France

Overview

France is the largest low-carbon power producer in Europe and its biggest net exporter of electricity. Both facts come off one asset base. The nuclear fleet is big enough that for most hours of the year it does not set the price at all. It simply removes the need for anything expensive to.

Nuclear supplied 68.1% of French generation in 2025. Low-carbon sources together supplied 95.2% of it. Fossil-fired output fell to its lowest since the early 1950s. The trading version is short. An enormous block of near-zero marginal cost capacity prices French power, and the interesting hours are the ones when that block is unavailable and gas has to cover.

The market is fully liberalised and coupled to the rest of north-west Europe. Wholesale power trades on EPEX SPOT. RTE runs the transmission system and the regulator is the Commission de régulation de l'énergie (CRE). Gas moves through the networks of GRTgaz and Teréga, trading at one national virtual point, the PEG, inside the Trading Region France zone created on 1 November 2018.

The commercial architecture around the fleet has just changed. EDF went back into full state ownership on 8 June 2023, and the regulated wholesale access scheme known as ARENH, which forced EDF to sell around 100 TWh a year to rivals at €42/MWh, expired on 31 December 2025. What replaced it is not a volume obligation. It is a revenue-sharing arrangement, and that changes who carries French price risk.

Market structure

One national bidding zone and one dominant generator. The market design exists mainly to share the output of a state-owned nuclear fleet with everyone else who wants to sell electricity.

Who does what

One zone, one incumbent

Italy and the Nordics split into zones. Mainland France does not: it is a single bidding zone with one day-ahead price for the whole country. Internal congestion is handled by RTE through redispatch, never shown as a locational price. For a position-taker that removes basis risk inside France and concentrates all of it at the borders.

Concentration is the defining feature. EDF owns the reactors, all 57 operable units, roughly 63 GW of net capacity, plus much of the large hydro. Competing suppliers own nothing comparable, so the state has always had to engineer them a route to nuclear output at something other than the market price. ARENH was that route from 2011 to 2025.

Renationalisation and what it changed

The state completed its buy-out of EDF's minority shareholders on 8 June 2023, taking its stake from 84% to 100%. The balance sheet drove it. Between the corrosion crisis and ARENH obligations, EDF was carrying a repair programme and a new-build programme it could not fund from market equity. What that means commercially is that outage scheduling, lifetime extension and the new EPR2 units are now decided inside a single state perimeter, with no public shareholders to negotiate with.

Infrastructure — power and gas

A meshed transmission grid with the strongest interconnection position in Europe. The gas system has turned into a west-facing LNG gateway rather than the end of a pipeline.

Power

Gas and LNG

Domestic production is negligible. Gas arrives by pipeline from Norway, the Netherlands, Belgium and Germany, and as LNG into four terminals: Dunkirk in the north, majority-owned by Fluxys; Montoir-de-Bretagne on the Atlantic; and Fos Tonkin and Fos Cavaou on the Mediterranean, the last three inside the Elengy group (IEA). Underground storage totals around 12.2 bcm, roughly 29% of annual consumption, run by Storengy and Teréga.

Transmission is split between GRTgaz, which runs the great majority of the network, including the low-calorific-value system in the north, and Teréga in the south-west. Since the Trading Region France zone was created on 1 November 2018, both networks balance into a single virtual point. One French gas price, rather than a northern one and a southern one.

Demand and supply

Flat demand and a generation mix that is 95% low-carbon. On the supply side there is really only one variable: how many reactors are running.

Demand

French consumption was 451 TWh in 2025, up 0.4% on the year. Flat, in other words, as it has been for a decade. The shape is another matter. Peak demand reached 88 GW, the highest since 2021, because France heats with electricity to an unusual degree. One degree colder in winter adds roughly 2 GW of load. Thermosensitivity is the demand variable that matters here, not economic growth.

Supply

Generation totalled 547.5 TWh in 2025, of which nuclear supplied 373.0 TWh. That is 11.3 TWh up on 2024 and back to pre-crisis levels. Solar added 8.1 TWh as 5.9 GW of new panels came online. Hydro fell 12.9 TWh on normal rainfall after an exceptional 2024, and fossil generation dropped to 18.7 TWh, the lowest since the early 1950s.

Price setting mechanism

A marginal-cost day-ahead auction in which the marginal unit is frequently not French at all. From 2026 there is also a nuclear revenue arrangement that redistributes the upside rather than the volume.

The day-ahead auction

Generators and suppliers bid into EPEX SPOT for delivery the following day. Offers stack cheapest first and the last unit needed sets one clearing price for the whole zone. Coupling with the rest of north-west Europe means the marginal unit can sit in Belgium or Germany, and when interconnectors are unconstrained prices converge across the coupled region.

Nuclear, hydro and renewables cover most of the load stack at near-zero marginal cost, so the French price spends much of the year detached from fuel. Average spot was €61/MWh in 2025. The tail is what pays. There were 513 hours of negative prices in 2025, up from 352 in 2024, as solar swamps midday demand. At the other end of the day the evening peak still clears on gas.

The post-ARENH arrangement

ARENH obliged EDF to sell about 100 TWh a year to competing suppliers at €42/MWh. It expired on 31 December 2025. The successor, agreed between the state and EDF, is not a volume right at all. It is a revenue-sharing contract over the whole nuclear output, built around a reference level of €70/MWh over fifteen years. Above roughly €78–80/MWh of realised wholesale price, 50% of EDF's excess revenue is clawed back and passed to consumers. Above €110/MWh, it is 90%. The thresholds get reviewed every three years.

Capacity payments

Energy revenue is not the whole of it. France has run a capacity mechanism since 2017, and the European Commission approved a reformed version, budgeted at €20bn over ten years from November 2026. Capacity revenue is what keeps peaking plant and demand response available for the handful of cold, still evenings that set the annual peak.

Regulatory regime

CRE regulates the networks and polices the market. The state owns the generator. Brussels sets the outer limits on both, and French energy policy happens inside that triangle.

CRE

Created on 24 March 2000, CRE regulates both electricity and gas, with the conventional European set of powers. It sets transmission and distribution tariffs, approves storage capacity auctions, arbitrates network access disputes through its CoRDiS committee and publishes the surveillance reports on how the wholesale market has behaved. It does not set the wholesale price. Its tariff decisions still determine a material slice of what an end user pays, and its access rulings decide who can reach the PEG and the LNG terminals.

State aid is the binding constraint

EDF is wholly state-owned and the nuclear arrangement redistributes its revenue, so every significant French market reform now runs through Brussels. The post-ARENH framework was explicitly designed, in the economy minister's words, to comply with European rules. The capacity mechanism reform needed a formal state aid decision before it could start. French reform timelines are therefore Commission timelines, and slippage is a live risk to any assumption about when a mechanism goes live.

Nuclear oversight after 2022

The stress corrosion episode reshaped how the regulator and EDF deal with each other. Corrosion near welds on safety injection pipework turned up at Civaux 1 in December 2021. The twelve most vulnerable reactors were inspected and repairs finished by January 2024 (World Nuclear Association). Safety regulation and technical support merged into one authority, ASNR, in 2025. The institutional shape hardly matters for the trading lesson. EDF's published outage schedules are forecasts open to regulatory revision rather than commitments, and French forward spreads carry that uncertainty.

Key links

Primary sources for this market. Figures on this page are drawn from these and from published market data.