European Electricity Market Research Articles

On market clearing of day ahead auctions for European power markets: Consumer payment minimisation versus social welfare maximisation

For inflexible demand and considering network constraints, we introduce a Consumer Payment Minimisation (CPM) market clearing mechanism and compare it with the standard Social Welfare Maximisation (SWM) used in European Day Ahead Electricity Markets. CPM presents a challenging optimisation problem, which we addressed by four numerical algorithms with varying computational costs and convergence guarantees, evaluated on synthetic data. We derive strong, partial analytical results and the concept of optimal zonal stack curves to facilitate efficient CPM solutions. Evaluations using 2019–2020 data from the Central Western European Day Ahead Power Market under the assumption of truthful bidding show that SWM models historical prices well, while CPM reduces producers’ market power and decreases zonal prices and total electricity procurement costs compared to SWM.

Impact of different CO2 price paths on the development of the European electricity system

In energy system transformation studies, the assumption of linearly rising CO2 prices is common and based on the decreasing issued European allowances (EUA). The actual auction price for allowances is influenced by market dynamics, resulting in non-linear variations in CO2 prices due to the possibility of banking allowances. This study explores the impact of non-linear CO2 price trajectories on the European electricity market. Various scenarios, such as increasing prices with the market interest rate, early price peaks, collapse, or fluctuations, are examined until 2030. The study quantifies the effects on power plant investments, profitability, consumer costs, and government revenues. The findings reveal that early and high price signals lead to an earlier transition with 7 % more wind power plants but at 4 % higher costs. Conversely, lower initial prices delay power plant investments in wind power plants by 6 % and result in 21 % higher emissions. Compensation for climate impact costs can yield a positive cost-benefit analysis in scenarios with early and high price signals when emissions are avoided through mechanisms like the Market Stability Reserve (MSR).

Impacts of large-scale deployment of vertical bifacial photovoltaics on European electricity market dynamics

Self-sufficiency, climate change and increasing geopolitical risks have driven energy policies to make renewable energy sources dominant in the power production portfolios. The initial boom in the mid-2000s of global photovoltaic installations demonstrated the feasibility of the ambitious renewable energy targets. However, this rapid scale-up has introduced challenges, including price volatility and system integration issues. This communication calls the attention to these emerging challenges and offers quantitative insights on how rapid adoption of a more diversified photovoltaics deployment strategies can mitigate price volatilities, reduce fossil fuel dependence and steer Europe towards a forward-thinking sustainable energy pathway. The analysis reveals that as innovative bifacial photovoltaic systems are incorporated on a large-scale disruptive scenario, four main patterns emerge: economic value of solar production increases, base-load electricity price decreases, sun-rich countries expand their solar contributions, whereas nations with ample grid interconnections enhance their energy imports from neighbouring countries. It also underscores the importance of maintaining photovoltaics an attractive option for energy investors and traders in the future. Establishing this groundwork is critical since a successful integration of large-scale solar systems contributing to decrease price volatilities in Europe and US will carry significant repercussions for global energy policy formulation.

Transitioning to a renewable hydrogen system: Optimal infrastructure for self-sufficient hydrogen supply in Austria by 2030

In this study, we employ an optimization model to optimally design a self-sufficient, independent of any imports and exports, hydrogen infrastructure for Austria by 2030. Our approach integrates key hydrogen technologies within a detailed spatial investment and operation model – coupled with a European scale electricity market model. We focus on optimizing diverse infrastructure components including trailers, pipelines, electrolyzers, and storages to meet Austria's projected hydrogen demand. To accurately estimate this demand in hourly resolution, we combine existing hydrogen strategies and projections to account for developments in various industrial sectors, consider demand driven by the transport sector, and integrate hydrogen demand arising from its use in gas-powered plants. Accounting for the inherent uncertainty linked to such projections, we run the analysis for two complementary scenarios. Our approach addresses the challenges of integrating large quantities of renewable hydrogen into a future energy system by recognizing the critical role of domestic production in the early market stages. The main contribution of this work is to address the gap in optimizing hydrogen infrastructure for effective integration of domestic renewable hydrogen production in Austria by 2030, considering sector coupling potentials, optimal electrolyzer placement, and the design of local hydrogen networks.

EU legislators approve the electricity market reform

The European electricity market is on the brink of transformative regulatory changes designed to reshape its landscape fundamentally. These changes encompass measures aimed at ensuring market stability, enhancing efficiency, promoting investment in clean energy, and safeguarding stakeholders from energy crises. Central to these reforms is the promotion of Power Purchase Agreements (PPAs) and Contracts for Difference (CFDs) to stabilize markets. Considering that existing barriers are impeding PPAs widespread adoption, the new design of the electricity market prompts regulatory adjustments to streamline access while maintaining fair competition. Concurrently, the design of CFDs must navigate competition distortions and ensure long-term viability, posing challenges for the European Commission in aligning them with State aid rules. Efforts to boost market efficiency include the reduction of intraday gate closure times, effective January 2026, and the establishment of minimum bid sizes to optimize resource allocation and pricing mechanisms. Moreover, the regulatory framework prioritizes incentivizing investments in clean energy, underscoring Europe’s commitment to sustainability. Member states will wield the power to implement non-fossil flexibility support schemes, offering payments for available non-fossil flexibility capacity, thereby fostering the transition towards cleaner energy sources. Lastly, protective measures are being instituted to shield consumers and undertakings from energy crises, emphasizing the need for resilience and stability in the sector. As these reforms unfold, policymakers must delicately balance fostering innovation, ensuring competitiveness, and safeguarding stakeholders’ interests. This article delves into the complexities of these reforms, offering insights into their implications and challenges.

Production or transmission investments? A comparative analysis

AbstractThe European electricity market is moving towards an integration process, and to facilitate that integration and the flow of electricity in that market, the European Transmission System Operator proposes different investments in transmission and production capacities. I develop a model of imperfect competition to study those investments, and I identify the economic forces that determine the equilibrium price and the flow of electricity: The size and the competitive effects. I prove formally when those forces operate simultaneously or independently, and how they determine consumers’ surplus and suppliers’ profits. I prove that an investment in transmission capacity outperforms an investment in production capacity by maximizing consumers’ welfare, but the performance in terms of suppliers’ profits is ambiguous.

Modeling and contribution of flexible heating systems for transmission grid congestion management

The large-scale integration of flexible heating systems in the European electricity market leads to a substantial increase of transportation requirements and consecutively grid congestions in the continental transmission grid. Novel model formulations for the grid-aware operation of both individual small-scale heat pumps and large-scale power-to-heat (PtH) units located in district heating networks are presented. The functionality of the models and the contribution of flexible heating systems for transmission grid congestion management is evaluated by running simulations for the target year 2035 for the German transmission grid. The findings show a decrease in annual conventional redispatch volumes and renewable energy sources (RES) curtailment resulting in cost savings of approximately 5% through the integration of flexible heating systems in the grid congestion management scheme. The analysis suggests that especially large-scale PtH units in combination with thermal energy storages can contribute significantly to the alleviation of grid congestion and foster RES integration.

Battery electricity storage as both a complement and substitute for cross-border interconnection

Cross-border interconnectors play a critical role in fulfilling the growing demand for cleaner and more affordable electricity. They are integral to completing the single energy market in Europe, so the European Union has set ambitious targets for the coming decade. Many challenges affect and delay the development of transmission infrastructure, and the deployment of non-wires alternatives such as battery energy storage systems may threaten the financial viability of these investments. We evaluate the potential impact of storage deployment on the profitability of cross-border interconnectors using the European electricity market model “EuroMod”. We find that higher battery penetration than projected in ENTSOE's TYNDP in 2030 significantly reduces transmission surplus (by €267 m to €506 m) under different battery uptake scenarios. To maintain the expected total surplus as projected by TYNDP in 2030, the continent-wide transmission capacity must decrease by 4.1–7.0%, potentially superseding 19–33% of planned transmission capacity expansions to 2030. Although cross-border interconnectors are of strategic importance for energy security and flexibility, the results highlight the pressing need for regulators, policymakers, and private investors to account for the rapid uptake of storage and integrate both storage and interconnectors in system planning.

Synergies and competition: Examining flexibility options in the European electricity market

The electricity market transitions from a market clearing in which flexible generation meets inflexible demand to one in which inflexible generation meets flexible demand. Consequently, new types of flexibility are needed to balance generation and demand. This paper mainly aims to analyse competition and synergy between various flexibility options in the electricity market. The developed European electricity market model maximises the joint socio-economic welfare of the electricity and the hydrogen market. Transmission grid,- storage expansion, electric vehicle demand side flexibility and hydrogen sector coupling are flexibility options. This work examines the implementation of different flexibility options in the bidding zones Austria and Germany. Austria, with a very high storage capacity in the alpine arc and Germany, with massive wind turbine capacities serve as representative case study. Results show that the storage location heavily influences the corresponding socio-economic welfare increase. Hence, location-dependent synergy and competition between storage and transmission line expansion can occur. In contrast, sector coupled hydrogen production and storage expansion compete with each other as both will reduce very low electricity prices. Demand-side flexibility primarily benefits end-users while producer surplus reduces. In combination with storage expansion, further positive synergistic effects for end-users occur. The combination of storage expansion and demand-side flexibility can replace transmission line expansion and vice versa if used comprehensively. Further efforts could address the evaluation of these effects if the individual flexibility providers aim for something other than a system-wide but individual optimum.

CONVERGENCE OF WHOLESALE ELECTRICITY PRICES ACROSS EUROPEAN MARKETS: ARE WE THERE YET?

European electricity market integration has been a research focus, especially after the third electricity directive emphasizing the internal market. Electricity markets are characterized by immediate consumption with storage and transmission constraints, leading to unique price dynamics. Price convergence in European markets can lead to competitive pricing, advocating market integration. This research examines whether European wholesale spot electricity prices converge. Prior literature uses sigma and beta-convergence to test price convergence. We have examined the stochastic convergence of prices across 19 European nations from 2013 to 2021 utilizing monthly data. For this analysis, we employed LM tests incorporating trend breaks grounded on the RALS regression framework. RALS-LM tests are more powerful than linear tests when structural breaks and nonnormal errors are present. LM and RALS-LM unit root tests with two trend breaks resulted in rejection of the unit root hypothesis for all countries, suggesting relative wholesale prices are stationary. Thus, shocks to relative prices are transient, supporting price convergence at the wholesale level. This result should be considered carefully as it contradicts the results from recent literature that examines retail electricity prices using beta- sigma- and club convergence. The policy implications of this finding can provide a foundation for establishing policies that promote a harmonized and integrated European electricity market.

The Devil in the details: The factors determining the selection of intrazonal congestion management methods across Europe

The European electricity market is becoming increasingly interconnected, raising questions about how intrazonal congestion management, typically governed by national regulations, interacts with the coupled cross-zonal markets. A major concern is the lack of information regarding intrazonal congestion management methods. This paper addresses this issue by examining different ways in which European transmission system operators (TSOs) use third-party resources to manage congestion in short-term electricity markets. We create a decision-tree-based classification to represent all identified congestion management methods and select three cases for comprehensive evaluation using predefined assessment criteria. While doing so, we identify a trade-off between efficiency and ease of implementation. The balance between these two factors is determined by the severity of the congestion. In a severely congested grid, locational signals are critical, requiring a better alignment between the network representation in the market clearing and the physical network constraints. When the congestion is less severe, TSOs can choose other congestion management methods based on factors such as the predictability of congestion and resource availability. These findings shed light on the complexities of congestion management in an integrated European market and can inform future policy decisions.

Regulatory incentives for transmission system operators under flow-based market coupling

Flow-based market coupling is a critical element of the electricity market in Europe. Transmission System Operators determine the commercial transmission capacity that can be implicitly traded in a zonal day-ahead market. However, this entails a trade-off: higher commercial transmission capacities increase market efficiency, affecting the electricity market prices, but also increase redispatch costs, affecting the network tariff. The decision on the commercial transmission capacity should optimally balance day-ahead welfare and redispatch costs, but depends on the rules and regulated incentives enforced on the TSOs. A MinRAM criterion, i.e., imposing minima for the commercial transmission capacity, is a one-size-fits-all policy without variation in time and space that unlikely leads to optimal transmission capacity allocation and is hard to tune because regulators have incomplete information. Incentive regulation is an alternative policy instrument promoting welfare-maximizing commercial transmission capacities, robust against information asymmetry. We provide a set of mathematical conditions to properly design an incentive scheme that rewards price convergence and penalizes excessive redispatch costs. Therefore, this paper serves as a stepping stone towards tapping the full potential of cross-border trade in zonal markets for policymakers, regulators, TSOs and market participants.

Energy efficiency strategies to improve productivity and competitiveness of the EU countries

Energy harmonization of the electricity market, infrastructure and decision-making in energy policy are a complex problem given the great technical contrasts, geopolitical diversity and different economic situations in the EU countries. Although the European authorities are taking steps, it will take a long time before an interconnected and harmonized electricity market in Europe is reached. The major challenges to face in the electricity sector in the EU are issues such as: the development of energy storage, as well as the intelligent network management, or demand-side participation by end-users in real time. The persistent dependence of fossil fuels on the electric mix remains a reality that dampens CO2 emissions and limits the use of clean technologies. At the same time, it is necessary to obtain a reliable data structure to obtain the reliable information with which to make decisions. Moreover, to analyze the information conecting different dimensions such as: energy sustainability, protection of the atmosphere, water and territory management. The present paper analyzes the appropriate variables for energy policy decision making, while alizing the behavior of several EU countries.

Exploring and Quantifying the Impact of Ex-Ante Market Power Mitigation in the Integrated European Day-Ahead Electricity Market

Exploring and Quantifying the Impact of Ex-Ante Market Power Mitigation in the Integrated European Day-Ahead Electricity Market

Reform of the European electricity market: Should we prefer a price based on a weighted average of marginal costs with cross-subsidies?

On the wholesale electricity market, the equilibrium price is set each hour on the basis of the marginal cost of the last power plant called, which is a gas-fired power plant a large part of the time in Europe. The surge in gas prices since the end of 2021 therefore largely explains the rise in the price of electricity. This paper analyses the reform projects proposed within the European Union to curb this surge in wholesale prices. It proposes then to reform the system by opting for pricing based on the weighted average hourly marginal costs, with financial compensation for power plants whose marginal cost is higher than this average. The quantitative study is conducted over the period January 1, 2020 through December 31, 2022 using ENTSOE hourly data. By implementing a compensation framework founded on average marginal costs, the market price experiences a significant decline, resulting in typically negative residual profits. Consequently, the fixed costs associated with the power plant fleet necessitate funding through the capacity market. This approach would enable French electricity consumers to align their payments with the structure of the national electricity fleet, specifically reflecting the average costs of power stations characterized by substantial fixed costs, such as nuclear facilities. The adoption of this proposed system is poised to expedite the energy transition toward a low-carbon economy.

Impact of large-scale hydrogen electrification and retrofitting of natural gas infrastructure on the European power system

In this paper, we aim to analyse the impact of hydrogen production decarbonisation and electrification scenarios on the infrastructure development, generation mix, CO2 emissions, and system costs of the European power system, considering the retrofit of the natural gas infrastructure. We define a reference scenario for the European power system in 2050 and use scenario variants to obtain additional insights by breaking down the effects of different assumptions. The scenarios were analysed using the European electricity market model COMPETES, including a proposed formulation to consider retrofitting existing natural gas networks to transport hydrogen instead of methane. According to the results, 60% of the EU’s hydrogen demand is electrified, and approximately 30% of the total electricity demand will be to cover that hydrogen demand. The primary source of this electricity would be non-polluting technologies. Moreover, hydrogen flexibility significantly increases variable renewable energy investment and production, and reduces CO2 emissions. In contrast, relying on only electricity transmission increases costs and CO2 emissions, emphasising the importance of investing in an H2 network through retrofitting or new pipelines. In conclusion, this paper shows that electrifying hydrogen is necessary and cost-effective to achieve the EU’s objective of reducing long-term emissions.

Attractiveness of Photovoltaic Prosumerism in the European Electricity Market

The current energy crisis calls for a rapid transition to renewables. Solar photovoltaics (PV) is the key component of the future energy system and a majority of PV systems are installed on rooftops in Europe. This article studies the business case of prosumers, i.e., consumers who produce part or all of their electricity with PV. The levelized cost of PV electricity is compared with the average value of PV electricity for the prosumers in residential, commercial, and industrial installations in Finland, Germany, France, Italy, and Spain with different self‐consumption (SC) and weighted average cost of capital rates. Prosumer business cases are positive in every studied market segment and country, especially for industrial PV systems with 100% SC where a payback time of less than 4 years can be achieved. The sensitivity of payback time on key input parameters is also studied. Reasonable cost of capital and adequate SC of PV generation remain the key elements for attractive prosumerism.

Dynamic volatility connectedness in the European electricity market

Since the 1990s, one of the energy policy objectives of the European Union (EU) has been to create a single, integrated European electricity market. This study uses a broad set of European electricity markets to answer the question whether volatility connectedness is higher in geographically closer markets or whether all markets are integrated. This question is particularly relevant now, at a time of high volatility of energy commodity prices, which can affect energy security in Europe. Our empirical analysis examines volatility connectedness in 26 European electricity markets between 1 August 2007 and 23 February 2022 using the time-varying parameter vector autoregressive model (TVP-VAR) based on the extended joint connectedness method (Balcilar et al., 2021). Furthermore, the impact of volatility of determinants of electricity prices on volatility connectedness in European electricity markets since 2016 is assessed.The results reveal that volatility connectedness between markets, i.e., the integration of European electricity markets, increases. Connectedness within geographically closer markets is observed mainly in the initial periods. However, since 2016, regional connections have increased, which is accompanied by interregional connections. This is particularly evident in the recent period –characterised by high volatility of electricity and energy commodity prices. However, when the impact of volatility of electricity price determinants on volatility connectedness is removed, especially since 2021, the results are slightly altered and indicate lower volatility connectedness in the European electricity markets. The role of the main net transmitters or net receivers does not change, while the role of the other markets changes or strengthens/weakens. Inter-regional connectedness is not as strong, which means that volatility connectedness occurs mainly in the markets from the same region.

SECURES-Met: A European meteorological data set suitable for electricity modelling applications

The modelling of electricity production and demand requires highly specific and comprehensive meteorological data. One challenge is the high temporal frequency as electricity production and demand modelling typically is done with hourly data. On the other side the European electricity market is highly connected, so that a pure country-based modelling is not expedient and at least the whole European Union (EU) area has to be considered. Additionally, the spatial resolution of the data set must be able to represent the thermal conditions, which requires high spatial resolution at least in mountainous regions. All these requirements lead to huge data amounts for historic observations and even more for climate change projections for the whole 21st century. Thus, we have developed the aggregated European wide climate data set SECURES-Met that has a temporal resolution of one hour, covers the whole EU area and other selected European countries, has a reasonable size but considers the high spatial variability.

Unlocking the Value of Aggregated Demand Response: A Survey of European Electricity Markets

This paper focuses on the possible roles of aggregators in the European electricity markets and the challenges and opportunities they face in participating in different market segments. Demand response (DR) is becoming increasingly important with the growth of renewable energy, and aggregators can play a critical role in balancing supply and demand in real time. This paper provides an overview of prices in electricity markets in which DR aggregators can participate and provides recommendations for aggregators regarding which markets to focus on. However, the regulatory framework for aggregators is still evolving in Europe, creating challenges for them to navigate different market designs, regulatory frameworks, and pricing mechanisms. Through a combination of literature review and data analysis, this paper aims to provide insights for aggregators on how to maximize profits and minimize risks in the European electricity market. The article achieves this by conducting an extensive analysis of various markets, comparing their essential attributes relevant to the functioning of aggregators.