In 2025, France produced 2.9 TWh of solar and wind electricity that it could not use. Excess production triggered episodes of negative prices for 513 hours during the year, and RTE ordered production adjustments. The law of April 30, 2025 requires, starting January 1, 2026 and above a threshold, the provision of technically available power to RTE through the balancing mechanism. Producers subject to the 10 MW threshold set by market rules approved by the CRE must participate according to these rules.
The essentials
- France recorded approximately 2.9 TWh of modulation in 2025; this increase stems primarily from legal and regulatory changes in 2025 (Pexapark, RTE).
- Hours of negative prices jumped from 147 in 2023 to 513 in 2025. The growth of photovoltaic power contributes to this increase, along with other determinants of the electricity system (Montel News).
- Legislative changes in 2025 established a general obligation for production facilities larger than 10 MW to participate in the balancing mechanism starting January 1, 2026. The relevant implementation procedures fall under market rules proposed by RTE and approved by the CRE, while RTE retains responsibility for system balance.
- The institutional wager is risky: insufficient absorption of peaks can degrade revenues and increase support needs for certain producers, particularly photovoltaic operators, and slow the acceleration of deployment.
- The question for 2030-2035 is whether this market design can maintain the balance of a system whose supply becomes increasingly inelastic.
Installed capacity has outpaced the system
France’s energy transition depends on efficient use of renewable capacity already built, not on installation of new capacity.
For years, France’s energy transition challenge was installing enough renewable capacity. This problem is being resolved, at least partly. Installed photovoltaic capacity doubled in three years, rising from 16 GW in 2022 to 30 GW in 2025. Wind followed a similar trajectory. Result: During certain episodes, total supply exceeds anticipated consumption needs and exchanges, even while France is exporting.
In 2025, the grid recorded 513 hours of negative prices, compared to 147 in 2023—a threefold increase in two years. During these hours, producers paid for their electricity to be accepted. This shift reflects a physical transition: the electricity system moved from a scarcity regime to one of occasional abundance, without management tools following suit.
The roughly 2.9 TWh of modulation result primarily from low consumption during hours of high solar production and increased low-carbon production, with regulatory changes potentially affecting how producers respond. Curtailment or modulation means reducing, even stopping, production; it can be decided for system balance, network constraints, or in response to a negative price signal. It is the electrical equivalent of throwing out a harvest for lack of refrigerated trucks. Potential electricity is not generated, installed capacity is paid for but unused, and curtailment reduces potential renewable output, but its effect on emissions depends on the marginal power plant being replaced, exports, and modulation of other sources. At a scale of 2.9 TWh, this represents the annual consumption of roughly 900,000 French households.
Negative prices reveal a structural incompatibility
Understanding why prices turn negative requires returning to basics. In an electricity market, the price reflects the balance between supply and demand at each moment. When renewables produce massively—midday sun in May, sustained wind on an October night—supply exceeds demand. The price falls. If the surplus persists, the price goes negative: producers with high variable costs (especially gas plants) have an interest in shutting down rather than producing, and flexible consumers (pumped storage stations, hydrogen electrolyzers, large industries) theoretically receive a signal to consume more.
The French problem has two dimensions. Flexible capacity capable of responding to price signals remains insufficient: pumped storage stations (STEP), the main existing bulk storage tool, have limited reservoir capacity, and green hydrogen and large-scale batteries remain in embryonic deployment. Facilities under purchase obligation were historically not incentivized to modulate according to market prices; those under feed-in premium already had incentives to shut down at negative prices.
This architecture worked as long as renewables represented a modest share of the mix. It shows its limits at 30 GW of solar. European regulation on carbon auditing faces similar logic: a rule designed for an older balance creates unforeseen friction when physical parameters change faster than institutional frameworks.
The balancing market reform: a wager on incentives
This is why 2025’s changes make full sense. Facilitating participation of supported facilities in the balancing mechanism—the system RTE uses to balance the grid in real time—represents both a philosophical and technical change.
Until then, grid balance rested essentially on controllable assets: nuclear plants that modulated output, gas plants, run-of-river hydropower. RTE bought so-called “reserve” services on this market: the capacity to ramp up or down production rapidly. Not all renewables were subject to participation obligation, partly because their intermittency made them unreliable for this role, partly because volumes were still too small to justify the constraint.
These changes invert the old logic. Producers participating in the balancing market can offer adjustments up or down according to applicable rules and remuneration terms of the mechanism. The market provides more signals and adjustment offers, while RTE remains the coordination authority.
Agnès Bénassy-Quéré, in her work on central bankers facing the energy transition, emphasizes that when a regulatory actor sees its physical constraints transform—like a central bank confronted with climate shocks—the legitimacy of expanding its mission becomes central: who decides, through what procedure, with what accountability. RTE, a grid manager mandated by the state, mobilizes more market offers for balancing while retaining its power to order adjustments necessary for system security. Participation of supported facilities in the balancing mechanism stems from provisions in the 2025 finance law and implementing texts; corresponding market rules were proposed by RTE then approved by the CRE, but public debate on its institutional architecture has been minimal.
The market’s limits as an electrical coordination tool
The reform is consistent with a liberal reading of the problem: if producers bear the costs of negative prices and curtailments, they have an interest in investing in absorption solutions—colocated batteries, contracts with flexible industries, hydrogen sales—better than a central planner would. Jean Tirole, whose work on market design has precisely explored how to create effective incentives in sectors with externalities, would likely defend this logic: a good energy market sends the right signals to the right actors at the right time.
The balancing market has structural gaps. The first criterion retained is the power of facilities or offers, not the size of actors. The 10 MW threshold triggers an offer obligation for facilities exceeding it; it does not condition small producers’ access to the balancing mechanism. Some actors will continue to be managed through administrative curtailment mechanisms, creating a two-speed system.
The second blind spot concerns adaptation speed.
Needed investments—batteries, industrial demand response, interconnections—take years to deploy. The reform sends the right signal, but absorption capacity will not appear in 2026.
The third blind spot is most fundamental: in a system where renewable supply is inelastic, sun and wind do not respond to price signals, overproduction peaks can generate negative prices that limit responses from flexible actors. Market capacity to correct imbalances depends on availability of these adjustment capabilities. This is the scenario that RTE’s 2030 trajectories will need to test as renewables’ share in the mix continues rising.
Toward 2030: a system whose supply becomes inelastic
The 2025 reform is a first step. It does not resolve the fundamental question the French electricity mix will pose around 2030-2035. The European target of 42.5% renewables in the energy mix by 2030 differs from France’s target of 40% renewables in electricity production and at least 33% in gross final energy consumption. The central question is no longer whether France can build enough renewable capacity. It can.
The question is whether the system can function in balance when certain support or shutdown mechanisms do not yet allow correct calibration of responses to price signals.
An electricity system with inelastic supply resembles less a classical market than a real-time logistics problem. Prolonged episodes of very low or negative prices can affect the economic viability of producers and developer returns, with potential impacts on future investment. The transition might then stall precisely when it reaches cruising speed.
Three levers could avoid this scenario. The first is bulk storage. According to BloombergNEF, lithium-ion pack prices experienced significant declines during the 2010s, making the economic arbitrage between production and storage increasingly favorable. France lags behind Germany and the UK in this deployment. The second lever is industrial demand response: paying power-intensive large industries to shift consumption toward hours of surplus.
This mechanism exists but remains underdeveloped. The third lever is European interconnection. Building an internal energy market capable of absorbing one country’s surpluses by exporting them to neighbors mechanically reduces curtailments, but requires political coordination that current price tensions make difficult.
The signals to watch are clear: the volume of curtailment in 2026 will tell whether balancing market reform already produces behavioral effects. The negative price curve will tell whether absorption capacity follows installed capacity. And solar developers’ investment decisions in 2027 will tell whether the business model remains viable without revision of the public support framework.
Once an electricity system reaches a significant share of intermittent renewables, management logic must adapt. France sees this capacity share growing in its electricity mix. The institutional design that will determine who captures residual value—producers, storage operators, flexible industries, or the state through public guarantees—remains entirely open.
Producers facing new market risk
The 2025 reform alters the distribution of risks linked to variable production. RTE can request or order adjustments to ensure balance, while remuneration terms depend on support mechanisms and applicable adjustment rules. Participation in the balancing mechanism operates under specific remuneration and support rules that reflect how overproduction is managed.
For large developers—Engie, TotalEnergies Renewables, EDF Renouvelables—this constraint is manageable: they have teams, trading tools, and sometimes storage assets to handle it. For intermediate-sized independent developers, operational complexity is real. Participating in the balancing market requires expertise in real-time management, fine-grained weather forecasting systems, and capacity to counterparty on markets whose rules evolve rapidly. Some will work through aggregators, intermediaries that pool participation from several sites—but this added layer has a cost.
The question of sector concentration thus arises: if the reform structurally favors large integrated players, it could reduce developer diversity and, over time, affect the competitive dynamic that pushes costs down. The regulator will need to monitor this selection effect with the same attention it gives to physical grid balance.
A full-scale test of the market as a transition tool
France is conducting in 2025-2026 an experiment whose results will interest all of Europe. Most major European electricity systems face the same transition: moving from centralized control logic, inherited from 20th-century national utilities, to decentralized price coordination. Germany did it earlier, with mixed results—curtailments also progressed massively there before storage and demand response began to help. Spain is experimenting with parallel capacity mechanisms. The UK has developed more sophisticated balancing markets.
The French reform tests how quickly a market signal can modify actor behavior in a sector with very long investment cycles. Solar panels installed today will still operate in 2045. The balancing market’s effectiveness will depend on how quickly investments in absorption solutions—battery storage, industrial demand response, interconnections—materialize to maintain balance as renewable deployment accelerates.
Lucid optimism here requires a caveat: the reform is well-designed in its incentive logic, but the calendar is tight. The 2.9 TWh curtailed in 2025 is acceptable loss in a transition phase. If this figure doubles by 2027, the question of whether the market mechanism alone suffices will impose itself, and more direct public intervention—funding grid batteries, strengthened industrial demand response obligations, revised connection fees—will become hard to avoid.
Whether the market does here what the planner no longer knows how to do, or whether the planner must return to supplement what the market does not yet know how to do: that is the question data from 2026 will begin to answer.
Sources
- Pexapark, “PRMC: France Mandates Renewables Participation in Balancing Mechanism from 2026”: https://pexapark.com/blog/prmc-france-mandates-renewables-participation-in-balancing-mechanism-from-2026/
- Agnès Bénassy-Quéré, “Central Bankers Facing the Energy Transition”, Touteconomie.org: https://www.touteconomie.org/conferences/benassy-quere
- RTE, Trajectories and Installed Capacity Data 2025 (RTE annual report, no direct link guaranteed)
- Montel News, Data on hours of negative prices in France 2023-2025 (no direct link guaranteed)
- Commission de Régulation de l’Énergie (CRE), Regulatory documentation on the balancing market and PRMC reform 2025
- BloombergNEF, Data on cost declines for grid batteries since 2015
- Ember Energy, European renewable targets 2030
