France’s CRE redesigns its solar tender to incentivise co-located batteries
France’s CRE redesigns its solar tender to incentivise co-located batteries
Across Europe, solar capture rates are declining as installed capacity grows. In France, the ratio of solar capture price to positive baseload capture price fell from 97% in 2022 to 60% in 2025.
Despite this, current tender conditions have not made co-location economically attractive, and the capture rate for awarded assets has been declining.
The French energy regulator (CRE) recently published a consultation proposing to redesign the contract-for-difference scheme for solar assets awarded from 2027 onwards. The proposed framework would directly incentivise the co-location of batteries with solar projects.
New solar tenders should allow PV to charge co-located batteries during negative-price hours
Under current rules, a PV plant must stop producing during negative-price hours to receive compensation.
The current system prevents a co-located battery from charging from PV during those hours, as the regulator classifies any energy flow as production.
The proposed framework replaces "non-production" with "non-injection." Exports to the grid remain prohibited, but PV can now feed power directly into the battery. The battery discharges later when prices turn positive.
To make this enforceable, the CRE proposes a new metering scheme that tracks energy flows separately at the PV array, the battery, and the grid connection point. Only PV-to-battery charging qualifies for the premium.
The new proposed CfD structure transfers solar cannibalisation risk to the developer
Under historical PPE2 solar tenders, the CfD top-up has been calculated against the solar capture price. As installed capacity grows, this reference has decoupled from the baseload average, falling from 97% of the positive baseload capture price in 2022 to 60% in 2025.
This decline raises the public cost of the CfD, as the state must compensate for a widening gap between the guaranteed tariff and a shrinking market reference price.
The CRE proposes indexing the CfD to the positive baseload capture price instead. The developer therefore bears the shortfall when solar output clusters in low-price hours, and has a direct financial incentive to avoid them.
Co-locating a battery is the most direct way to do so by shifting output from oversupplied midday hours to higher-value evening periods, narrowing the gap between the solar capture rate and the baseload reference.
The improvement varies by region: southern sites concentrate output in a narrow midday window, where cannibalisation hits hardest, while northern sites spread generation across a flatter summer profile.
The new compensation formulas could cut uncompensated negative hours for hybrid projects
Negative prices have become a growing structural problem for French solar producers. In 2025, France recorded 513 negative-price hours, up sharply from previous years. They concentrate in spring and summer, when solar output peaks.
The pattern is predictable: negative prices cluster between 10h and 16h from March to September, precisely when PV plants generate the most. As more capacity comes online, these hours will only multiply.
Under current rules, PV plants must curtail production during negative-price hours to receive the Pneg premium. The state compensates curtailed output at 50% of Pmax per hour, capped at 1,600 minus the project's annual full-load hours (FLH).
A project generating 1,300 FLH can claim compensation for at most 300 negative-price hours per year. As negative-price hours multiply, an increasing share falls outside this cap and receives no compensation.
To give producers the tools to manage this exposure, the CRE proposes three new formulas:
- Option 1 (CRE preferred): removes the FLH-based cap and introduces a daily 2-hour franchise period. Compensation remains at 50% Pmax. Hybrid projects can absorb franchise hours by charging the battery instead of curtailing, reducing uncompensated exposure to near zero.
- Option 2: halves the compensation rate to 25% Pmax and retains a franchise period. This widens the uncompensated gap for all projects and provides the weakest protection against negative-price exposure.
- Option 3: retains the 50% Pmax rate but sets a fixed annual franchise of 300 uncompensated hours, applying only between 8h and 20h.
The simulator below estimates uncompensated negative-price hours based on a project's solar yield, battery size, and assumed negative-price volume.
Methodology
Simulation: We simulate 1 MW of PV across every hour of 2025, using the EPEX Spot day-ahead negative-price distribution from ENTSO-E (France). The hourly distribution shape is fixed from 2025 data; the "Neg-price hours" slider scales the total volume while preserving this shape. The PV profile follows a Gaussian curve centred on solar noon, calibrated to the selected yield. The BESS charges from PV during negative-price hours and discharges at evening peak (17h–21h).
Compensation approximation: The CRE compensates a flat 50% × Pmax per hour, regardless of actual output. Since the average solar capacity factor during daylight is close to 50%, this approximately covers 100% of real curtailed production, consistent with the CRE's own Table 7 (note of 5 March 2026). Plants with high DC/AC ratios may see real output slightly above 50% × Pmax, meaning compensation covers marginally less than 100%. For Option 2, the halved factor (25% × Pmax) covers roughly 50% of real output.
Residual uncompensated hours under Option 1: even with a 2-hour battery, a small number of hours remain uncompensated. This occurs when the battery is already full at the start of a new negative-price sequence, typically during multi-day episodes in spring when negative prices arrive early and the battery has not fully discharged from the previous day. A dispatch algorithm that anticipates negative-price hours via day-ahead prices can reduce this residual further.
Germany's experience suggests that old and new tender prices could converge quickly
Germany's Innovationsausschreibung has required co-located storage since 2022. The core logic matches France's proposal: a battery absorbs low-price hours and shifts output to higher-value periods.
Germany's early hybrid rounds were undersubscribed, with awarded prices starting at 83 €/MWh. As the tender became competitive, prices fell to 53 €/MWh within two years, converging with EEG PV-only auctions at around 50 €/MWh.
The premium for co-located storage shrank as more developers entered and learned to price the value of energy shifting.
The two frameworks differ on several points. Germany prohibits grid charging and sets a minimum battery ratio of 25% with a 2-hour discharge requirement. France imposes no such ratio and allows grid charging.
This gives French developers more levers to extract value from the battery, but also more variables to optimise. In recent CRE solar tenders, the average awarded price was 79 €/MWh.
The new hybrid cap at 95 €/MWh gives developers a buffer for battery capex. That buffer will compress as developers learn to size and dispatch hybrid systems more efficiently.
Solar IPPs should model hybrid designs before the first tender opens
The consultation response deadline is 30 April 2026, and the first hybrid tender could open in late 2026 or early 2027.
Solar IPPs should already be modelling the revenue impact of each compensation formula, testing how the injection constraint affects optimal battery sizing at different irradiance levels, and adjusting permitting strategies for co-located configurations.
Developers who have completed this design work before the first tender opens will be best positioned to bid competitively.
