Summary of ACER’s Monitoring Report on the development of wholesale energy markets in the EU in 2025

On March 16, 2026, the Agency for the Cooperation of Energy Regulators (ACER) published its annual monitoring report on key developments in the EU electricity and natural gas markets, covering data through the end of 2025. The report is structured around four main themes: global context and price competitiveness, the transformation of the electricity market driven by solar energy, dynamics of the gas markets, and flexibility deficit in the system.

The analysis does not reflect geopolitical developments since the beginning of 2026, which represents a significant limitation given the unstable international situation.

Price competitiveness – the widening gap between the EU and the US

One of the report’s key messages is that the difference in industrial electricity prices between the EU and the US continues to widen. In 2015, the average end-user price for industrial consumers in the EU-27 was 98 EUR/MWh compared to 62 EUR/MWh in the US—a difference of 58%. By 2025, this gap reaches 104% (151 EUR/MWh in the EU versus 74 EUR/MWh in the US). During the crisis in 2022, the price in the EU peaked at 215 EUR/MWh (+172% compared to the US). Although a post-crisis decline has occurred, prices have not returned to pre-crisis levels.

Regional differences within the EU are also significant. In the first half of 2025, the final price for industry in Sweden was 85 EUR/MWh, in Italy 161 EUR/MWh, and in Germany 188 EUR/MWh. By comparison, in Texas the price is 57 EUR/MWh. ACER emphasizes that the competitiveness of European industry hinges on the efficiency of the three main components of the final bill: the wholesale market price, network charges, and taxes.

Electricity prices for households are stabilizing at elevated post-crisis levels: an average of 295 EUR/MWh in the EU-27 in 2024 (compared to 218 EUR/MWh in 2020). The energy and supply component now accounts for 49% of the final price, while network costs make up 27% and taxes and fees 24%. Fixed-price contracts and hedging strategies are slowing the pass-through of the decline in spot market prices, and the expiration of crisis-era tax breaks is an additional factor.

At the wholesale level, electricity in the EU is approximately 1.5 times more expensive than in the US, while natural gas is about three times more expensive. The price spread for electricity is mainly due to differences in the generation mix and fuel costs, with Europe’s higher exposure to gas price dynamics continuing to exert pressure despite the growing share of RES.

Renewables account for 50% of electricity generation: the solar transformation

In 2025, renewable sources provided about 50% of electricity generation in the EU-27/EEA (for the second consecutive year). Solar generation has increased by 41 TWh compared to 2024, establishing itself as the fastest-growing source and overtaking coal. In terms of installed capacity, annual new solar capacity reached 50 GW in 2025 (compared to 18 GW in 2020). By comparison, new onshore wind capacity is 9 GW (up from 8 GW in 2020), while offshore capacity is just 0.5 GW. The growth rate of wind energy is clearly slowing, which is cause for concern given its central role in balancing energy systems during the transition.

Despite the growth in renewable energy, wind and hydroelectric generation will decline in 2025 due to unfavorable weather conditions: wind generation by 14.3 TWh and hydroelectric generation by 43.1 TWh. The proportion of time during which the wind capacity utilization rate was below 10% increases from 10.3% in 2020 to 16.6% in 2025—a trend linked to more frequent and prolonged periods of low wind (Dunkelflaute). Gas-fired generation increases in the short term by 33 TWh to compensate for the shortfall.

The “duck curve” deepens: negative prices and widening intraday spreads

Growing solar penetration is transforming pricing patterns in the exchange market. Cheap electricity at midday, when solar generation is highest, contrasts with sharp price spikes in the evening, when solar output drops and available system flexibility is limited. The average difference between the minimum and maximum exchange prices within a day is increasing fivefold compared to 2020: from 28.3 EUR/MWh to 109 EUR/MWh in 2025.

The share of hours with prices below 5 EUR/MWh is expected to rise from 9% in 2020 to 10% in 2025, while the share of hours with prices above 150 EUR/MWh is projected to increase from 1.1% (2021) to 8.5% (2025).

On May 1, 2025, an extreme intraday price spread of 294 EUR/MWh was recorded in Germany: the exchange price fell to -130 EUR/MWh at noon and rose to +164 EUR/MWh in the evening. On July 1, 2025, a heat wave in Europe increases demand by about 6% (in France, every degree above 20°C adds approximately 600 MW of load), while elevated river temperatures limit the cooling capacity of nuclear and thermal power plants. Prices exceed 400 EUR/MWh in Germany and 470 EUR/MWh in Poland.

An important institutional step is the transition of the European day-ahead market to 15-minute trading granularity starting October 1, 2025, which allows for a more accurate reflection of rapid changes in solar and wind generation and creates better price signals for flexible resources such as batteries.

The evolution of gas’s role from baseload to peak pricing

The report identifies a fundamental shift in the role of gas-fired power plants in the European electricity system. Gas is transitioning from a role as constant baseload generation to that of a flexible reserve, primarily balancing the market during peak hours and when renewable energy production is low. The average number of daily starts for gas-fired units is increasing from 57 in 2019 to 88 in 2025, while the average operating hours per start are decreasing from 69 to 38. This implies a more intensive cycling regime, shorter operating periods, higher production costs, and lower thermal efficiency.

The share of hours during which gas generation is profitable (“gas-in-the-money”) remains at around 43% in 2025. These hours coincide with periods of low solar and wind availability, when gas-fired power plants are brought online to cover residual demand.

The correlation between gas and electricity prices remains moderately positive, albeit with a downward trend—a reflection of a transitional system in which renewables are increasingly shaping pricing patterns, but gas still sets the price during peak hours. A high share of fossil fuels in a country’s generation mix correlates directly with higher carbon intensity and higher exchange prices. Bulgaria is among the countries with a fossil fuel share of around 30% and an average exchange price in the upper range of the ranking.

The gas market per se is stabilizing amid shifting dependencies

The EU’s gas mix in 2025 remains heavily dependent on imports: 50% pipeline gas, 40% LNG (primarily from the U.S.), and 10% domestic production and storage. Russian pipeline supplies decrease by 162 TWh compared to 2024 following the cessation of transit through Ukraine, which is offset by a 356 TWh increase in LNG imports. The US now supplies over 50% of the EU’s LNG and 27% of total gas supplies (worth approximately €23 billion in 2025).

Global LNG supply is growing significantly and between April and December 2025 is 412 TWh (35 billion cubic meters) higher than the three-year average. By 2030, new supply (+250 TWh/month) is expected to reach twice the volume of current EU imports. This contributes to narrowing the price spread between the US and the EU, particularly in the final quarter of 2025.

The second half of 2025 marks a break in the trend of volatile gas prices: price volatility on the NL-TTF falls to its lowest levels since 2020, even though EU gas storage levels are at their lowest since 2021 – 82% on November 1 and 62% at the end of the year. However, gas consumption in the EU is projected to rise slightly by about 2% in 2025 (339 billion cubic meters), which slows the pace of achieving the Fit-for-55 (280 billion cubic meters by 2030) and REPowerEU (190 billion cubic meters) targets. An additional reduction of 17–44% from 2025 levels is needed over the next five years.

The flexibility deficit: the central challenge

The ACER report identifies insufficient system flexibility as the main structural weakness of the European electricity system. The growing spreads between peak and off-peak market prices reflect a system in which the growth of RES is outpacing the development of storage solutions, demand response, and interconnections. Price models for 2025 show a clear geographical divide: countries with more hours of negative prices typically have fewer extreme price spikes, and vice versa, highlighting the role of interconnections in smoothing volatility.

The electricity grid requires significant investment to support electrification: projected annual investment needs reach 100 billion euros between 2025 and 2050. By 2030, the EU could benefit from an additional 85 GW of interconnection capacity (compared to today’s 50 GW). The forecast for grid costs for households shows a 66% increase between 2022 and 2050—from 32 to 51 EUR/MWh.

Alternatives to gas storage for seasonal flexibility remain underdeveloped—biomethane accounts for only about 2% of the EU’s total gas supply.

ACER Recommendations

The report outlines three main groups of recommendations:

• Efficiency and market integration for affordability and competitiveness: ensuring efficiency across all components of the final electricity price (exchange price, network charges, taxes) to improve affordability for households and the competitiveness of industry; Expanding market integration to support decarbonization and Europe’s global competitiveness.
• Strengthening system flexibility and interconnections: accelerating the deployment of demand response, storage, and other flexibility solutions to address widening intraday price spreads; Ensuring market signals that enable flexible resources to respond effectively to evening price peaks; strengthening cross-border interconnections to reduce regional price differences.
• Further diversification of gas supplies and low-carbon alternatives: reducing conventional gas consumption while accelerating the uptake of renewable gases; careful planning of infrastructure development and tariff design to limit the growth of network costs without compromising security of supply.

Implications for Bulgaria and the region

The report contains several observations directly relevant to Southeast Europe and Bulgaria. The high prices in the SEE region in July 2024 are explicitly noted as a distinct market episode. The cessation of Russian gas transit through Ukraine led to a price divergence in Central and Eastern European hubs in early 2025, with stronger flows from the west and rising transportation costs. Bulgaria ranks among the countries with a fossil fuel share of around 30% in the generation mix and an average exchange price at the upper end of the range. The share of hours with prices above 150 EUR/MWh in Bulgaria and Romania is among the highest in the EU (17–19%), while hours with negative prices are practically zero—direct evidence of insufficient flexibility and limited interconnection capacity to effectively absorb the growing capacity from RES.