The Internal European Electricity Market: Achievements over the past 25 years, challenges it faces and what lies ahead

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Professor Dr. Klaus-Dieter Borchardt is a Senior Energy Advisor at Baker McKenzie and former Deputy-Director General for Energy at the European Commission

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The Internal European Electricity Market: Achievements over the past 25 years, challenges it faces and what lies ahead

by Prof. Dr. Klaus-Dieter Borchardt

An integrated EU energy market is the most cost-effective way to ensure secure, sustainable and affordable energy supplies to EU citizens. Through common energy market rules and cross-border infrastructure, energy can be produced in one EU country and delivered to consumers in another. Creating competition and allowing consumers to choose energy suppliers keeps prices in check. The liberalisation of the EU energy market has largely been successful in achieving these goals. The creation of a single market has facilitated cross-border trade and increased security of supply, and the separation of generation, transmission, and supply activities, the so called unbundling, has allowed for greater competition and market efficiency.

However, to get to this point was not an easy task. The national systems were characterised by a vertically integrated structure, where a single entity controlled the entire value chain from generation to supply. The goal was to provide reliable electricity to citizens, with little concern for competition or market efficiency. To introduce competition and incentivise efficiency, as well as to create a single market for electricity five substantial Internal Energy Market Design Packages have been necessary between 1996 and 2024. 

At the heart of the electricity market is the wholesale market, where electricity is bought and sold between generators, traders, suppliers, and aggregators. The price in this market is determined by supply and demand, with prices fluctuating based on the amount of electricity being produced and consumed. This principle aims to ensure that demand is served at any moment in time in the most cost-effective way. The power is then sold by suppliers via the retail market. The EU market reform process has included retail competition from the start. The concept of eligible customers who have the legal capacity to contract electricity from any supplier was introduced and later complemented by the concept of prosumers defined as individuals who consume and produce power, either for self-consumption or for selling the excess power for the consumption by others. 

In parallel, there has been the development of power exchanges and a system of market coupling, whereby national markets are merged or coordinated. The introduction of day-ahead and intra-day market coupling have been milestones in creating the conditions for a higher degree of market integration. Prior to market coupling a trader that wished to sell electricity between two markets would need to buy the power in one market, sell the power in another, and separately procure the transfer capacity on the interconnector between them, a quite costly and cumbersome process. Under market coupling, available transfer capacity is declared to the markets, and power can be bought and sold between the two markets subject to one market-clearing algorithm. If there is enough transfer capacity, the prices in the two markets should be the same; if there is a transmission capacity constraint, power should flow from the low-price market to high-price market. 

Overall, the development of the electricity market design has been a complex and ongoing process, yet its evolution has led to a more dynamic, market-driven system guaranteeing security of supply and affordable prices.

However, the latest energy price crisis in 2022 has dramatically shown that one cannot take neither security of supply nor affordability for granted. Over the next 20 years the EU's energy market must transform fundamentally, and the Internal Market needs to continue to adapt to be 'fit for purpose', to continue to drive the three overarching energy policy objectives which are security of supply, sustainability, and competitiveness. In addition, the energy system of the future must considerably contribute to reaching the net-zero emission target by 2050 at the same time. The EU's electricity market will need to be decarbonised by 2040 in line with the Emission Trading System (ETS) trajectory and the 90% Green House Gas (GHG) emission reduction target which the Commission has made public in February this year. 

The response to this challenge is to move towards a more Integrated Energy System. Today the EU's energy system consists of several rather parallel, vertical energy value chains, linking specific energy resources or commodities with specific end-sectors. In the future, the energy system will require a much more integrated and dynamic interaction between suppliers, energy grids and end-customers, and across the different energy markets, facilitated by the advances in new green energy technologies and digitalisation. The different energy carriers (electricity, heat, gas, solid and liquid fuels) will have to be better and more innovatively linked and converted to enable them to compete against one another, to ensure correct price signals and to provide these energy services in the most cost-efficient and carbon-neutral manner. In this sense, Energy System Integration is a strategy to link the production and the various energy carriers with each other as well as with the energy demand sectors, whilst using smart and green technologies to optimise the energy system as a whole, instead of each sector independently. 

In order to prepare for the power market of the future the following measures might be envisaged:
The marginal pricing system that we know from today where the cheapest possible sources of electricity will be used, and where the wholesale electricity price will be set by the price of the last selected offer in the auction to meet demand should remain the basis for the price fixing in the wholesale market. This pricing system has delivered over the years a number of essential advantages, notably: 

  • the cost minimalisation by tapping into the cheapest source of electricity production first;
  • the reduction of carbon intensity by prioritising low carbon energy sources in the mix;
  • the viability of existing and future investments; and 
  • the transparency of the day-ahead price signal, advantages which are still present and justify to keep the marginal price system. 

However, as the energy price crisis in 2022 has shown, the marginal price setting has led to perverse outcomes of having sometimes very high consumer prices for power determined by sky-rocketing gas prices despite the fact that large blocks of power were produced at costs well below those prices. Emergency measures such as windfall taxes on renewable energy and low cost power was introduced so that governments could claim funds which were often redirected to consumers who suffered from high energy prices. To mitigate these challenges in the future, a goal for the power market might be to remove as much power as possible from the marginal price market by pre-selling it so that the scale of the market which displays and delivers these outcomes is smaller, and fewer producers and consumers are effected by them. 

Two leading methods of pre-sale of the power upstream are Power Purchase Agreements (PPAs), and Contracts for Difference (CfDs).

  • PPAs are direct purchase contracts between producers and consumers of power where the price is fixed for long periods. In order to play a mitigating role the PPA power market needs to increase by order of magnitude which requires the creation of better conditions for PPAs that are able to deliver a market of the required size.
  • CfDs are long-term contracts between the electricity generator and the State which enable the generator to stabilise its revenues at a pre-agreed level (the strike price) for the duration of the contract. Under the CfDs, when the market price for electricity generated by a CfD is below the strike price set out in the contract, payments are made by the State to the generator to make up the difference. However, when the market price is above the strike price, the generator pays the State the difference (two-ways-CfD). The level of the strike price provided by the State is one of the most important decisions to make in CfD contracts. It is typically found through a competitive bidding procedure, where generators compete against each other on which fixed price is sufficient for them to go forward with their respective investment project.

Taken together, this vision for the future power market reform requires the promotion and expansion of CfDs, a much larger growth in the PPA market and the marginal price market remaining to provide the discipline of the market in hour-to-hour trading albeit on a smaller segment of the markets.

The rapid ongoing deployment of variable renewable energy generation comes with the need for considerable flexibility in the energy system. In the mid-term, demand needs to become increasingly flexible to match intermittent generation, as renewables replace traditional power plants using fossil fuels. In the short term, energy demand needs to be reduced in order to moderate high prices. Having demand response participate in all electricity markets, including notably the balancing and wholesale markets, is the most efficient way to achieve these goals. The benefits are huge because the need for gas and peak power generation are reduced, as are the wholesale prices during peak hours.

Investments in flexibility might not be adequately rewarded under the current market design, despite being critical to guaranteeing security of supply at all times and nodes of the network. The reason is two-fold:

  • in energy only markets, payments to generators are solely a function of their production; and
  • some flexible technologies are still not mature enough and need additional support to become profitable.

Capacity mechanisms which are temporary support measures that EU countries can introduce to remunerate power plants for medium and long-term security of electricity supply could be a useful instrument in this regard. They enable power plants to be available for generating electricity when needed. In exchange, the mechanisms provide payments to these power plants. These capacity payments are in addition to the earnings that power plants gain by selling electricity on the energy market. These capacity mechanisms require a detailed and ongoing review to ensure that they are fit for purpose and are based on Energy System Integration. 

Finally, a review of the bidding zones and their future usefulness might be needed: Bidding zones are areas in Europe in which a single (wholesale) electricity market price applies. The day-ahead market where supply and demand are balanced to set the price for electricity for every hour of the following day is Europe’s lead market for electricity. Every day, power exchanges across the EU publish wholesale electricity prices for the EU’s bidding zones. The zonal design was relatively simple to implement, with quick benefits for market integration. However, it is increasingly evident that the zonal markets are largely based on political borders and not, as it should be, to match the technical requirements in order to make zonal markets and flow-based allocation a success. Furthermore, trade between bidding zones is limited to the level of cross-border capacity. That creates boundaries on how much trade is technically feasible and implicitly prioritises internal trade over cross-border trade which may foreclose national markets, and create barriers to competition. By the end of 2025 Member States have to make sure that 70% of the capacity is allocated for cross-border trade. It remains to be seen whether this obligation will make the trick or whether a move from the zonal to the nodal system will take place where prices are differentiated by location (locational marginal pricing).

All in all, one can conclude that the EU has made huge progress over the past 25 years in the development of a truly integrated European electricity market. However, there is no time for self-complacency; new challenges lay ahead, first and foremost to achieve the decarbonisation of the energy sector by 2040 and the pursuit of the three overarching energy policy objectives which should not remain a "trilemma" but will become an essential part of the European Energy System Integration.