily gap between the cheapest and the most expensive hours in the day-ahead market rose from around 117 €/MWh in 2024 to around 130 €/MWh in 2025. The deeper midday prices fall, the wider this gap opens.
• More usable volatility: more frequent extreme hours mean more days on which a full charge and discharge cycle pays off.

How a storage system collects this revenue across day-ahead, intraday and balancing markets is explained in Direct marketing explained: day-ahead, intraday and balancing power; which return ranges realistically follow from it is covered by Battery storage returns: where the revenue comes from, and what is realistic.

How does a storage system turn the solar problem into a charging opportunity?

The division of labour is clearest when a solar park and a storage system share the same grid connection point. Exactly the quarter-hours in which §51 EEG cancels the solar park's remuneration are the cheapest charging windows for the storage system next to it: instead of letting the midday power be curtailed or fed in without payment, the storage system absorbs it and sells it into the evening peak. Out of the very market situation that weakens the pure solar profile, a second revenue stream emerges at the same site. Whether this co-located structure beats a stand-alone storage system, and where its limits lie, is compared in detail by Co-located vs. stand-alone: which gives the better risk structure.

Where are the limits of the storage opportunity?

The honest counter-argument: the storage advantage rests on an imbalance, and every new storage system works to shrink it. The more flexibility comes onto the grid, the more the price peaks that all storage systems live on are smoothed out; the cannibalisation that depresses solar revenue today reaches the storage side as well as build-out grows. On top of that comes the regulatory framework, which can change quickly in a market growing this fast; the Solar Peaks Act itself is the best example. Record years like 2025 therefore cannot simply be extrapolated over twenty years. How market size, build-out and grid connection queues are developing is covered by Germany's battery storage market: the numbers, the drivers, and why "now" has a date; the structural risks of a storage investment are sorted by Risks in BESS direct investments, and how they are structurally addressed.

What does this mean for investors?

Negative electricity prices shift value from inflexible generation to flexibility; that is the core message behind all the individual figures. For a pure solar profile it means: calculate conservatively. A project calculation that extrapolates past market values and ignores the unremunerated hours is too optimistic; the right question for any provider is which market value path and how many negative hours the calculation assumes. For battery storage and solar-plus-storage combinations, the same trend is supportive, but it does not replace proper project due diligence: storage revenue, too, consists of market variables with ranges, not guarantees. Independent of the market profile, the second lever remains the tax side: an entrepreneurial direct investment in a solar park or storage system can be structured via the investment deduction (Investitionsabzugsbetrag) under §7g EStG; how that works out in numbers is shown by IAB under §7g EStG: example calculation for battery storage.

Whether a specific project benefits from these mechanisms or suffers under them is not written in the marketing material but in the revenue assumptions. Those are exactly what we go through in a non-binding first call: remuneration structure, market value assumptions, storage combination and tax effect, on real project figures instead of buzzwords.