10 minute read | February.27.2026
Germany plans to introduce a double-sided CfD regime. Here’s what developers, plant operators and investors need to know.
A leaked draft of Germany’s Renewable Energy Sources Act 2027 (EEG 2027) signals a major shift in renewables support. The draft is dated 22 January 2026 and is still under inter-ministerial review.
The unpublished proposal draft introduces two‑sided Contracts for Difference (CfDs). This means operators receive market premiums in low‑price years but must repay excess revenues through a refinancing contribution in high‑price years, in line with EU market and state‑aid rules.
The draft also abolishes fixed feed-in tariffs (among other things), discontinues support for installations below 25 kW and introduces resilience auctions under the EU Net-Zero Industry Act, but the following focuses solely on the CfD mechanism. Overall, the draft marks a paradigm shift from a one‑sided market premium to a symmetric CfD regime, bringing Germany closer to the UK model while adding features such as dynamic low‑price adjustment and an exit option.
Two key figures drive the new CfD mechanism:
The applicable value (AV) (anzulegender Wert): essentially the strike price, typically set by the operator's auction bid.
The annual market value (AMV) (Jahresmarktwert): the technology-specific average market price for electricity from renewable sources over a calendar year, calculated retrospectively.
Under the current EEG, payments only flow one way. If the energy carrier-specific monthly average market value falls below the AV, the operator receives the difference as a market premium (MP). If the energy carrier-specific monthly average market value exceeds the AV, the operator simply keeps the surplus. Under the new system, this becomes symmetric: in calendar years where the AMV exceeds the AV, the operator must pay back the difference as a refinancing contribution (RC).
The formulas:
Support year (AMV < AV): MP = AV – AMV (grid operator pays plant operator)
Clawback year (AMV > AV): RC = AMV – AV (plant operator pays grid operator)
Neither value can go below zero.
Installations with an installed capacity of 100 kW or more will only receive support if the operator notifies the grid operator in text form that it wishes to participate in the support scheme. By opting in, the operator also accepts the clawback obligation. The deadline is six months after commissioning. Miss it, and neither support nor clawback applies.
The clawback applies to all installations of 100 kW or more that hold an auction award or have submitted a support declaration. Installations below 100 kW are exempt. Biomass installations are exempt regardless of size, as required by the EU Electricity Internal Market Regulation. Post-subsidy installations taken off by the grid operator also fall outside the clawback, since they hold no auction award or support declaration.
Importantly, the clawback cannot be avoided by switching to "other direct marketing.” In this case, the operator can make opt to stop receiving the market premium and instead sell its electricity directly on the market – without the market pregium – but in return can claim guarantees of origin for the green electricity produced. This is typically used by operators who want to market their output under a green PPA rather than relying on the EEG subsidy. Operators within the support scheme remain subject to the refinancing contribution regardless of how they sell their electricity.
Plant operators get a one-time, irreversible right to leave the entire support scheme – both the market premium and the clawback. The exit notice must be submitted in text form to the grid operator no later than ten years after commissioning. From the first calendar day of the following year, both the promotion scheme and clawback cease – permanently, with no way back.
The ten-year cap is designed to prevent operators from gaming the system by staying in during low-price years and exiting just before anticipated high-price periods. Such behaviour could amount to overcompensation under EU State aid rules. Operators who exit the promotion scheme are expected to secure revenue through long-term PPAs instead.
In a clawback year, there may be individual quarter-hours where the spot price is very low. If the operator had to pay the full refinancing contribution (RC), feeding in would be uneconomical. The draft addresses this with a dynamic adjustment mechanism.
In a given quarter hour, whenever spot price ≤ RC + minimum revenue, the refinancing contribution (RC) is adjusted:
RCadjusted = Spot price – minimum revenue
The technology-specific minimum revenues are provisionally set at:
Bottom line: the operator always retains at least the minimum revenue per quarter-hour, as long as the spot price exceeds that threshold. This aims to cover running costs and keeps the feed-in incentive alive.
Market premium and refinancing contribution (RC) are calculated retrospectively on an annual basis using the AMV. During the calendar year, monthly interim payments are due by the 15th of each month for the preceding month. These can be based on the previous year's market value. Overpayments or underpayments are settled with the final annual invoice.
All examples below assume an onshore wind installation with an AV of 6.0 ct/kWh (awarded auction bid price).
Example 1: Refinancing year with high electricity prices
| Parameter | Value |
| Annual market value (AMV) | 9.0 ct/kWh |
| Applicable value (AV) | 6.0 ct/kWh |
| Refinancing contribution (RC = AMV – AV) | 3.0 ct/kWh |
| Annual feed‑in | 10,000,000 kWh |
| Total refinancing contribution | EUR 300,000 |
In this scenario, the annual market value (AMV) significantly exceeds the applicable value. The plant operator generates market revenues of EUR 900,000 but must transfer EUR 300,000 as a refinancing contribution. The remaining EUR 600,000 corresponds exactly to the awarded value.
Example 2: Dynamic adjustment in low‑price quarter‑hours
Assume, as in Example 1, that the refinancing contribution amounts to 3.0 ct/kWh and the minimum revenue for onshore wind is 1.0 ct/kWh. The adjustment threshold is therefore 4.0 ct/kWh (RC + minimum revenue).
| Spot market price | Adjustment required? | Refinancing contribution | Remaining revenue |
| 8.0 ct/kWh | No (8 > 4) | 3.0 ct/kWh | 5.0 ct/kWh |
| 3.0 ct/kWh | Yes (3 ≤ 4) | 2.0 ct/kWh (= 3 – 1) | 1.0 ct/kWh |
| 0.5 ct/kWh | Yes (0.5 ≤ 4) | 0.0 ct/kWh (floor) | 0.5 ct/kWh |
The dynamic adjustment prevents plant operators from generating a negative contribution margin during low‑price periods. The minimum revenue of 1.0 ct/kWh is always retained – or, if lower, the full spot‑market revenue.
The German model clearly takes cues from the UK CfD scheme (in place since 2014) but differs in several important respects. While both systems are two-sided – the UK pays generators when market prices fall below the strike price and claws back the difference when prices exceed it – the German version is statutory rather than contractual. This means there is no private law agreement with a counterparty like the UK's Low Carbon Contracts Company. Instead, the rights and obligations arise directly from the EEG.
The most striking difference is settlement methodology. The "genuine" two-sided CfD would, in every quarter-hour interval, skim off or compensate for the difference between the spot market price and the applicable reference value. Instead, the EEG 2027 adopts a simplified approach on an annual basis, which corresponds to the existing market premium system. There are practical reasons for this:
The system could therefore be described as a "CfD light" or an annual-basis CfD – it meets the European law requirements for revenue clawback while largely preserving market incentives within any given year. Reference to the retrospective annual market value under the German “CfD light” model means that the final amount owed or receivable is only known after year-end. However, monthly interim payments partially offset the resulting cash-flow uncertainty.
Furthermore, the support period is also longer: 20 years under the EEG versus 15 years under the UK CfD.
Three features are unique to the German model. First, the dynamic adjustment for low spot prices ensures operators retain a minimum revenue even in quarter-hours with weak but positive prices – a mechanism the UK scheme does not have. Second, the one-time exit right allows operators to permanently leave the support (and clawback) system within the first ten years, whereas UK generators cannot unilaterally walk away from their CfD contract. Third, the German clawback only applies to installations of 100 kW or more and explicitly excludes biomass, whereas the UK scheme applies to all awarded projects without a capacity threshold.
Pros:
The CfD provides a symmetric hedge against price volatility. In low-price years, the market premium continues to protect. At the same time, clawback revenues in high-price years reduce the burden on the federal budget and, ultimately, on taxpayers. The dynamic adjustment mechanism prevents uneconomic feed-in during low-price quarter-hours. The exit option provides a degree of flexibility absent from the UK model.
Cons and risks:
The annual retrospective calculation creates cash-flow uncertainty. The final amount due is only determined after year-end, leaving operators exposed to top-up payment risk if actual market values diverge significantly from interim payment assumptions.
The upside cap limits the profit potential of subsidised installations. This may reduce equity returns in high-price phases and make EEG support less attractive for projects that could be commercially viable without subsidies. It may also affect bankability as lenders will factor the capped upside into their credit assessments.
The clawback applies even in "other direct marketing". This prevents circumvention by switching marketing routes, but also limits flexibility when structuring green PPAs. Operators can still switch to obtain guarantees of origin, but must pay the refinancing contribution regardless.
The irreversibility of the exit is a significant risk in itself: operators who leave bear full market exposure for the remainder of the installation's lifetime with no way back.
New installations face a trade‑off: EEG auctions offer downside protection but cap upside via clawback, making subsidy‑free, PPA‑backed projects potentially more attractive where commercially viable. The clawback applies only to new installations; existing plants remain under the EEG 2023 regime. Operators of ≥100 kW installations must opt in within six months of commissioning, requiring early strategic decisions.
A one‑time exit is possible within the first ten years but is irreversible and depends on price outlooks, financing and PPA availability. For project finance, the symmetric CfD alters risk profiles: while low prices are hedged, clawback, retrospective settlement and top‑up risk must be reflected in cash‑flow models and liquidity planning.
The choice between support (with clawback) and subsidy-free deployment (with uncapped upside but full market risk) becomes a critical strategic decision. Projects in the pipeline should start evaluating both routes now. The EEG 2027 is expected to enter into force on 1 January 2027, though the timeline is ambitious given ongoing inter-ministerial coordination, outstanding parliamentary approval and required EU State aid clearance.
Finally, it is to be noted that the final legislation may differ from the leaked draft bill. Interested parties should closely monitor the ongoing legislative procedure. We will keep you updated.