EEG 2027: what the refinancing contribution means for a solar park direct investment

Since 7 September 2026 the government draft of the EEG 2027 has been before the Bundestag. For investors who operate a solar park as a direct investment or are currently assessing one, one point matters more than all the others: support for new plants becomes two-sided. What that means in the day-to-day of an operation, which projects it affects and what changes in the return calculation is what this article sets out, based on the statutory text and on our own look back at the past seven years.

What changes in the market premium from 2027?

The direction of payment. Today the market premium is a one-way street: the grid operator pays the difference between the applicable value, normally the award value from the tender, and the solar market value. If the market value falls below the applicable value, money flows; if it rises above, the premium becomes zero and the operator keeps the full exchange revenue. The draft adds the reverse direction in §21d: for every calendar year in which the annual solar market value exceeds the applicable value, the operator pays the difference for every kilowatt hour fed in as a refinancing contribution to the grid operator. Anlage 1 states both in two lines: market premium equals applicable value minus annual market value, refinancing contribution equals annual market value minus applicable value, each with zero as the floor.

Three details decide the effect. First, the benchmark: the calculation uses the annual solar market value, the volume-weighted exchange revenue of all German solar plants in the calendar year, which the transmission system operators publish after year end. Not the revenue of the individual plant. A park whose daily profile earns more than the average keeps that lead in both directions; how the profile comes about is shown in South, east-west or vertical: which solar park layout pays off for investors. Second, settlement: under Anlage 1 both payments are calculated annually and retroactively, as already applies today to the market premium of plants commissioned from 2023. During the year, monthly instalments run in both directions under §26, measured for instance against the previous year's annual market value; the refinancing contribution falls due four weeks after the grid operator's final statement. Third, the threshold: the payment obligation starts at 100 kilowatts of installed capacity. Every ground-mounted park is above it, including the plant below one megawatt that takes its applicable value from the statute without a tender.

For plants under the current law, by contrast, nothing changes, not even the calculation against the monthly market value that continues for plants commissioned or awarded before 2023. How the market premium works today and what the direct marketer does is explained in Direct marketing and the market premium: how a solar park earns its money.

Would the refinancing contribution have applied in recent years?

Yes, in three of seven years. To show the order of magnitude, we take the volume-weighted award value of the tender of 1 July 2026, 4.79 cents per kilowatt hour, as the applicable value and run it against the official annual solar market values of 2019 to 2025. This is a model assumption: a plant with this award did not exist in any of those years, and future bids will price the mechanism in. The structure still becomes visible.

The sum is unambiguous. Over the seven years the plant would have received 4.1 cents per kilowatt hour in market premium and repaid 22.7 cents, of which 17.5 cents for 2022 alone. Translated to a park with one megawatt of capacity and around 1,000 kilowatt hours per kilowatt of annual yield, that is roughly EUR 175,000 of refinancing contribution for the year 2022. Under the current law that revenue would have stayed with the operator, at least until the revenue skimming of the Electricity Price Brake Act, which also collected part of it from December 2022 to June 2023. In the other four years almost nothing changes: the premium is paid either way, and in 2024 as in 2025 the annual market value was only just below the assumed award value.

What the look back does not show is the plant's own capture price. A park does not earn the annual market value on the market, it earns its own profile. If that profile is above the average, the difference stays with the operator even in a clawback year; if it is below, it is missing in a premium year too. Which assumptions the yield assessment should state on this is described in Reading a yield assessment: what P50 and P90 mean for a solar park direct investment. Direct marketing costs come on top in both worlds.

Which projects stay under the current law?

All those commissioned before 1 January 2027 or whose applicable value was determined in a tender round before that date. That is what §100 paragraph 1 of the draft says; for these plants the EEG in its version of 31 December 2026 continues to apply, with the one-sided market premium and without a refinancing contribution. For a direct investment, the decisive date is therefore not the commissioning date but the tender date of the award. A park awarded in December 2026 and completed only in 2028 stays under the current law; a park that first bids in spring 2027 falls under the new mechanism, even if it builds faster. According to the Federal Network Agency, the last tender date of the first segment before the cut-off is 1 December 2026.

Two additions. For ground-mounted plants below one megawatt that feed in without a tender, only the commissioning date counts. And an award is no guarantee of construction: it lapses if the plant is not commissioned within the statutory realisation period. Whether grid connection, building permit and supply chain support that deadline is therefore part of the review; what needs clarifying is shown in Investing in solar parks: revenues, costs and tax leverage at a glance.

Can an operator avoid the clawback?

Only by giving up the support for good. §21e allows the operator to notify the grid operator in text form that it will permanently stop claiming the market premium; from 1 January of the following year, claim and payment obligation then lapse together. The notification is a one-off, irrevocable and possible only until the end of the tenth calendar year after commissioning. The explanatory memorandum states the reason openly: anyone able to leave in high-price years and return in low-price years would render the clawback meaningless. The exit is therefore a bet on the market for the rest of the term, hedgeable at most through a long-term offtake agreement; what such a contract delivers and costs is set out in Understanding PPAs: how power purchase agreements make solar park revenues predictable.

Two routes do not work. Switching to other direct marketing, that is selling without the market premium while the support claim continues, does not release the operator from the payment obligation under §21d paragraph 1; the draft closes exactly this loophole. And the detour via a storage system does not help either: through the reference to §19 paragraph 3, the payment obligation also covers electricity that was stored before being fed in. What a storage system at the same grid connection does otherwise is set out in Co-located vs. stand-alone: which gives the better risk structure.

What happens in negative-price and low-price hours?

In quarter hours with a negative spot price, both become zero. §51 of the draft sets the payment claim and the payment obligation to zero alike for these periods; for the market premium that continues today's rule, for the refinancing contribution it is new and necessary. Without it, an operator would pay in a clawback year even for hours in which it loses money on the exchange itself. The compensation under §51a remains: the payment period is extended by the quarter hours concerned, for solar plants with a factor of 0.5. How often these hours now occur and what they do to the market value is covered in Negative electricity prices: what they mean for solar and storage investors.

For hours with a low but positive price, Anlage 1 Nr. 4.2 contains a second brake. If the spot price of a quarter hour does not exceed the sum of the refinancing contribution and a minimum revenue, the operator pays only the spot price less that minimum revenue; for solar power it is 0.5 cents per kilowatt hour. In such hours the operator should keep no less than its running costs, according to the explanatory memorandum. How much this rule dampens the annual contribution depends on how many quarter hours fall below the threshold: few in a high-price year, considerably more in a year with many summer hours close to zero.

What does this mean for the return of a direct investment?

The floor stays, the ceiling goes. That is the trade in one sentence. Downwards, the applicable value continues to secure every kilowatt hour fed in outside negative hours; for the financing bank nothing changes in the downside case. Upwards, the revenue of the supported electricity is capped at the applicable value as long as the plant stays in the support scheme. What the look back shows is therefore not a loss in the base case but the removal of an upside that the base case of most prospectuses does not include anyway.

Two caveats belong here. First, inflation: the applicable value is nominal and fixed for twenty years. If power prices rise with the general price level, the annual market value grows nominally above the applicable value, and that is exactly when the refinancing contribution applies. The explanatory memorandum says so itself: because of the inflation-driven rise in nominal annual market values alone, clawback years become more likely over the term, and for photovoltaics relevant clawback revenues are conceivable. The park keeps its character as a real asset, but the revenue of the supported electricity becomes a nominally fixed quantity; what real assets do and do not deliver against inflation is set out in Real assets as inflation protection: what actually protects and where energy assets fit in. Second, bidding behaviour: whoever knows the cap bids higher. The memorandum expects this too, and under §37b the maximum value of the first segment will in future be derived from the awards of the previous rounds, with an upper limit of 5.9 cents per kilowatt hour. Part of the lost upside therefore comes back through higher award values; how much is decided by competition in the rounds from 2027.

The tax side is untouched. The investment deduction allowance, the special depreciation and the declining-balance depreciation attach to the investment, not to the support mechanism; how they work together is explained in The Investitionsabzugsbetrag explained simply: how the IAB works. And for operating parks commissioned or awarded before 2027, nothing changes on the revenue side.

Which questions should you ask the provider?

• Which tender date does the award come from, and is it before 1 January 2027? For plants below one megawatt without a tender: when is commissioning planned, and how robust is that date?
• Which version of the EEG does the revenue model use, and is the refinancing contribution deducted in the high-price scenarios? A model that carries the one-sided market premium forward beyond 2027 is too optimistic.
• Which market value does the model assume, the annual solar market value or the capture price of the plant's own profile, and is there a yield assessment with an hourly profile to support it?
• How does the direct marketing contract handle the monthly instalments and the grid operator's final statement, and who carries the liquidity if the final statement results in a back payment?
• Is there a storage system at the grid connection, and does the model take into account that stored electricity is also subject to the payment obligation?
• Who decides on a waiver under §21e, and is that decision reserved to the investor in the operating agreement?
• What happens if the Bundestag changes the draft before the award: is there a right of withdrawal or an adjustment clause in the contract?

Where does the legislative procedure stand?

The draft is in the Bundestag but has not been passed. The federal cabinet adopted it on 29 July 2026, it has been available as printed paper 21/7867 since 7 September, and according to the agenda the first reading is scheduled for Thursday, 24 September 2026. Committee deliberations, the second and third readings and the Bundesrat follow. The draft aims at entry into force on 1 January 2027; under §104 the support provisions are additionally subject to state aid approval by the European Commission. The procedure is unlikely to overturn the two-sided mechanism itself: Article 19d of the European electricity market regulation requires two-way contracts for difference or equivalent schemes for support contracts concluded from 17 July 2027. What is negotiable are thresholds, minimum revenues, exit deadlines and the transition.

How we assess projects with this in mind

For every solar park we present to investors, we first check the tender date of the award and assign the project to the current or the new law. For projects under the new law we run the revenue model with capped revenue for the supported electricity and set the plant's hourly profile against the annual market values of recent years, as in this article. We make no return promises; we show which figure rests on which assumption. That is exactly what we do in a non-binding initial consultation, ideally on the basis of a specific prospectus.