German capacity market: what does it offer battery storage and solar parks?

Until now, a power plant or battery in Germany has earned money only by delivering electricity or holding balancing capacity. The Strom-Versorgungssicherheits- und Kapazitätengesetz (StromVKG, the electricity security of supply and capacity act) adds a second route: payment for being available in scarce hours. The act has applied since 22 July 2026, and the European Commission approved it under state aid rules on 2 September 2026. The first auction closed on 8 September 2026.

Investors in storage and solar projects face a simple question: is this additional money one can count on? The answer is shorter than the length of the act suggests. It turns on three points that are rarely explained together: who may bid at all, what the payment costs and when the figures will be known. We go through them in order.

What is the capacity market, in two sentences?

A capacity market pays for capacity, not energy: operators bid in auctions how much firm capacity they will keep available at what price per megawatt and year, and the transmission system operators pay the awarded value. It is financed through a levy on the electricity price, so that enough power plants, batteries and flexible loads are available even in a windless winter week.

What counts is not installed capacity but reduced capacity (reduzierte Leistung): installed capacity times a de-rating factor (§ 2 no. 30, § 22). The factor expresses how reliably a technology delivers in scarcity hours. In the long-term segment a gas plant counts at 0.85 and a photovoltaic plant at 0.02 (Annex 4). Every figure in the act, from payment to penalty, refers to this reduced capacity.

The first step is deliberately small. The StromVKG procures capacity for the delivery period from 1 November 2031 to 31 October 2032; a comprehensive capacity market is to follow, governed by a further act planned for 2027 (Bundestag printed paper 21/6279). The awards nevertheless run for up to 15 years.

How much does the capacity market pay, and for how long?

As much as the bidder itself bid, at most 244,000 euros per megawatt of reduced capacity and year (§ 39 (1)). The Bundesnetzagentur ranks the bids from the cheapest upwards and awards until the volume is reached; each award is paid at its own bid value (§ 48 (3) and (4)). There is no uniform clearing price that cheaper bidders also receive.

• Term: 15 years in the auctions for long-term capacity and for generation capacity (§ 12 (2)), 1, 7 or 15 years in the later technology-neutral rounds (§ 13 (2)). For those rounds the Bundesnetzagentur sets separate price caps per term (§ 39 (2)).
• Start: the first obligation year runs from 1 November 2031 to 31 October 2032 (§ 2 nos. 40 and 41). Nothing is paid before that.
• Payment: in arrears, within 60 working days after the end of each obligation year (§ 74 (3)). The first payment therefore arrives in early 2033 at the earliest.
• Minimum size: 1 megawatt of reduced capacity, also via a pool (§ 7).

Anyone investing today in a storage project that connects in 2027 therefore earns nothing from the capacity market for at least four operating years, even if it later wins an award.

When can battery storage take part in the capacity market?

In practice from the auction on 18 May 2027. The act classes a battery as a generation plant of an energy-limited technology class (§ 2 nos. 4, 10 and 37). In the two 2026 rounds, however, it only counts from ten hours of storage duration, because a long-term criterion applies there; the common two- to four-hour systems have no de-rating factor in those rounds. How the act values storage duration in detail is shown in 2-hour or 4-hour battery: which storage duration pays off for investors.

The Bundesnetzagentur determines the de-rating factors for the rounds from 2027 and publishes them at least six weeks before the announcement (§ 23 (1)); the announcement comes seven weeks before the bid deadline (§ 35 (1)). For 18 May 2027, by our calculation, the factors must be available by mid-February 2027 at the latest. Until then nobody knows how many megawatts a four-hour battery counts for.

What does a battery have to give back for the capacity payment?

The part of its peak revenues above the strike price. The act calls this the Preisspitzenausgleich, a peak-price payback (§ 81): for every quarter hour in which the day-ahead price exceeds the strike price, the operator pays the difference times its reduced capacity to the transmission system operator. And it does so regardless of actual operation (§ 81 (2)). A battery that is empty in that quarter hour pays just like one that is discharging.

The strike price (Ausübungspreis) mirrors the variable cost of an open-cycle gas turbine (Annex 7 no. 3): the previous day's gas price converted at 37 percent efficiency, plus CO₂ costs, plus 50 euros per megawatt hour for other costs, plus a future dynamic grid fee. It therefore rises and falls with gas and CO₂. At an assumed 35 euros per megawatt hour for gas and 70 euros per tonne of CO₂, it is around 193 euros per megawatt hour.

Economically, this is a swap. The battery keeps selling on the market, including in the most expensive hours; whatever exceeds the strike price it hands back. In return it receives the fixed annual payment. How much it hands back depends on how often and how high prices jump above the threshold. We recalculated this with the day-ahead prices of the last two years:

Measured against the 244,000-euro cap, that is little. Measured against a battery's business, it is noticeable: according to our arbitrage model, disclosed in the article on storage duration, around 7 percent of a four-hour battery's 2025 day-ahead revenue came from the part of prices above 193 euros, and just under 10 percent for a two-hour battery. That is the peak it gives up in the swap.

A second effect hits short batteries harder. On days with price peaks in 2025, an average of three hours were above the threshold. A two-hour battery can serve only two of them but pays for all three. On a net basis an award pays off as long as the bid value exceeds the expected payback plus the cost of obligations and securities. Bidding too low means selling one's best hours below value.

Which obligations and securities come with an award?

More than the annual payment suggests, and some of them tie up capital long before the first payment. The capacity market has no market exclusion: awarded plants keep trading on the spot and balancing markets, as the Bundesnetzagentur states in its procedural Q&A. But they are bound to the following:

• Availability: the bid capacity must be available; this is checked in high-price quarter hours, i.e. when the day-ahead price exceeds the activation price, which is the strike price plus 150 euros per megawatt hour (§§ 65, 66, Annex 7 no. 2). Shortfalls trigger a compensation payment (§ 76). Once a year, up to two full months between May and September can be exempted, then without payment (§ 67).
• Performance test: if the plant does not reach the awarded capacity in the test, a penalty applies. Compensation payments and penalty together are capped at twice the annual payment (§ 80 (3)).
• Securities: a bid security of 15 percent of the price cap per megawatt is due with the bid, 36,600 euros in the long-term rounds (§ 42). Further securities follow after the award (§§ 43, 44).
• Realisation: if a new build is not completed on time, a penalty of up to 1.5 times the bid value applies (§ 64).
• Minimum investment: with a term of 7 or 15 years, at least 201,000 or 431,000 euros per megawatt of reduced capacity must be invested after the award (§ 14).
• Grid-forming inertia (Momentanreserve): with a 15-year term, larger plants must provide inertia. A battery does so via an inverter rated above 130 percent of the agreed grid connection capacity; only the part above that counts (§ 16 (2)). That is additional hardware.
• No double support: the plant may not receive EEG or KWKG support during the term (§ 11 (1) no. 2).

Can a solar park take part in the capacity market?

As a rule, no. Three hurdles combine. First, § 11 (1) no. 2 excludes any plant that additionally receives EEG support during the term; a park with a market premium is therefore out. Second, photovoltaics cannot meet the long-term criterion of the 2026 rounds, ten consecutive hours at 80 percent of capacity (§ 12 (5)). Third, solar counts with a very small factor, 0.02 in the long-term segment (Annex 4).

For the later rounds the Bundesnetzagentur sets the factor anew. If it were similarly low, a park would need around 50 megawatts of installed capacity to reach the minimum size of one megawatt of reduced capacity. Participation remains theoretically possible for a large park without EEG support that runs purely on a power purchase agreement. In practice, it is not a revenue item for investors.

The battery at a solar park is an open question. According to the Bundesnetzagentur's Q&A, generation modules at the same site with a shared grid connection and a technical link count as one plant. Whether a battery sharing the connection with an EEG-supported park thereby falls under the support exclusion or can bid as a separate plant is not expressly regulated by the act. That calls for a legal review before any bid. The other pros and cons of a shared design are described in Co-located vs. stand-alone: which gives the better risk structure.

What changes for existing batteries and solar parks without an award?

Directly, nothing; indirectly, possibly the prices in the scarcest hours. According to the legislative explanatory memorandum, the technology-neutral rounds from December 2027 are also open to existing plants (Bundestag printed paper 21/6279), with terms from one year (§ 13 (2)). An existing battery can therefore apply there, but does not have to.

Indirectly, more firm capacity in the system can make scarcity peaks rarer. Batteries partly live off them, while solar parks barely benefit in those hours because they mostly occur in the evening and in winter. How strong the effect will be from 2031 cannot be quantified reliably today. We treat it as a risk in the scenario calculation, not as a forecast.

Who pays for the capacity market and what does it cost?

Electricity customers, via a levy whose procedure a further act is to regulate in 2027 (Bundestag printed paper 21/6279; likewise the Bundesnetzagentur). The federal government estimates the support costs at 1 to 3 billion euros for 2031 and 0.9 to 2.3 billion euros a year from 2032 to 2045. The European Commission puts the total measure at 15.6 to 35.2 billion euros (state aid case SA.106805).

For investors this is mainly a political risk: a levy of this size will be debated. Under current law it does not affect awards already granted; for future rounds, volumes and rules may still shift.

What belongs in the revenue forecast of a battery direct investment?

Today only a scenario, not a revenue item. There are four reasons. The de-rating factors for batteries have not been published. The bid value arises in competition and has never been observed for batteries. The first payment arrives in 2033 at the earliest. And an award costs peak revenues, securities and possibly additional inverter capacity.

Anyone aiming for a 15-year award must also set the battery's service life against the obligation: the cells must deliver the awarded capacity until 2046, otherwise compensation payments apply. How batteries age and when a replacement is due is covered in The battery as a real asset: lifespan, degradation and warranties of a grid-scale storage system. The other revenue sources a forecast should rest on are set out in Battery storage returns: where the revenue comes from, and what is realistic and Direct marketing explained: day-ahead, intraday and balancing power.

A sound presentation is one in which the project works without a capacity payment and the payment is shown separately as an option: with a stated bid value, a stated de-rating factor, the peak-price payback deducted and the year from which it is counted.

Which questions should investors ask about the capacity market?

• Does the revenue forecast include a capacity payment? If so: from which year, with which bid value and which de-rating factor, given that the Bundesnetzagentur has not yet published it?
• Is the peak-price payback under § 81 deducted? Which strike price was used?
• Does the project also work entirely without a capacity payment?
• In which round is a bid planned, and does the site meet the requirements of § 12 (3)?
• Is the inverter sized for grid-forming inertia under § 16 (2), and are the extra costs in the budget?
• Who provides the bid, realisation and performance securities, and what happens to them in case of delay?
• Is the battery's service life sufficient for a 15-year obligation, or is a cell replacement planned?
• Does the battery share its grid connection with an EEG-supported solar park? How has the support exclusion under § 11 been legally reviewed?

General checkpoints for any provider are listed in How to tell a trustworthy provider of energy direct investments.

How we assess the capacity market in projects

For every storage project we present to investors, we calculate the base case without a capacity payment. If a provider shows one, we recalculate it separately: with the stated bid value, the de-rating factor then applicable, the peak-price payback according to our model and the cost of securities and inertia. For batteries at solar parks we record whether the double-support question has been resolved. As soon as the Bundesnetzagentur publishes awards, factors and price caps, we align our assumptions and update this article.

We do not promise returns. What makes a battery attractive as a direct investment overall is set out in Investing in battery storage: the options at a glance. That is exactly what we check with you in a no-obligation initial consultation, gladly using a specific offering document.