Understanding PPAs: how power purchase agreements make solar park revenues predictable

Few acronyms appear as often in documents on solar direct investments as “PPA”. It stands for power purchase agreement: a contract under which the plant sells its electricity for years at contractually agreed terms to a fixed offtaker, instead of marketing every kilowatt-hour at the daily exchange price. For investors this is not a side note on vocabulary: the PPA plays a decisive role in how predictable a project's revenues are, and in who carries which market risk.

This article explains the contract logic at the depth needed for investment analysis: the difference to the EEG subsidy, the common price structures, and the points at which a revenue floor is less solid than it first sounds. How a solar park earns money overall is covered in Investing in solar parks; here the focus is on the contractual side of the revenues.

What is a PPA?

A PPA (power purchase agreement) is a longer-term electricity supply contract between a generating plant and an offtaker: the park commits to deliver electricity, the offtaker commits to purchase it over the contract term at an agreed price or price formula. Offtakers are either utilities and electricity traders, or large consumers directly: industrial companies, rail and logistics groups, data centres. Typical terms range from a few years up to 15 years; recently, shorter contracts with terms under five years have become more common in Germany.

At its core, the contract is a distribution of risk: the offtaker secures long-term green power at calculable cost, the plant secures a calculable outlet. Both give up upside in return. If exchange prices rise, the park has sold too cheaply; if they fall, the offtaker has bought too dear. Precisely this symmetry makes the PPA a planning instrument, not a subsidy: it shifts market risk, it does not remove it.

Why do solar parks sign PPAs at all?

Because not every solar park receives an EEG subsidy, and because banks want to see predictable revenues. Statutory support for ground-mounted plants of 1 MW and above runs through tenders held by the Federal Network Agency: whoever wins an award receives a sliding market premium on top of the achieved market value for 20 years, up to the awarded reference value; how this sliding market premium works in detail is explained in Direct marketing and the market premium: how a solar park earns its money. Since the Solar Package I legislation (2024), the maximum bid size in these tenders has been 50 MW. Very large parks beyond that limit, projects without an award, and plants that have reached the end of their 20-year support period need a different form of revenue security, and that usually means a PPA.

Then there is the financing logic: a bank financing a park over 15 or more years wants to know which revenues will service the debt. An award from the EEG tender or a PPA with a creditworthy offtaker fulfils that role as a revenue floor; pure merchant marketing without any hedge usually does not. In practice, many projects therefore layer both building blocks: a secured floor plus a market-based share that can benefit from rising prices. On the offtake side a regulatory driver has been added: under §11 (5) EnEfG, data centre operators must cover their electricity 100 percent from renewable energy on a balance-sheet basis from 1 January 2027, which makes them possible counterparties for long-term offtake agreements (Data centres and AI: what the new electricity demand means for solar and storage investors).

What types of PPAs exist?

Two distinctions are enough for investment analysis: who buys, and how delivery works. In a utility PPA, the offtaker is a utility or electricity trader that markets the power onwards. In a corporate PPA, a company buys the electricity for its own consumption, often also for the guarantees of origin that feed its climate accounting. In Germany, corporates dominate: of the 21 PPAs published in 2025, 16 were signed with corporate offtakers, above all from the transport, automotive and chemical sectors.

On the delivery side, physical PPAs, in which the electricity is actually delivered to the offtaker in balancing terms, are distinguished from financial PPAs, in which the plant continues to sell its power on the exchange and only the difference between market price and contract price is settled with the offtaker. Economically both work the same way: they fix the revenue per kilowatt-hour. For assessing an investment, the delivery form is therefore secondary; what matters are price, term and offtaker.

How is the price in a PPA structured?

The dominant structure in Germany is “pay as produced”: the offtaker takes the electricity exactly as the plant produces it, with the full solar profile including the midday peak, and pays a fixed price per megawatt-hour for it. The profile risk thus sits with the offtaker, which is why this price lies below the baseload price on the futures market. Alongside it exist structures such as “pay as nominated” or baseload deliveries, in which the park owes a fixed delivery profile and must balance deviations itself: higher prices, but also more risk on the plant side.

For orders of magnitude: for ten-year solar PPAs in the pay-as-produced structure, indicative prices in Germany recently stood at around €35 to €45/MWh (as of the April 2026 market analysis). The contract price can be fixed over the term or linked to inflation or an index via an escalation clause; a fixed price is predictable but, precisely for that reason, does not grow. Increasingly, PPAs also explicitly regulate what applies in hours with negative exchange prices: deliveries are then often excluded, priced separately or capped in volume. Why these hours have become so relevant for solar plants is explained in Negative electricity prices: what they mean for solar and storage investors.

PPA or EEG subsidy: which is better for investors?

It is rarely an either-or question. The EEG award is state-backed for 20 years and carries no counterparty risk; in return it comes with conditions, above all the rule in section 51 of the EEG under which no subsidy is paid in hours with negative prices. In 2025, almost a quarter of German solar generation already fell into periods of negative prices; the statutory safety net has a growing hole exactly where solar plants produce the most. A PPA, by contrast, is freely negotiable, including on the treatment of negative hours, but depends on the creditworthiness of a single offtaker and typically on shorter terms.

In project practice the two instruments therefore complement each other rather than compete: part of the revenues is secured via the award or a PPA, part runs close to the market via direct marketing. Combining the park with a battery storage system at the same grid connection also changes the calculation, because the storage system can shift the midday peak into more expensive hours; the structure behind this is described in Co-located vs. stand-alone. What counts in the end when assessing an investment is the revenue mix of the specific park: how much is secured, for how long, at what price, and what is left to the market?

What does a PPA mean for the risk profile of an investment?

A PPA makes revenues more predictable, but it does not make them safe. Three points belong in any sober assessment. First, counterparty risk: a fixed price over ten years is only as reliable as the offtaker paying it. The creditworthiness of the PPA offtaker is therefore a review item in its own right, not a detail. Second, the term gap: a solar park produces for 30 years and more, a PPA often runs considerably shorter, and the market trend has recently been towards terms under five years. What applies after the contract ends (a follow-on PPA, market values, the price assumption in the model) carries a substantial share of the total return. Which paths are open to a solar park at the end of the subsidy period is shown in A solar park after 20 years: continued operation, repowering or decommissioning?.

Third, the market phase: the German PPA market has cooled recently. The number of published deals fell from 51 (2024) to 27 (2025), contracted capacity from 2.2 to 1.3 GW, with the sharpest decline in the solar segment; Germany dropped from second to fourth place in the European ranking. The background is falling market values and uncertainty over the treatment of negative prices. For investors this does not mean PPAs are no longer available; it means the terms of the specific contract are what count, and a prospectus calculating with the PPA prices of 2022 is out of date. Whether such secured revenues also protect against inflation depends on the escalation clause; the broader picture is covered in Real assets as inflation protection: what actually protects and where energy assets fit in.

Do PPAs exist for battery storage too?

Yes, they just go by a different name there. A battery storage system does not sell a predictable volume of electricity but flexibility; the counterpart to the PPA is therefore the tolling agreement (also called a flexibility purchase agreement): a marketer or utility pays a fixed fee per megawatt and year and, in return, operates the storage system across the electricity markets for its own account. Alongside it exist floor models with a guaranteed revenue floor and profit sharing above it. How these models distribute market risk between project and marketer is explained in detail in Direct marketing explained: day-ahead, intraday and balancing power.

This market is currently growing fast: the volume of storage marketing agreements signed in Germany more than doubled in 2025 to around 1.1 GW year on year, and the share of contracts with fixed price hedging is rising, because banks demand revenue security at higher debt ratios. For risk assessment, the same logic applies as with the solar PPA: a tolling agreement trades market upside for predictability and depends on the creditworthiness of the contracting party. Which further risks should be structurally addressed in storage investments is collected in Risks in BESS direct investments, and how they are structurally addressed.

What this means for direct investments

For assessing a specific project, the PPA is not a seal of quality but a contract that can be reviewed. The revenue assumptions of a prospectus can only be judged once it is clear which share of production is secured over which period at what price, and what is assumed afterwards. Questions you should ask any provider:

• Which share of revenues is secured via EEG award, PPA or merchant marketing, and over which term in each case?
• Who is the PPA or tolling offtaker, and how is their creditworthiness evidenced?
• How does the contract handle hours with negative prices, and what share of such hours does the revenue model assume?
• Is the contract price fixed or indexed, and which price assumption applies after the contract term ends?
• Does the model calculate with current market prices or with historical PPA terms?

These questions double as a seriousness test: a provider who cannot or will not explain the revenue structure of their own project precisely is either avoiding transparency or does not know it themselves. Further warning signs and review questions are collected in How to tell a trustworthy provider of energy direct investments.

What the revenue structure looks like in a concrete project (which floor is secured, who the offtaker is, which assumptions the model uses) is what we discuss in a no-obligation initial consultation: based on real contract data, with named assumptions. We give no return promises in doing so.