This is an extract from a recent report “Energy market “Wild West”: European capacity mechanism 2026 state of play” published by Beyond Fossil Fuels.
Capacity markets in operation in Europe
Poland: Battery storage squeezed out of auctions by de-rating factor changes
The Polish capacity market has historically sat as an outlier among the European capacity markets for its higher support for batteries and coal. However, in recent years the Polish government has taken deliberate steps to boost support for gas plants in its capacity market auctions through changes to ‘de-rating factors’ – and the main beneficiaries from the scheme will be gas-fired sources from 2029. This appears to contradict EU State Aid rules, which require technology neutrality and the protection of competitiveness. Between 2025–2030, the contracted capacity for gas will more than triple from 3.8 GW to 11.6 GW. Most of these are Combined Cycle Gas Units units, which are most economically efficient when they operate for extended periods of time. This makes it likely that they will be used for more than covering peak demand, meaning prolonged gas burning would be subsidised through public funds, directly undermining the creation of a renewables-dominated energy system. A comprehensive review of the Polish capacity market published by Forum Energii in February 2026 had damning conclusions: that the mechanism is not transparent, has no clear strategic goal, favours gas units, creates risk of capacity oversizing and does not support system flexibility. Since its state aid approval for the capacity market will soon expire, Poland will be announcing a new proposed scheme shortly. The Commission must ensure that current concerns are addressed in the next version.
In Poland’s long-term auction held in December 2024, battery energy storage systems (BESS) far outperformed gas plants, due to the uneconomic nature of these projects. A number of major gas plants failed to receive long-term contracts. Poland responded by running another auction in July 2025, with the ‘de-rating factors’ designed to favour gas. Seven new gas plants units won 17-year capacity contracts for over 2.7 GW – including projects that had lost out in the auctions two years in a row. No storage projects were able to win. The auction ended in the first round with a record closing price of PLN 534.09/kW/year – over double the closing price for the December 2024 main auction. The main auction for 2030, held in December 2025, saw a continuation of this theme. A sharp cut in the de-rating factor for BESS to just 13% – down from 60% in 2024 and 95% in 2023 – resulted in a big drop in support for BESS, with just 685MW of auction wins. Gas projects, meanwhile, won around 2,400MW of contracts. In addition, the decision-making process which concluded the necessity of a supplementary auction was not transparent. The Transmission System Operator (TSO), PSE, did not publish the models and assumptions used to underpin the analysis. The analysis that has been published by PSE – which concluded that 5.2 GW of new gas was needed – was critiqued by both Poland’s energy regulator and Office of Competition and Consumer Protection. Supporting expensive gas over cheap BESS will have knock-on impacts on energy bills. According to the Energii Forum, high contract prices and indexation mean that the unit cost of gas capacity will increase from PLN 281.0/kW in 2025, to PLN 778.6/kW in 2045. By comparison, the contracted storage units will cost almost half as much in 2045.
Great Britain: The need for a long-term gas exit plan
With its ambitious 2030 clean energy plan, Great Britain is well positioned to act as a leader in replacing fossil gas with renewables and clean alternative forms of flexibility. However, uncertainty currently hangs over the future of the country’s significant gas fleet. In 2025, the government proposed changes to Great Britain’s capacity market which would have seen the introduction of a higher, separate price principally for new build gas plants. This proposal evoked concerns: that without due guardrails in place, there was a risk it could undermine the market for fossil-free flexibility, while adding billions of pounds to energy bills. It could have also presented a legal risk for the government, should clean energy actors have made appeals over a lack of technology neutrality. In February 2026, the government published a decision that it would not go ahead with this change, after the department “carefully considered the [consultation] responses and evidence submitted by stakeholders”. This suggests a policy intent of focusing on the refurbishment of existing gas generators, rather than building new ones. The decision, while welcome, leaves a question mark over the future of Great Britain’s gas fleet.
Clarity is required over whether gas plants will, over time, be removed from the capacity market and placed in an out-of-the-market mechanism. A gas plant exit strategy is needed to set out the short and long-term measures to ensure a smooth transition towards a renewables-based future. This requirement is echoed in the National Energy System Operator’s (NESO) assessment of Resource Adequacy in the 2030s, which concluded: “A longer-term whole energy system strategy is needed to support the future role of unabated gas in meeting consumer demand when needed. Great Britain’s 2026, long-term (T-4) auction saw gas continuing to form the backbone, but without the provision of long-term 15 year contracts for new-build gas plants through an auction – for the first time since 2016. The clearing price of £27.1/kW was less than half of the previous years’. With the lower target capacity, this will lead to a spending of £1.1bn in the first year of delivery compared to £2.6bn for last year’s auction. Successful new-build capacities were mostly new-build batteries (1.18 GW of contracts in the T4 auction), thanks to the drop in battery capital costs over the past year. Demand side response also performed well – securing 2.6 GW of contracts, a 45% year-on-year increase for the past couple of auctions.
Ireland: Data centres and fossil gas risk adding billions to energy bills
The Irish capacity market, implemented in 2018, is currently operating under State Aid approval until May 2028 – and thus approaching its renewal. Without necessary interventions, there is a risk that it could add billions to household energy bills to support data centre electricity consumption; which would run in contradiction to EU State Aid rules. Ireland’s capacity auction prices are by far the most expensive in Europe. This could be exacerbated further due to spiralling energy demand from data centres. Data centres are already using over 20% of Ireland’s electricity. This is forecast to grow up to 30% by 2030. As part of the EU regulations setting out the proportionality of the State Aid measures and Article 22 of Electricity Regulation, electricity consumers creating the need for the measure should contribute to its costs. This suggests that it would be unwarranted for households to pick up the tab for the energy capacity ’need’ created by data centres. The recent update to the EU state aid framework sets out a model for capacity markets which proposes: “At least 90% of the capacity mechanism costs must be allocated to consumers based on their consumption during at least 1% and at most 5% of the highest price hours (or market time units) each year (or each delivery window).”
There is a very strong case to suggest that the energy demand contribution of data centres would fit within this category. They fundamentally contribute to the scale and nature of peak demand. The absence of large hourly fluctuations does not negate the constant baseload of data centre demand – in fact, constantly high baseload leads to excessive demand at times when society also requires energy at peak times. Data centres always contribute to the level of peak demand precisely because of their inflexible demand profile, and in the south of Ireland their share of demand at peak times is significantly higher than elsewhere. Data centres make the peak significantly higher than it would otherwise be (with obvious impacts for household bills during those times). Capacity market costs that result from the energy needs of data centres must not be levied on household and business bills; but rather borne by data centre owners. The Irish energy regulator, CRU, should conduct independent analysis to assess the current and future burden that can be attributed to data centre growth; and ensure this proportion is paid for by data centres. This suggests that it would be unwarranted for households to pick up the tab for the energy capacity “need” created by data centres.
Italy: Derating factor changes risk cementing the gas-plant bias
Italy’s capacity market has to date provided the highest share of capacity market auction contracts to fossil gas plants – 84% of the €18 billion that will be added to energy bills since the initiation of the capacity market in 2018. Changes proposed by the TSO, Terna, could risk further locking in this dynamic. In spring 2026, Terna ran a consultation on changing the derating factor for BESS. The logic behind the consultation appears to be that Terna is concerned that BESS is outcompeting gas plants in the auctions – and is seeking to influence the outcomes to ensure that expensive gas plants can compete against these more economic clean energy solutions. Similarly to concerns raised for Poland, changes that ensure that one technology can secure contracts in the auction, would run counter to state aid rules and the promotion of technology-neutral, competitive and transparent processes. Furthermore, certain assumptions made in the policy proposal regarding future storage penetration risk creating a structural bias in the accreditation of storage resources. This approach would avoid self-fulfilling assumptions that could discourage storage participation in the capacity market.
These changes are particularly concerning given the urgent imperative for Italy to reduce its dependence on fossil gas in order to reduce energy bills. A focus on expanding batteries would have excellent results for energy security, and helping Italy make the most of its abundant solar capacity. In 2025, Italy’s batteries contributed to meeting demand during peak gas-use hours, a trend that could rapidly accelerate as that pipeline is built. In September 2025, large-scale battery systems discharged an average of 1.1 GW during the early evening hours. With the delivery of the development pipeline, battery capacity could quickly grow by nearly six times, meet higher shares of demand during peak gas-use hours and reduce the country’s high reliance on expensive gas. Italy’s great battery potential was demonstrated in a recent auction. Italy held the first auction under its new long-term capacity mechanism for electrochemical storage systems, contracting up to 10 GWh of new storage capacity. The average clearing price was considered very competitive – nearly 65% below the reserve premium of €37,000/MWh-year. Enel Produzione was awarded over half of this total (5.2 GWh).
Belgium: Renewables and clean flexibility needed for energy security
In October 2025, Belgian transmission system operator Elia published the results of the three CRM auctions. Contracts to gas plants once again dominated the auctions, representing around 83% of the projects selected, in terms of de-rated capacity. However, clean energy experts also welcomed that nearly all new capacity contracted in the 2025 auctions came from large-scale batteries. Gas-power plants selected by the CRM auction have committed to being carbon neutral by 2050, which is 15 years after the International Energy Agency suggests that Europe needs to decarbonise its power system in order to be compliant with climate goals. The capacity market resulted in the construction of two new gas power plants – Luminus in Seraing and Engie’s Awirs, supported by contracts worth around €450-900M in subsidies per gas power plant over 15 years.
These plants were built because a series of governments in Belgium failed to properly plan for the nuclear phase-out in 2025, by not installing adequate renewable production capacity in time. The plants deepen Belgium’s reliance on volatile international gas markets. Every megawatt generated depends entirely on imported fuel, increasing the country’s exposure to the volatility of global gas markets. Instead Belgium should focus on increasing investments in renewable energy and clean flexibility solutions to insulate the country from volatile fossil fuels markets and deliver affordable, climate-friendly energy. The current Belgian Prime Minister, Bart De Wever, has publicly criticized the energy policies of the previous Vivaldi coalition government, specifically condemning their decision to subsidise new gas plants, and pointing to how this has left the country more exposed to gas imports. While he blames the nuclear exit for this position; the real answer for Belgium lies in more renewables.
France: New auctions should be designed to boost demand flexibility
Traditionally, the French capacity market has been an outlier in its high support for nuclear contracts – representing 50% of the total value (€10 billion). The capacity market has recently undergone a major transformation, away from a decentralised market with many auctions each year – towards a centralised mechanism where RTE is the sole buyer, organising annual auctions to contract the necessary capacity. The reform has the dual objectives of supporting new decarbonised capacities, such as demand response and battery storage – as well as thermal power plants. The costs will then be passed on to suppliers via a tax calculated on their customers’ consumption during periods of tension. The French TSO, RTE recently noted that thermal plants are being used less and less hours; although some new capacity could be needed in the next decade. The next step will be considering how demand-side flexibility and storage are now integrated into the power system. This works both through the capacity mechanism, which enables more visibility on future revenues over 4-5 years, as well as a new mechanism which specifically incentivizes load shifting (both upwards and downwards).
Capacity markets currently under consideration and development
Germany: Action needed to prevent a dangerous, gas-biased precedent
In Germany, consecutive governments have been working for years to bring forward a gas plant plan to introduce tenders for a new fleet of gas plants. The exact GW volume of these tenders has changed over the years – from 12.5 GW, to 10 GW, to 20 GW, and now to build 12 GW of new dispatchable capacity. The cabinet-approved government proposal for the ‘ad hoc’ CRM, the draft StromVKG, will contain three tender types. The proposal will now go through parliament, with the government aiming for adoption before the summer break.
● Ad hoc long-term capacity tenders: Two rounds of 4.5 GW each on 8 Sep 2026 and 22 Dec 2026; approximately 10 GW nominal; 15-year commitments only; generation facilities only; BESS effectively excluded by the 10-hour criterion and Made in Europe requirements; demand side response (DSR) officially excluded.
● Ad hoc capacity tender: One round of 2 GW on 18 May 2027; 15-year commitments only; generation facilities only; both power plants and BESS admissible; no requirements that effectively exclude BESS; DSR officially excluded.
● General capacity auctions: Two rounds on 1 Dec 2027 and 1 Oct 2029; open to generation facilities and controllable loads; i.e. power plants, BESS and DSR all admissible.
Despite the insistence that “the agreement is based on a technology-neutral approach”, the government has steered it to favour gas. The key factor excluding storage from these auctions is a criterion saying that all long-duration capacity must be able to deliver for 10 hours straight, while ‘energy-limited technologies’ (effectively BESS/storage) must also be able to meet this requirement again within one hour. Demand side response will be explicitly excluded from the only auctions with a pre-determined capacity volume. The legislation (StromVKG) explicitly excludes DSR from the ‘long-term’ and ‘generation’ auctions, the only tenders with a guaranteed capacity volume (of 9 GW), and the only auctions guaranteed to take place. The law does not require any credible pathway towards climate neutrality and does not have a mechanism to incentivise a conversion or to sanction the lack thereof, which exacerbates the risk of fossil gas lock-in. It also completely omits the cost recovery mechanism, which dictates how the policy costs will be recovered from customers. The legal charity, ClientEarth, points out further issues with the proposal. EU law requires schemes to be grounded in an assessment that shows additional capacities are in fact needed. However, most of the capacities to be tendered are not tied to any assessment at all, and the rest are tied to a German assessment that diverges significantly from the European one on key issues like the potential of batteries and demand side response.
A report from the German Federal Network Agency (BNetzA) was also critiqued for potentially overestimating the amount of gas plant need; while underestimating the potential role of clean flexibility. The German Solar Association, BSW-Solar, criticised the report for inadequately modeling the potential of large-scale battery storage systems, arguing that it failed to reflect actual developments and thus ignored a key aspect of the energy transition. Indeed, the source of the original 20 GW number appears to be influenced via the fossil lobby. RWE and Uniper – who are among the largest recipients of capacity market payments in Europe – have been actively lobbying for the German government to set up a capacity market. In another sign of the influence of energy companies in policy discussion; the energy minister recently asked the energy company ENBW for arguments to push batteries out of the tenders; and they suggested the 10 hour rule. The plans will likely face legal action, with a number of clean industry groups already signalling their opposition to the proposed approach. A report recently commissioned by the German Chamber of Industry and Commerce, Federal Association of Energy Consumers, 1Komma5°, Octopus Energy Germany and many others warns of the “significant economic, regulatory, and environmental risks associated with capacity support mechanisms”. With many existing capacity markets coming up for their 10 year renewal with the European Commission – including in Poland, Italy and Ireland – if Germany is allowed to go ahead with its ‘ad hoc’ capacity market auctions which clearly benefit gas plants; this will set an extremely dangerous precedent across the EU.
Spain: Decarbonisation measures must be baked into new capacity market
Spain is a leader in renewables – and has incredible potential to continue building out solar and wind capacity. As seen with the recent spike in energy prices, this has helped ensure energy security, and more stable energy bills. At the beginning of June 2026, the European Commission approved Spain’s €9bn capacity mechanism. The devil will be in the detail of the final scheme and auction design. The discussion on energy security in Spain has intensified over the last year, following the black out and now with the energy crisis. Spain consulted on a proposed capacity market in 2025. The proposal contained some welcome positions – such as that new investments could only be renewables or storage – but also would allow existing gas plants to access contracts. However, it is not clear that there is a strong need for Spain to introduce a capacity mechanism, and in doing so, the country could risk keeping unnecessary fossil fuel plants in the system for longer, thus harming the efficiency of the wholesale energy market and burdening consumers with higher electricity bills. The current proposal limits emissions from eligible technologies to 550 gCO2/kWh. To ensure the capacity market is aligned with Spain’s climate strategy, Greenpeace España has set out policy conditions that must be put in place. These include a binding commitment to gradually reduce the annual CO2 of the mechanism, reaching zero by 2030 at the latest – backed with a legal obligation to cease providing contracts for fossil fuel assets from that point onward. This will help prevent the mechanism from becoming manipulated to support gas plants, as has been done in other countries.
Greece: An opaque approach lacking an evidence-based justification
Greece is currently setting up a capacity market. From the start, the process has been intransparent, and does not appear to have followed the Commission’s requirements. There has not been an adequacy assessment published to demonstrate the need for a capacity market. Nor has modelling been published, nor a public consultation. This means there is a risk of excessive financial support for unnecessary gas units. Indeed, it is not clear that Greece has a capacity gap at all. The Green Tank’s analysis, based on ENTSO-E data, indicated that the maximum thermal capacity needed for domestic needs by Greece at any given time is currently well below the total installed gas capacity (6 GW) – thus challenging that the additional 5.5 GW of gas plants currently planned or under development is needed to meet a domestic shortfall. Thus, it appears that a number of requirements set by the European Commission regarding the development of capacity mechanisms are being disregarded. The option of a strategic reserve should be considered as a first option, if adequacy issues are identified in the National Resource Adequacy Assessment.
It is worth noting that ENTSOe’s EU Resource Adequacy Assessment identified minimal adequacy gaps for Greece, which could may be fully covered through a Strategic Reserve mechanism It is not clear that the government is looking to establish a capacity market to support energy security, especially considering the scheduled installation of a significant capacity of batteries. It seems that the government is looking to support the investment decisions of gas producers to construct new gas plants at a time when domestic demand for gas-fired electricity generation is rapidly diminishing due to the increasing output of renewables. When designing a capacity mechanism, priority should be given to ensuring the country’s energy security while minimising costs for consumers. If the government is seeking to set up a mechanism to support its ambition to be an energy exporter, it appears that an apparent wealth transfer is set to take place between consumers – who will pay for the capacity mechanism through levies on their bills – and the energy companies who are benefiting from energy exports, and government who benefits from tax revenues.
Czechia: An intransparent approach with a high risk of gas lock-in
Not much is publicly known about the Czech government’s plans to introduce a capacity market, aside from the Czech market reform plan, and the response of the European Commission. The mechanism is being prepared according to the Clean Industrial Deal State Aid Framework (CISAF), providing a robust basis. However, CISAF cannot address structural issues in the Czech power system: inadequate build out of renewables, especially wind power. This leads to a systemic lack of clean energy during the winter period that current technologies of clean flexibility cannot bridge. Thus, most importantly, Czechia should start with a significant buildout of wind power in line with its National Energy and Climate Plan. In the meantime, Czechia should do its best to support clean flexibility and make use of interconnection in order to minimise the risk of gas lock-in.
Access the full report here