The Estonian Competition Authority, Konkurentsiamet, has fined Futugrid Technologies OÜ €16,000 for manipulating the balancing energy market by placing a non-genuine bid (i.e. a bid that was not intended to be executed), which sent misleading signals to the market. 

This is the Authority’s first decision on market manipulation under REMIT (Article 5) and remains subject to appeal.

The REMIT Regulation prohibits market manipulation, including sending false or misleading signals, to protect the integrity and transparency of the EU’s wholesale energy markets.

What happened?

On 31 March 2025, Futugrid offered its capacity on the Baltic balancing capacity market (where providers are paid to remain available for the subsequent balancing energy market), and its offer was accepted. This obliged it to submit a corresponding energy bid for delivery on 1 April 2025.

To fulfil this obligation, Futugrid submitted a bid for manual Frequency Restoration Reserve (mFRR), a reserve that grid operators activate to keep the system in balance. The bid was for 1 MW of downward balancing energy (used when there is a surplus of electricity on the grid), covering the market time unit from 12:00 to 12:15 on 1 April 2025. Futugrid set a very low price (-9,999 €/MWh), with the aim of avoiding activation. The bid was nonetheless activated and directly set the marginal balancing price for that period.

The Estonian Competition Authority found that the bid was not genuine, as Futugrid priced it to avoid activation while still meeting its obligation. The Authority concluded that the bid sent a misleading signal to the market and directly influenced price formation, constituting market manipulation in breach of REMIT.

For more information, access the Estonian Competition Authority’s press release (in Estonian).

See the latest table of REMIT breach sanction decisions adopted by national regulatory authorities.

Check the ACER REMIT Guidance (6.1^st edition) for more information on trading practices that could constitute market manipulation under REMIT.

Interested in further information on enforcement decisions under REMIT? Check out ACER’s REMIT Quarterly reports.

As Europe moves towards greater electrification, retail energy markets will increasingly shape the costs and opportunities for consumers. How electricity is priced and how consumers can respond to changing prices will influence whether households can benefit financially from this transition.

The 2026 Monitoring Report on retail energy markets examines electricity bills, affordability and what the shift to electrification means for consumers. 

What trends did the monitoring find? 

• Household retail prices rose sharply after the 2022 energy crisis and have remained elevated. In 2025, EU households spent an average of €840 on electricity and €1,170 on gas.

• Household electricity expenditure ranges from 1.2% to 3.9% of national median income across the EU, reflecting differences in prices, consumption and household income.

• High electricity-to-gas price ratios can weaken the incentive to electrify. Electricity remains relatively expensive compared to gas, discouraging households from switching to electric technologies. Network charges, taxes and upfront costs often widen this price gap further.

• Most consumers are not exposed to the benefits of flexibility. 7% of EU households are on dynamic price contracts, while over 80% in nine countries are on single fixed-term, fixed-price electricity contracts. This limits their exposure to changing price signals and potential savings. Smart meter rollout is also uneven across Member States: 66% of monitored customers have a smart meter, but coverage remains below 20% in several countries.

• Flexible consumption could reduce bills. ACER analysis shows that switching to dynamic pricing and shifting consumption to lower-price periods could have saved households an average of 20% (around €120) on their electricity bills in 2025. 

• Better contract monitoring is needed to assess consumer outcomes. More complete and comparable contract data are key to assessing market impacts on European consumers.

Looking ahead

Electrification will increase electricity consumption and change when and how consumers use energy, creating new challenges for retail energy markets.

Three areas will be particularly relevant:

• Making electrification financially attractive. Retail electricity prices relative to fossil-fuel prices, technology efficiency and upfront investment costs will shape incentives to electrify.  

• Ensuring network investment delivers value for consumers. Efficient planning and use of existing grids will help contain costs and protect electricity affordability as network investment increases.

• Enhancing monitoring of energy retail contracts to understand consumer choice. Better data on the contracts consumers actually choose will help assess whether appropriate price signals and choices are available as consumption patterns change.

On 18 December 2025, ACER received two proposals from all electricity transmission system operators (TSOs) to amend the implementation frameworks for PICASSO and MARI, the EU platforms for exchanging balancing energy from frequency restoration reserves.

With its Decisions 12/2026 and 13/2026, ACER approved both proposals.

What are the implementation frameworks for balancing platforms?

Established under the Electricity Balancing (EB) Regulation, the implementation frameworks harmonise how balancing service providers (BSPs) participate in electricity balancing markets across EU Member States.

These markets allow TSOs to manage unexpected differences between electricity supply and demand. PICASSO coordinates cross-border exchanges of automatically activated balancing energy (e.g. in case of sudden need), while MARI coordinates manually activated balancing energy. Together, they enable TSOs to access balancing resources across borders and maintain system stability.

What did the TSOs propose?

The TSOs proposed to further harmonise the BSP prequalification process, which ensures that power generation or demand units meet the technical and operational requirements to participate in the market and provide balancing services. 

The proposals also introduce a common process for amending the implementation frameworks of PICASSO and MARI to further harmonise the terms and conditions for BSPs.

What did ACER decide? 

ACER approved the proposals, while introducing some amendments:

• A structured harmonisation process. Every two years, TSOs will run stakeholder surveys to identify areas where the terms and conditions for BSPs still need to be aligned across countries. TSOs will then develop a common proposal for further harmonisation and publicly consult on it.
• More harmonised prequalification requirements. ACER introduced additional requirements for switching, re-prequalification, termination of prequalification and data exchange. Given the limited experience with harmonised prequalification, some requirements will continue to be set at national level, with further harmonisation expected as TSOs gain more experience.
• More prequalification options. ACER introduced three prequalification options: activation testing, ex-post verification and a fast-track process. Compared with activation testing, the other two offer faster and easier market access, as balancing services are monitored during operation instead of tested upfront. TSOs can choose any or all three options, subject to approval by their national regulatory authority.
• Easier access for smaller market participants. ACER simplified the prequalification process for smaller participants to help ensure a level playing field. As existing processes were designed around large conventional generators, ACER adapted them to make it easier for all participants that can provide secure and reliable balancing services to enter the market and improve liquidity.

What are the next steps? 

TSOs have six months to submit a proposal to their national regulatory authority to align national terms and conditions with the new requirements. Once approved, TSOs will have 24 months to implement the harmonised prequalification process.

ACER published its Opinion on Portugal’s National Resource Adequacy Assessment (NRAA).

The NRAA is part of the country’s electricity security of supply monitoring report, the RMSA-E 2025 (Relatório de Monitorização da Segurança de Abastecimento), and complements the European Resource Adequacy Assessment (ERAA) 2025.

What is a resource adequacy assessment?

The ERAA assesses whether the EU has enough electricity resources to meet demand and ensure security of supply. It is carried out annually by the European Network of Transmission System Operators for Electricity (ENTSO-E) and reviewed by ACER.

Member States can complement this European analysis with national assessments (NRAAs) that reflect local conditions. When a national assessment differs from the European one, ACER issues an opinion.

What did the Portuguese NRAA find?

Unlike the ERAA 2025, which found no adequacy concerns for Portugal, the national assessment identified adequacy risks in all target years from 2028 to 2035.

The NRAA projects that Portugal’s loss of load expectation (i.e. the number of hours per year when demand is expected to overcome supply) will exceed the country’s 1.46-hour reliability standard. This is expected to increase over the years:

• slightly in 2028;
• by about five times in 2030; and
• by nearly fifty times in 2035.

The projected increase assumes electricity demand growing much faster than the resources needed to meet it. Compared with the reference ERAA, the NRAA assumes:

• higher demand from new energy-intensive consumers, particularly data centres;
• slower deployment of renewables;
• lower availability of pumped-hydro storage, based on historical data;
• conservative assumptions on long-term battery deployment; and 
• the shift of the Tapada do Outeiro gas-fired power plant into an out-of-market reserve, taking offline about a quarter of Portugal’s thermal capacity, normally highly available during scarcity times.

Figure: Portugal’s projected installed electricity capacity, 2028-2035

The Portuguese NRAA assumes considerably slower growth in installed electricity capacity than the ERAA 2025, with a gap of around 15 GW by 2030 and 12 GW by 2035. This is largely due to assumptions of slower wind and solar deployment in the national assessment.

Source: ACER based on the NRAA and ERAA 2025.

What are ACER’s key findings? 

ACER finds that the projected resource adequacy risks are mainly driven by assumptions of strong demand growth, while new capacity, including demand-side response, is assumed to lag behind.

At the same time, the NRAA does not adequately assess how the market could respond to increasing electricity supply scarcity. Its economic viability analysis shows that existing gas-fired generation capacity would remain highly profitable, especially long-term, as tighter supply could push prices up. However, the NRAA does not examine whether these price signals could attract investments in new resources, including batteries and demand response, and offers only a limited projection of their potential contribution to security of supply.

The national assessment also overlooks cross-border factors, such as Spain’s recently approved capacity remuneration mechanism, that could affect how much electricity Portugal can import during scarcity periods.

As a result, the NRAA may overestimate Portugal’s adequacy gap by not fully accounting for resources that could realistically enter the market or be available cross‑border.

What does ACER recommend?

To strengthen Portugal’s assessment, ACER recommends:

• Applying the economic viability assessment in line with the ERAA methodology.
• Assessing the potential for new market-based investments, particularly batteries and demand response.
• Reflecting the contribution of currently ‘out-of-market' resources, such as the Tapada do Outeiro gas-fired power plant.
• Using more realistic demand response projections.

Overall, ACER considers that a robust adequacy assessment should capture new investments that could be delivered in response to market conditions, in addition to current resource development trends.

What are the next steps? 

ACER encourages the Portuguese authorities to consider its feedback to improve the assessment.

Today, ACER publishes the first open-access EU-wide dataset on cost of new entry values (EU CONE Dataset).

The dataset provides economic parameters for new electricity resources (including estimated capital and operational costs for different power generation technologies and demand-side flexibility) to support long-term system modelling.

To make the data easier to explore, ACER has also published an interactive dashboard.

Why does it matter?

Until now, only fragmented data was available at EU level. This made cross-country comparisons difficult and increased the risk that adequacy assessments and investment signals would rely on inconsistent cost assumptions. 

By providing more complete and consistent input data, the new dataset helps improve the accuracy and robustness of adequacy modelling. This supports:

• assessing future investment needs (e.g. whether new generation or flexibility resources are likely to be built and whether existing power plants are expected to remain economically viable);

• understanding how investment and retirement decisions shape the future resource mix in Member States, helping identify potential adequacy gaps; and

• estimating the optimal level of system reliability, by balancing the cost of new capacity against the risk and impact of unmet demand.

How was the dataset developed?

The EU CONE Dataset builds on a preliminary version developed by consultants. Following a public consultation (February 2026), ACER refined its data, integrating feedback from stakeholders (including system operators, generators, manufacturing and technology companies) and national regulators (see the evaluation of responses).

Respondents provided constructive feedback and proposed evidence-based refinements to several parameters, including:

• capital expenditure (CAPEX);

• fixed operating and maintenance (FOM) costs;

• weighted average cost of capital (WACC) for different technologies; and

• the categorisation of demand-side response.

Views on gas technologies were broadly aligned with the consultancy study, while input on batteries and demand-side response was more diverse.

What’s next? 

The EU CONE Dataset can be used to support power system modelling, including future editions of the European Resource Adequacy Assessment (ERAA), national adequacy assessments (NRAAs) and other related studies.

It may also help Member States calculate reference reliability standards and meet the criteria for fast-track approval of capacity mechanisms under the new State aid framework.

On 21 July 2026, ACER received a proposal from all nominated electricity market operators (NEMOs) to amend the methodology for the price coupling, continuous trading matching and intraday auction algorithms.

What is the methodology about?

Established under the Capacity Allocation and Congestion Management (CACM) Regulation, the methodology provides a common framework for the algorithms used to simultaneously match electricity market orders and allocate cross-zonal capacities in Europe’s day-ahead and intraday markets. It defines common requirements, timelines and implementation deadlines.

The current methodology was approved by ACER in July 2018 and amended in January 2020 and September 2024.

Why amend the methodology? 

NEMOs propose amendments to the methodology to enable more efficient cross-border electricity exchanges, deliver greater welfare and maintain the secure operation of the power system by:

• enabling the introduction of three intraday auctions using flow-based capacity calculation by updating the timings and delivery of intraday auction results;

• setting a concrete implementation deadline for flow-based allocation in intraday auctions; and

• amending the relevant deadline for publishing the single day-ahead coupling results.

What are the next steps? 

ACER expects to decide on the methodology by 21 January 2027. 

Interested stakeholders are invited to share their views on the topic by 31 August 2026 via ACER-ELE-2026-006@acer.europa.eu.

ACER’s new retail energy markets dashboard offers an interactive, country-by-country view of electricity and gas markets across the EU and Norway. It replaces ACER’s country sheets, bringing together comparable data to explore how retail markets are evolving and how consumers’ behaviour changes alongside the energy transition.

What trends did ACER monitoring find?

With over 270 million electricity and more than 90 million gas customers across the EU and Norway, retail energy markets play an important role in supporting Europe’s energy transition. At the same time, the latest data shows ongoing challenges and significant untapped potential for more active consumer participation.

• Energy bills remain above pre-crisis levels. Retail prices rose sharply after the 2021-2022 energy crisis and remained elevated, with gas prices still nearly 70% higher than before the crisis. On average, EU households spent around €840 on electricity and €1,170 on gas in 2025.
• Household electricity and gas consumption is rising modestly, highlighting the importance of enabling consumers to actively manage their energy use.
• Fixed contracts remain the most common contract type. Around 52% of household electricity customers are on single fixed-price, fixed-term contracts, while only 7% are on dynamic-price contracts, pointing to significant unexploited capacity for demand-side flexibility.
• Smart meter rollout progresses unevenly. 66% of household customers monitored across the EU and Norway have a smart meter. While deployment exceeds 80% in most EU Member States, it remains below 20% in several countries, limiting consumers’ ability to adjust their consumption in real time.

What are the next steps?

The retail energy markets dashboard will be updated annually as new data becomes available, allowing to monitor progress across all indicators.

On 17 July 2026, the national regulatory authorities of the Core capacity calculation region (Core NRAs) asked ACER for a three-month extension to decide on the proposal to amend the Core intraday capacity calculation methodology. The proposal was submitted by the transmission system operators of the Core region (Core TSOs).

The Core region is the EU’s largest electricity capacity calculation region, covering 13 Member States: Austria, Belgium, Croatia, Czech Republic, France, Germany, Hungary, Luxembourg, the Netherlands, Poland, Romania, Slovakia and Slovenia.

ACER intends to ensure a timely decision on the matter.

What is the Core intraday capacity calculation methodology? 

The methodology determines how much cross-zonal transmission capacity is available for intraday electricity trading in the Core region. 

First approved in 2019, the methodology would now be amended for the sixth time to reflect the continued development of capacity calculation and support EU electricity market integration through more efficient and secure allocation of cross-zonal capacity.

Update as of 30 September 2026: On 6 September 2026, the NRAs referred the matter to ACER, which intends to ensure a timely decision on the matter.

On 7 July 2026, the national regulatory authorities of the Continental Europe Synchronous Area asked ACER to decide on the minimum activation period that frequency containment reserves providers with limited energy reservoirs must ensure to remain available during the alert state.

The Continental Europe Synchronous Area includes Austria, Belgium, Bulgaria, Croatia, Czechia, Denmark, Estonia, France, Germany, Greece, Hungary, Italy, Latvia, Lithuania, Luxembourg, the Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia and Spain.

Why is the minimum activation period important?

EU’s electric power systems operate at the frequency of 50 Hz. Any imbalance between electricity supply and demand causes the frequency to deviate. If not corrected quickly, this can lead to blackouts.

Frequency containment reserves are the first line of automatic response to such deviations. They are activated within seconds to stabilise the frequency and are provided continuously by power-generating or consuming assets (like batteries, hydro plants, or demand response systems). 

Some of these providers, especially batteries or demand-side resources, have limited energy reservoirs and can only respond for a short duration. The System Operation Regulation therefore requires a minimum activation time to ensure these resources remain available during the alert state. 

What are the next steps? 

ACER intends to decide on the minimum activation period within 6 months. 

ACER has adopted two decisions amending the day-ahead and long-term capacity calculation methodologies for the Core capacity calculation region (CCR).

The Core CCR is the EU’s largest electricity capacity calculation region, covering 13 Member States: Austria, Belgium, Croatia, Czech Republic, France, Germany, Hungary, Luxembourg, the Netherlands, Poland, Romania, Slovakia and Slovenia.

ACER Decisions follow referrals by the regional national regulatory authorities under the Capacity Calculation and Congestion Management and the Forward Capacity Allocation Regulations.

What are the methodologies about?

Capacity calculation methodologies determine how much cross-border transmission capacity can be made available to electricity markets.

The day-ahead methodology determines how much electricity capacity is available for cross-border trading one day before delivery. The long-term methodology covers yearly and monthly capacity calculations, enabling long-term planning and hedging opportunities.

In the Core region, both methodologies apply a flow-based approach, meaning capacities are calculated by accounting for actual transmission network constraints. This improves efficiency compared to simpler methods.

Why amend them?

Currently, long-term capacity allocations are included in the day-ahead capacity calculation process. The Core transmission system operators (TSOs) proposed separating these two timeframes so that operational security, which is central to day-ahead capacity calculation, is no longer linked to the volume of capacity allocated in the long-term timeframe. 

This separation aims to better harmonise the region’s market timeframes and facilitate the transition towards long-term flow-based capacity calculation, planned for 2027.

What did ACER decide?

After reviewing the TSOs’ proposals and consulting with stakeholders, ACER approved the amendments, introducing changes to strengthen legal clarity and ensure compliance with EU electricity market rules.

Key amendments include:

Long-term methodology:

• introducing benchmark available transfer capacity (ATC) values as a transitional measure to support flow-based capacity calculation, better reflecting historical cross-border transmission capacities;
• establishing formal amendment procedures for any future changes to these values; and
• integrating the Ireland and Northern Ireland single electricity market–France bidding zone border into the Core region, following the commissioning of the Celtic Interconnector.

Day-ahead methodology:

• removing long-term allocations from the capacity calculation process; and
• updating the methodology to reflect the transmission system’s expansion and new infrastructure (including the Celtic Interconnector).

ACER’s Decisions support consistent capacity calculation in the Core region and facilitate the implementation of long-term flow-based capacity calculation.

Next steps

The Core TSOs must implement both amended methodologies for the 2027 capacity calculation processes.