Key drivers for electricity price changes in Europe

UNSPLASH | License | Arne Lindgren

The era of predictable and low electricity prices came to an end following the COVID-19 pandemic and the outbreak of the Russia-Ukraine war, presenting Europe with new energy-market challenges. As dependence on Russian energy declined, the role of more expensive American oil and liquefied natural gas (LNG) increased. Meanwhile, the European green transition has further emphasised the importance of renewable energy sources in the energy mix. However, the surge in gas prices has led to extreme fluctuations and imbalances in electricity prices across many European countries, as they remain closely tied to the gas market.

Despite market integration objectives, the introduction of renewable energy sources has brought a new dynamic to European electricity markets. This is reflected both in the increasing number of hours with negative electricity prices and in occasional extreme price spikes.

Costs of Different Energy Sources

The price of electricity is influenced by a combination of weather conditions, market dynamics, technological advancements, and regulatory factors. Among these various factors influencing the market, the balance between supply and demand is particularly crucial. Demand is shaped by consumers’ price sensitivity and the volume of electricity they intend to purchase. At the same time, supply is largely determined by the energy mix composed of various generation technologies, which can be categorised into three primary sources: fossil fuels, renewables, and nuclear energy. These categories can be further divided: within fossil fuels, natural gas and coal are key cost components, while in the renewable sector, solar, wind, hydro, and geothermal energy prices are the most influential.

Since the cost of producing a unit of energy (be it measured either in kWh or MWh, the point is to maintain consistency in comparisons between different power plant types) depends on the specific conditions of each country, these sources are best compared using the so-called Levelized Cost of Energy (LCOE), which represents the lifetime average cost per unit of electricity generated.

Over the past 15 years, the most significant LCOE reduction (85%) has been observed in solar photovoltaic (PV) technology, primarily due to economies of scale in manufacturing and the widespread penetration of solar power plants.

The cost of onshore wind energy has more than halved, driven by increasing turbine efficiency and declining operational expenses (OPEX). Offshore wind energy has seen an even greater LCOE reduction (65%); however, its 2023 cost level remains higher than that of onshore wind power (BloombergNEF, New Energy Outlook 2023). Nevertheless, due to the steadier wind conditions at sea, offshore wind farms offer more stable electricity generation and thus better revenue potential.

Run-of-river hydroelectric power plant remains a reliable and low-cost energy source, with pumped-storage hydro plants playing a crucial role in energy storage (IRENA, Renewable Power Generation Costs in 2023). However, due to site-specific limitations and high capital expenditure (CAPEX) requirements, hydropower has not gained a competitive edge in the past one and a half decades.

Geothermal (and biomass) technology shares several similarities with hydropower: while it can provide continuous electricity generation, its site-specific nature has limited its widespread expansion in Europe (Fraunhofer ISE: Levelized Cost of Electricity – Renewable Energy Technologies).

The LCOE of natural gas has shown a slight increase. Although the capital and operational costs of gas power plants have not changed significantly, carbon pricing mechanisms have driven up the cost per unit of generating electricity (IEA, World Energy Outlook 2023).

Coal-fired power generation has experienced an even steeper cost increase, attributable to the same factors affecting natural gas. With the continued expansion of renewable energy sources, coal’s LCOE is expected to become unsustainably high. By 2023, wind and solar energy had already displaced coal in the energy mix in countries like the Netherlands, Italy, and France, according to ENTSO-E data.

The LCOE of nuclear energy has remained relatively stable over the years. While its high CAPEX and long construction timelines (especially for conventional nuclear power plants) pose challenges, its ability to provide steady, baseload power and its carbon-free operation make it an essential component of the European energy mix.

Examining the changes in the average LCOE per MWh across different power plant types, it is evident that while coal has experienced a slight cost increase, solar and wind energy –particularly offshore wind – have seen dramatic cost reductions.

The following chart illustrates the aforementioned LCOE trends across different energy generation methods, highlighting the substantial cost declines in solar and wind power.

The Expansion of Renewable Energy Sources in Europe

As a result of the European Union’s emission-reduction policies, renewable energy sources are increasingly replacing traditional fossil fuels. According to the European Electricity Review 2024 published by EMBER, more than 44% of the EU’s energy mix in 2023 came from renewable sources.

For the first time in history, European renewables generated more electricity in 2023 than fossil fuel and nuclear power plants combined. Parallel to this green transition, coal- and gas-based energy production significantly declined, with coal generation dropping by 26%, and gas by 15%, compared to the previous year. The two driving forces of renewable energy production were solar and wind power, which together accounted for more than a quarter (27%) of the EU’s total electricity generation. Notably, in 2023, wind energy surpassed gas for the first time in the EU energy mix (EMBER, European Electricity Review 2024).

However, weather-dependent power sources, due to their production variability, cannot always meet the rising electricity demand driven by heat pumps, air conditioning, and other energy-intensive technologies. Additionally, long-term energy-storage technologies remain costly. As a result, fossil-fuel-based gas power plants are still required for intermittent electricity production to compensate for shortages and ensure balancing power, contributing to rising intraday market prices.

Before the widespread integration of renewables, the stability of grid frequency was primarily maintained by highly flexible gas-fired power plants. This role remains crucial in today’s electricity market, especially as renewable power generation is significantly less predictable. Due to the lower scheduling accuracy and intermittent nature of wind and solar power, gas power plants have assumed an even greater role in balancing and backup generation. Consequently, grid flexibility challenges now stem not only from fluctuating consumption but also from the increasing unpredictability of electricity generation. In an energy mix with a substantial share of weather-dependent capacity, higher reserve capacity is necessary compared to a system primarily reliant on conventional energy sources.

The rise of renewables has significantly reshaped the electricity-market supply. The increasing number of solar and wind farms pushed the more expensive, typically fossil-fuel-powered plants further down the dispatch order, reducing the need for extended gas-power-plant operation. However, this transition has led to higher costs associated with fossil fuel plant utilization.

On one hand, reduced operating hours have prompted fossil-fuel power plants to set higher prices to cover their fixed costs over these shorter periods. On the other hand, their costs are further driven up by the EU’s Emissions Trading System (ETS), which requires CO₂-emitting power producers (mainly fossil-fuel-based generators) to purchase allowances to cover their emissions. As allowance prices increase, the production costs of coal- and gas-fired power plants rise accordingly. Under the current quota system and methods, providing cheaper balancing power is simply not feasible.

Finally, geopolitical tensions arising from the Russia–Ukraine conflict further aggravate the situation. The global market price of energy carriers has increased due to the shift away from Russian gas toward alternative sources such as LNG, which involves additional costs. These factors have had a substantial impact on European electricity prices.

Flexibility and Energy Storage

Reserve capacity can be provided by the previously mentioned gas power plants, which are responsible for supplying balancing power and can be quickly activated but come with relatively high operating costs. Alternatively, various energy storage technologies can also contribute to system flexibility. Among these, Battery Energy Storage Systems (BESS) have seen the most significant growth.

According to the August 2024 annual report by SolarPower Europe, a solar industry organization, battery storage capacity in Europe has doubled every year since 2020. Despite this rapid expansion, the current storage capacity remains relatively low: in 2023, it stood at just 17.2 GWh. To put this into perspective, European renewable energy sources (482 GW) generate the same amount of electricity in just over two minutes, while European consumers use this much energy in less than two minutes during peak-demand periods. As a result, energy storage remains an unsolved challenge in the short and medium term (1–2 days), contributing to the high prices on intraday and balancing markets across the EU.

The Price Wall in the European Electricity Market

Partly due to the above-mentioned factors, significant electricity price differences can emerge between countries with varying production structures and infrastructural conditions. Although these disparities typically last for only short periods – sometimes just a few hours –, they highlight structural weaknesses in the pan-European electricity system.

The ‘price wall’ is a recurring phenomenon in the European electricity market, and it means that sharp price differences develop between different regions of the continent. This is particularly noticeable between Central and Southeastern Europe, on the one hand, and Western Europe, on the other. On the western side of the ‘wall’, electricity prices are significantly lower, while on the eastern side, they can be two to three times higher.

The formation of the price wall is primarily linked to the limited network capacity and the differing operational conditions across regions. Analysing electricity prices on 15 July 2024 reveals a clear division between the two parts of the continent.

The emergence of the price wall is the result of multiple factors. In the summer of 2024, extreme heat led to a substantial increase in electricity demand in Eastern Europe. However, high demand alone does not fully explain the situation: differences in market-regulation methods and weak infrastructural connections between regions also play a crucial role. While Southeastern Europe employs the traditional NTC (Net Transfer Capacity) method, which focuses on energy flow between neighbouring countries, Western Europe utilises a more advanced flow-based market-coupling system (FBMC). The latter considers the actual capacity of the entire network, making it more efficient but sometimes restricting energy flow in certain directions when the grid is overloaded, or other constraints arise.

The limited network interconnections also significantly contribute to the formation of the price wall. Insufficient connections between Bulgaria, Romania, Greece, and the rest of the EU create major obstacles. Southeastern Europe has relatively few cross-border transmission capacities, hindering the free flow of electricity from western markets to the east. According to a report published by ENTSO-E in May 2024, the electricity infrastructure in Eastern and Southeastern Europe lags significantly behind that of Western Europe, where grid interconnections between member states are denser and more robust.

With the growing penetration of renewable energy sources, the challenge of limited interconnections between national transmission networks is becoming even more pressing. It is evident that, on the western side of the price wall, extensive cross-border capacities facilitate electricity trade between member states, whereas, on the eastern side, opportunities for international electricity flows are much more restricted.

Another factor influencing local price increases has been the war-driven surge in Ukraine’s electricity-import demand, which has added further pressure to regional demand and pricing. Between May and June 2024, Ukraine’s electricity imports more than doubled to 850,000 MWh, which is 6% higher than the total import volume for 2023. In June 2024, 42% of Ukraine’s electricity imports came from Hungary, 17% from Slovakia, 17% from Romania, 16% from Poland, and 8% from Moldova, according to data from the Ukrainian think tank DixiGroup.

Beyond these structural reasons, additional temporary factors also contribute to the emergence of the price wall. These include power plant and substation maintenance or upgrades, as well as seasonal reductions in the output of renewable energy sources, such as hydropower plants in summer.

Price walls can be considered market anomalies, as they highlight extreme situations caused by imbalances between electricity supply and demand. However, the price wall is not the only phenomenon disrupting market operations. Similar factors – such as the weather-dependent production of renewable energy sources and the limitations of grid interconnections – can lead to other irregularities. These include negative electricity prices, which may occur when an inflexible system experiences an oversupply that cannot be properly managed through, for example, exports.

The Reasons Behind Negative Electricity Prices

The vast amounts of green energy (mainly wind and solar) available in Germany and the Nordic countries periodically lead to oversupply, which inevitably drives down electricity prices and, in some cases, pushes them into a negative range. In the third quarter of 2024, Europe’s solar power generation reached a record 94 TWh – the highest ever recorded – representing a 15% increase compared to the same period in the previous year. Wind power generation stood at 104.7 TWh, marking the second-highest quarterly value ever measured.

Another key factor contributing to occasional low electricity prices is the system of Guarantees of Origin, widely applied in Sweden and Norway. These certificates ensure that the electricity purchased and consumed by end-users originates from a specific (typically renewable) source. This mechanism encourages continuous renewable energy production even during periods of oversupply, as the value of these guarantees can only be realised for energy that is generated and fed into the grid.

The electricity market has two potential ways to manage this issue: it could either abandon the sale of Guarantees of Origin or limit the production of conventional power plants, such as nuclear facilities. However, for environmental reasons, the former is not an option, and due to operational safety concerns, the latter is also not feasible. This results in significant supply pressure, leading to increasingly frequent occurrences of negative electricity prices across Europe.

As a consequence, the day-ahead electricity market in Scandinavian and German regions experiences a disproportionately high number of hours with negative prices. Moreover, the number of negative-price hours has been steadily increasing year after year. In Germany, there were 69 hours of negative electricity prices in 2022, but this figure more than quadrupled (to 301 hours) in 2023. The trend accelerated further in 2024: while solar and wind power generation reached record levels in the third quarter, the number of negative price hours surged in several countries. In Finland and parts of Sweden, for example, there were over 200 hours of negative prices in Q3 alone.

The oversupply of renewable energy, particularly during solar generation peaks, has significantly widened the price gap between peak and off-peak hours. Due to the nature of the European electricity market, this phenomenon has had ripple effects across the entire continent. While negative prices may seem beneficial from a consumer perspective, they pose significant risks to the market as a whole. Such extreme price fluctuations – ranging from −€500 to +€4,000 – are exceptionally large compared to other markets and can result in substantial financial losses for market participants.

Conclusion

Based on the energy-market phenomena outlined above, it can be concluded that the anomalies in the European energy market stem partly from the rapid expansion of renewable energy sources and partly from infrastructure limitations.

The increasing share of solar and wind power has displaced gas-fired power plants, which are capable of flexible production adjustments, from daytime generation. As a result, their operation has been largely restricted to evening and nighttime hours. This shift significantly impacts their cost recovery, as they now have a shorter window to generate revenue, forcing them to sell electricity at much higher prices than before. Due to the intermittent nature of renewables, when demand exceeds supply, the market balance shifts towards higher-cost energy producers, leading to substantial price spikes. Conversely, during periods of oversupply, negative electricity prices emerge. While these may initially seem beneficial, they pose serious long-term risks.

Market anomalies of this kind can jeopardise the economic viability of stable energy providers, preventing them from securing sufficient revenue to sustain operations. In extreme cases, this could lead to the shutdown of essential power plants, reducing overall system reliability. Additionally, the unpredictability of returns discourages future investments in the sector.

The lack of adequate infrastructure, particularly the limited availability of cross-border transmission capacity, worsens regional disparities. In Central and Southeastern Europe, electricity prices are multiple times higher than in other parts of Europe due to these constraints.

Industry analyses consistently indicate that the key to resolving these issues lies in advancing energy-storage technologies and increasing grid flexibility and capacity. A truly sustainable transition requires not only large-scale renewable energy generation but also the development of the infrastructure needed to store and distribute this energy efficiently.

This post is a reprint of an article written by our colleague, which was originally published on March 18, 2025, in the online journal CEEnergy News.