Framework of Market Coupling

Abstract of Chapter 1 Framework of Market Coupling

This chapter introduces the key building blocks of the electricity market in Europe. From the First Energy Package in 1996 to the Fifth Energy Package in 2021, Europe’s single, integrated electricity market has been evolving over the last three decades. The Guideline on Capacity Allocation and Congestion Management (CACM Guideline) is also introduced, which ensured that market coupling became the mandatory means of allocating cross-zonal capacity in the day-ahead and intraday timeframes. Furthermore, this chapter describes the key aspects of the integrated market design from bidding zones and market coupling to price formation and congestion income. Additionally, the enablers of market coupling including Transmission System Operators, Regional Coordination Centres, and Nominated Electricity Market Operators are explained. The chapter closes by discussing current and upcoming developments in market coupling.

1.1 Key EU Energy Packages Shaping European Market Integration

Aiming to create a single, integrated electricity market with fair market access and a high level of consumer protection, as well as adequate levels of interconnection and generation capacity, the EU has taken several steps over the last three decades.

Fig. 1.1 Evolution of electricity markets and the relevant EU regulatory packages. Source: Adapted from Poplavskaya (2021)

As illustrated in Fig. 1.1, it started with mandating the liberalization of thepower sector with the aim to break up the monopolies that historically ran national energy markets. A stepwise process of unbundling business activities into transmission, distribution, generation, and retail was put in motion. With the First Energy Package (entry into force 1996), unbundling of accounting was mandated.

In 2003, with the Second Energy Package, legal unbundling was imposed.National Regulatory Authorities (NRAs) were established to oversee the activities of the newly formed Transmission System Operators (TSOs). As member states implemented the requirements of the First and Second Energy Packages, the power sector became composed of both regulated entities, such as transmission and distribution system operators (DSOs), whose networks represent natural monopolies, and deregulated market participants in wholesale and retail markets.

The Third Energy Package (2009), and the guidelines that derived from it, made market coupling obligatory and created a framework for TSOs¹ working together to compute cross-zonal capacities in a coordinated manner.

In 2019, the Clean Energy for all Europeans (CEP) arrived, further paving the road for EU energy market integration. At the heart of this package are the proper functioning of the internal market and its competitiveness by mandating market-based principles for operating the electricity market. In this sense, it also lays the groundwork for the access of all technologies on the supply and demand side in the electricity markets and enables a non-discriminatory and technology-neutral approach for market participation across borders.

To date, the latest energy package, the “Fit for 55” (fifth) package, entered into force in 2021. This package is set to align EU energy targets with its climate ambitions.

Finally, the recent energy crisis of 2022 had a profound impact on the integrated electricity market and put it through a true acid test. This crisis, among other drivers, spurred the review of the market design by the Agency for Cooperation of Energy Regulators (ACER) and later the Electricity Market Design Reform that was adopted in June 2024, as will be discussed in the last section of this chapter.

The main focus of this chapter is the Third Energy Package and the Clean Energy Package since they have shaped market coupling into what it is today and formed the foundation for the EU’s electricity market design and its entities.

1.1.1 The Third Energy Package (2009)

The main objective of the Third Energy Package was to pave the way for the completion of the EU’s Internal Energy Market (IEM). To achieve that, it included provisions on the unbundling of suppliers from network operators and strengthening cross-border TSO cooperation in Europe.

Each Energy Package is made up of directives and regulations. The main legal documents found in the Third Energy Package pertaining to the electricity sector include:

• Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC
• Regulation (EC) No 714/2009 of the European Parliament and of the Council of July 2009 on conditions for access to the network for cross-border exchanges in electricity.

Thus, the Third Energy Package pushed unbundling further and required TSOs to be fully independent from their parent companies (often incumbent vertically integrated utilities) through ownership unbundling (Articles 9 and 14, Directive 2009/72/EC). This implied the effective separation of appointed system operators from any generation or supply activities to prevent potential conflict of interest and ensure non-discriminatory access to electricity networks. To verify that the unbundling process has indeed been completed, an additional step required that TSOs be certified (Article 3, Regulation 714/2009).

In addition, the package mandated the independence of NRAs from governments and industries. It established ACER, as laid down in Regulation (EC) No 713/2009 of the European Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators. The Regulation tasked NRAs with developing framework guidelines, which are non-binding and serve as a basis for the process on network code and guideline development.

The Third Energy Package further established the European Network of Transmission System Operators for Electricity (ENTSO-E) as the coordinating body among European TSOs¹ (Fig. 1.2). Following the adoption of the framework guidelines drafted by ACER, ENTSO-E is tasked with drafting network codes and guidelines. The draft network codes and guidelines then each go through a comitology process before becoming legally binding in the entire EU. In line with this process, ACER provides its “reasoned opinion and recommendations” on each network code to ENTSO-E and submits it to the European Commission (Article 6, Regulation 713/2009). ACER is moreover tasked with monitoring network code implementation and analysing the progress in terms of facilitation of market integration, competition, and non-discrimination (Article 6(6), Regulation 713/2009).

Figure 1.3 outlines the Network Codes and Guidelines which have been developed following the framework of the Third Energy Package. Subsequent NCs and GLs are now being developed and amended based on the Clean Energy Package, in particular Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (so-called Electricity Regulation). It is worthwhile to mention that an important change brought by the IEM Regulation is that the European Commission may now either request ENTSOE or the EU DSO Entity in cooperation with ENTSO-E, to submit a proposal for a Network Code.

In the context of (physical) power market integration, the most relevant piece of legislation is the Capacity Allocation and Congestion Management (CACM) Guideline (Regulation 2015/1222), which will be addressed in more detail in the next Section.

Requirements on transparency were also strengthened and later further specified in Commission Regulation 543/2013 of 14 June 2013 on submission and publication of data in electricity markets (Regulation 543/2013). Also called Transparency Regulation (see Chap. 16), it forms the legal foundation for the establishment of <>

Fig. 1.2 Entities involved in the development of Network Codes. Source Author’s own illustration

Fig. 1.3 Overview of EU’s electricity network codes and guidelines (status October 2023). Source: author’s own illustration

1.1.2 Guideline on Capacity Allocation and Congestion Management (2015)

The CACM Guideline is concerned – as its name implies- with two crucial areas affecting market operation and its effective integration, the process of calculating and allocating available cross-border capacity for trade as well as the requirements guiding situations where market transactions cannot be accommodated given the technical constraints of the grid.

Regarding the first element, with the adoption of the CACM Guideline, market coupling became the mandatory means of allocating cross-zonal capacity in the day-ahead and intraday timeframes. Market coupling relies on either a so-called “price coupling algorithm” that matches day-ahead or intraday bids across borders while allocating cross-border capacity to enable it (see Chap. 6) or a continuous trading matching algorithm (see Chap. 7) for the intraday market (Article 37,

Regulation (EU) 2015/1222). Beyond that, the Guideline introduced the entity of the Nominated Electricity Market Operator (NEMO) (Arts. 4–7, Regulation (EU) 2015/1222). NEMOs are, among others, responsible for developing and operating the two algorithms (Article 36, Regulation (EU) 2015/1222) and—together with TSOs—carrying out market coupling. For this, NEMOs were tasked with a joint implementation of Market Coupling Operator (MCO) functions. The role and further responsibilities of NEMOs are introduced in Sect. 1.3.3 and explained in more detail in Chap. 2.

The Guideline further mandates that there is one Single Day-Ahead Coupling (SDAC) and one Single Intraday Coupling (SIDC). That is, all cross-zonal capacity must be allocated through SDAC or SIDC. It formulates a target model for capacity calculation, according to which the flow-based market coupling (FBMC) method should be used—for both day-ahead and intraday markets (Article 20, Regulation (EU) 2015/1222).

Exceptions for a method based on coordinated net transfer capacity (NTC) calculation are available provided the TSOs can demonstrate that the application of FBMC method would not be more efficient compared to the coordinated NTC method (Article 20(7), Regulation (EU) 2015/1222).

The stepwise implementation approach since 2015 has led to first the introduction of FBMC in Central Western Europe (CWE), including Austria, Belgium, France, Germany, and the Netherlands. On 8 June 2022, FBMC went live in the Core Capacity Calculation region, spanning the largest area of the EU. For an analysis of the effects see Chap. 11.

Concerning the second element, the CACM Guideline holds provisions on three means of congestion management:

• redispatch and countertrade (short-term, within a day)
• cross-zonal capacity calculation (short-term, two day-ahead to day-ahead)
• bidding zone review (mid- to long-term, lead time of a few years).

The CACM Guideline lays the groundwork for the review process of bidding zone configurations (Article 32, Regulation (EU) 2015/1222) that would ideally enable a way to tackle structural congestion that exacerbates a misalignment between the (nodal) physics of the grid and the zonal markets based on a copperplate assumption. See Sect. 1.2.1 for a description of bidding zones.

In the context of this handbook, we focus on cross-zonal capacity calculation and allocation (further detailed in Chap. 3).

The EU regulation creates a framework for the so-called “target model” of the internal electricity market, which relies on the zonal model, SDAC, SIDC, and further implementation of FBMC—all meant to facilitate a common market with efficient price formation. In the depicted target model for market coupling, TSOs provide cross-zonal capacities and NEMOs operate the market:

• The starting point on the capacity calculation side is the determination of the Capacity Calculation Regions (CCRs, Fig. 1.4) (Article 15, Regulation (EU) 2015/1222). The CCRs then serve as the defined geographical areas within which TSOs first develop a methodology, implement it, and then compute cross zonal capacities in a coordinated fashion across a set of bidding zone borders following the previously developed methodology.
• The starting point on the capacity allocation side is the designation of NEMOs. Following the establishment of NEMOs, the MCO plan was put in place. This plan serves as the basis for the cooperation of NEMOs in carrying out SDAC and SIDC and ensuring that the results of the calculation are shared among all power exchanges in a non-discriminatory fashion (Recital 5, Regulation (EU) 2015/1222). With the governance in place, NEMOs were required to draft a set of methodologies fundamental to market coupling (e.g. on the algorithms for SDAC and SIDC, minimum and maximum prices, gate opening and closure time of cross-zonal intraday markets, etc.).

A Capacity Calculation Region (CCR) is a geographical region in which TSOs cooperate to compute cross-zonal transmission capacities. A CCR is defined as a set of bidding zone borders (note: not bidding zones or TSO control areas). Hence, one bidding zone or TSO can be a member of several CCRs, while each bidding zone border is associated with only one CCR. See Chap. 3 for more details.

Fig. 1.4 Capacity Calculation Regions in Europe. Source Author’s own illustration

1.1.3 The Clean Energy for All Europeans Package (2019)

The Clean Energy Package (CEP) consists of several legislative documents, of which two are most relevant in terms of giving another layer of definition to the European internal market for electricity:

• Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (so-called “Electricity Regulation”).
• Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (so-called “Electricity Directive”).

The revised Electricity Regulation (2019/943) contains crucial provisions pertaining to the integration of the European electricity market. This regulation introduced the “70% minRAM rule”, which requires TSOs to provide at least 70% of the remaining available margin (RAM) capacity for cross-zonal trade (Article 16, Regulation 2019/943). The Regulation cites “uncoordinated curtailment of interconnector capacities” that can significantly limit cross-border trade as well as insufficient transparency towards market participants as the reason for the introduction of the 70% criterion (Recital (27) Regulation 2019/943). It thus discourages TSOs from using cross-border capacities to solve internal congestion thus prioritizing internal exchanges over cross-border ones (Article 16(8), Regulation 2019/943).

The adoption of this rule has created a lot of debate where one of the arguments against it were centred about the arbitrary nature of the value of 70%. Additionally, according to ENTSO-E Market Report 2023 (ENTSO-E, 2023), ENTSO-E continues to question whether a general minimum cross-zonal trading margin is appropriate for enhancing European market integration. While ENTSO-E supports the general optimization of the use of trading capacities, the organization highlights that further analysis on the economic and technical impact of the 70% rule is needed, with a focus on system security, economic efficiency, and decarbonization targets.

The CEP provides for two ways of (temporarily) derogating from the 70% rule:

• Until 2026, TSOs who cannot cope with providing 70% due to internal, structural congestion, may develop an Action Plan. This Action Plan must list measures on how to overcome these internal congestions and must contain a linear trajectory reaching 70% by 2026 (defining a ramp from the time of adoption of the Action Plan to 2026).
• Next to Action Plans, temporary derogations from the 70% rule may be granted by NRAs for individual periods not exceeding one year in situations where the TSO can demonstrate that the application of the rule would endanger operational security. Targeting short-term obstacles that prevent TSOs from providing 70%, derogations must be consulted with other NRAs before they can be approved and oblige the TSO to develop a methodology and projects to achieve a long-term solution (Article 16(9) Regulation 2019/943).

NRAs are responsible for assessing the compliance of their TSO(s) with the 70% rule. Not being able to provide 70% (or any relevant value based on the linear trajectory after adopting an Action Plan) can trigger a discussion on bidding zone reconfiguration.

With the aim to specify further how the 70% rule is to be interpreted and applied, ACER issued a recommendation detailing the application of the rule in August 2019. In this recommendation, the term “minimum margin available for cross-zonal trade” (minMACZT) was introduced and serves as the “yardstick” for assessing whether the rule has been complied with.

Even though it is not explicitly stated in the regulation or in ACER’s recommendation, the (unofficial and) applicable timeframe for the 70% rule is (currently) the day-ahead timeframe.

In addition, the CEP introduced the following changes:

It imposed additional provisions guiding the bidding zone review (BZR) process (Article 14, Regulation 2019/943), such as obliging ENTSO-E to report on structural congestion, its location and frequency every 3 years (Article 14(2)), obliging “all relevant TSOs” to provide a proposal for a methodology for a BZR by 5 October 2019 (Article 14(5)). Note that these are ultimately Member States that decide whether the proposed adjustment should be progressed, or the present configuration maintained.

Regulation 2019/943 (Arts. 34–43) introduced the role of Regional Coordination Centres (RCCs) to facilitate regional cooperation among TSOs. It defined their main tasks, including coordinated capacity calculation and security analyses as well as creation of common grid models (Article 37). RCCs will be described in more detail in Sect. 1.3.2.

Finally, it laid the foundation for the establishment of System Operation Regions (SORs) in Article 36 of the Electricity Regulation within which RCCs perform their tasks. Note that SORs were defined several years later in ACER’s Decision 5/2022 to include TSOs “that have been designated or assigned with responsibilities which are relevant for system operation, such as, but not limited to: calculation of capacity, assessment of needed remedial actions to ensure security of the whole system, coordination of all the outages” (Article 3, Annex I, ACER, 2022a). The SORs defined in the ACER Decision are shown in Fig. 1.5.

1.2 Geographical Scope of the European Integrated Market Design

1.2.1 Bidding Zones

Geographically, the electricity market in the EU is based on the so-called “zonal model”. The zonal model implies that there is one single price per bidding zone and market time unit (MTU). At the same time, the grid is considered a copperplate, i.e. no congestion is assumed to occur within the bidding zone but only between them.

A bidding zone is commonly defined as the geographic (grid) area within which trade of electricity is not constrained by any capacity limitations. This means that a zonal model is a rough approximation of the actual power grid, which requires multiple assumptions. At the time of writing, bidding zone borders predominantly coincide with the control area borders of TSOs and/or member states (with the notable exceptions of Norway, Sweden, and Italy, as is shown in Fig. 1.6).

Fig. 1.5 System operations regions in Europe. Source: Author’s own illustration

Capacity does not need to be allocated within a bidding zone whereas bidding zones are coupled via market coupling. The coupling happens via allocation of cross-zonal capacity available for power to be traded across bidding zones. Cross-zonal capacities determine how much trade can happen between bidding zones. If cross-zonal capacity is abundant, price convergence is going to be achieved, that is, two or more bidding zone would have the same market price. In contrast, price divergence generally increases with limited levels of cross-zonal capacities.

Market coupling ensures that the prices between bidding zones are coupled – either through auctions or continuous trading. Thus, market coupling reflects possible congestion between bidding zones. Hence, the bidding zone delineation determines how efficiently congestion is addressed through market-based allocation.

Note that several other power systems (e.g. most of the US, Australia) use the nodal market model to manage congestion. A nodal approach relies on a detailed model of the physical grid whereas the market clearing is done at substation level.

Fig. 1.6 Bidding zones in the EU and Norway. Source: Author’s own illustration

It thus represents physical properties of the individual components as well as laws of physics governing the flows in a meshed AC grid. Consequently, capacity allocation is done on all lines going in and out of each node. The result of this market model is different prices at each node affected by congestion.

The zonal vs. nodal approach for Europe has been subject of years of debate with proponents and opponents on both sides. It became particularly acute due to increasing instances of internal congestion within bidding zones, e.g. due to a simultaneous infeed of large generation volumes from variable renewables in a single grid area. As a result, the market outcome and market efficiency may be weakened as at least some of the trades may not be feasible and would require the TSO to intervene by redispatching (i.e. changing the dispatch) of some assets to relieve congestion.

From the bidding zone external perspective, a telling sign of internal congestion is the presence of so-called loop or transit flows. In the first case, generation in country A that is also consumed in country A flows through country B. In the second case, generation in country A is consumed in country B but to get there it flows through country C. Such a situation is problematic as it may lead to congestion in a country that is not involved in the trade in the first place. For instance, up until October 2018, Germany and Austria formed part of a single bidding zone.

Frequent transit flows through their Eastern European neighbours exacerbating the local grid situation were cited as the main reason for the bidding zone split of the two countries, which introduced limits to their cross-border exchanges (e.g. Hurta et al., 2022).

The main argument for the nodal approach appears to be better alignment with the reality of the grid and thus its ability to price congestion in the market prices. Some of the arguments often mentioned against it in the European context is a high computational complexity, unresolved governance issues, liquidity problems of nodal markets, as well as low political acceptance of having different prices within the same country.

Although there remains majority support for keeping the zonal model, the EU regulation provides for mechanisms to ensure that overall market efficiency is preserved while structural congestion is addressed. For this purpose, the CACM Guideline and the CEP defined a bidding zone review (BZR) process (Arts. 32–34 Regulation (EU) 2015/1222), meaning that the current bidding zone delineation is not set in stone. Based on provisions in the CACM Guideline, the participating TSOs are required to formulate a methodology and assumptions for the review process. In the second step and after conducting the comparison of the status quo with alternative configurations, they are to publish a consultation and submit a joint proposal to the participating Member States (Article 32, Regulation (EU) 2015/1222). The CACM Guideline further includes the minimum set of assessment criteria such as change in operational security, overall market efficiency as well as bidding zone stability and robustness over time (Article 33, Regulation (EU) 2015/1222). Within this process, the bidding zone configuration review is completed every couple of years and can be launched by ACER, NRAs, TSOs themselves, or a Member State (Article 32(1)). Finally, the current configuration is to be assessed by ACER every three years based on the technical and market reports drafted by ENTSO-E.

In its latest related Decision 11/2022 ACER proposed alternative bidding zone configurations for Germany, France, Italy, the Netherlands, and Sweden (Annex I, ACER, 2022b). The publication of the BZR is expected in summer 2024.

1.2.2 Market Timeframes, Market Coupling, and Price Formation

The CACM Guideline covers two timeframes: day-ahead and intraday. The dayahead market is the most liquid market in Europe and, as a result, provides the most robust price signal to buyers and sellers. The traded volumes in the intraday market have been increasing over the last decade in parallel with the growing penetration of variable renewable generation and the need to balance portfolio positions closer to real time. As Fig. 1.7 shows, the electricity market in fact consists of a number of interlinked markets in different timeframes, from long-term to real time. Note that forward, as well as balancing, markets are out of scope of this book.

Fig. 1.7 Sequence of market timeframes. The focus of this chapter, day-ahead and intraday markets and the respective capacity calculation processes are marked in teal. Source: author’s own illustration

In the day-ahead timeframe:

• The allocation of cross-zonal capacities is performed in one pan-European auction. This auction is held at 12:00 CET D-1 (hence the name “day-ahead”) daily and determines the day-ahead clearing prices for all participating bidding zones for all 24 h of the upcoming day from 0:00 to 24:00. That is, the market time unit (MTU) in the day-ahead market is equal to one hour defining the shortest time unit for which a market price is determined. Note that there is only one single clearing price per bidding zone and MTU—there are no side payments or other differentiation between the price that sellers receive, and the price buyers pay (Article 42, Regulation (EU) 2015/1222).
• Single-day-ahead coupling (SDAC) has been introduced as a mechanism to achieve market price setting and simultaneous capacity allocation for all coupled bidding zones thus maximizing social welfare across the EU (and Norway) (Article 2(26), Regulation (EU) 2015/1222). For this, it uses a so-called price coupling algorithm (EUPHEMIA) whose objective function is to maximize economic surplus (Article 38, Regulation (EU) 2015/1222). All the buyer and seller bids submitted by the gate closure time at 12:00 CET D-1 form part of a common merit order—as long as sufficient cross-border capacity is available. In this regard, social welfare can be broken down in three components: (1) producer surplus, (2) consumer surplus, and (3) congestion income. The latter is calculated from the price difference between two zones generated by the congestion between them and its volume, which is meant to facilitate TSOs’ investment in improved interconnection. When determining the clearing prices in SDAC, 1 Framework of Market Coupling 17 marginal pricing rule is applied, i.e. the marginal production/seller bid sets the price (i.e. the bid that is just needed to cover demand at a given price).

Fig. 1.8 Sequence of market coupling timeframes. Source: author’s own illustration

In the intraday timeframe:

• Single Intraday Coupling (SIDC) was similarly introduced by the CACM Guideline (Article 2(27)) and refers to the process during which bids are matched continuously and capacity is allocated simultaneously while observing cross-border constraints. While SDAC is based on one pan-EU auction with marginal pricing, SIDC is (for now solely) based on continuous trading with direct matching (known as Cross-Border Intraday, XBID). In contrast to auctions, continuous trading matches bids and offers constantly and instantly, provided that a matching set of bids and offers are available and, if the bids and offers originate from two different bidding zones, sufficient cross-zonal capacity is available. This also means that—in contrast to SDAC—no optimization takes place in the continuous market and, as a consequence, the pricing rule is pay-as-bid and there is not one single clearing price per bidding zone. Note that, in continuous trading, allocated cross-zonal capacity does not receive any congestion income. Instead, a power trader sees only allowed bids that can be accommodated based on available cross-zonal capacities. For instance, in a situation where all capacity was allocated to the day-ahead market for export, only capacity in the import direction would be available in the intraday market.
• To address the missing congestion income in SIDC, the CACM Guideline requires a methodology on intraday cross-zonal capacity pricing (Article 55). This methodology was adopted by ACER in 2019 and foresees the introduction of three intraday (implicit) auctions (IDAs) with an MTU of 15 min.2 These three auctions are to take place at 15:00 CET D-1, 22:00 CET D-1, and 10:00 CET D (for the second half of day D, see Fig. 1.8). To conduct these auctions, continuous trading is temporarily on hold to avoid double allocation of crosszonal capacity. At the time of writing, the go-live of the three IDAs is planned for Q2 2024.
• The gate closure times for national versus cross-border intraday markets differ. Currently, the gate closure time for cross-zonal trade in SIDC is 60 min before delivery (H-1). In some bidding zones, gate closure for bidding zone internal intraday trade differs nationally and is between 30 and 5 min before delivery.
• Additionally, the CACM Guideline offers a vehicle for allocating cross-zonal capacity in the intraday timeframe explicitly. Pursuant to its Article 64, adjacent TSOs can submit a proposal for explicit allocation of cross-zonal capacity in the intraday timeframe to the relevant NRAs for approval. Such an arrangement refers to a specific border, should be temporary and gradually phased out.

The CACM Guideline allows the use of two methods for capacity calculation that are aimed at maximizing transfer capacity available for trade while observing operational security constraints:

Coordinated net transfer capacity approach (CNTC) (primarily for regions with “less interdependent” cross-zonal capacity, Recital 7, Regulation (EU) 2015/ 1222)

Flow-based approach (FB), which is based on a more detailed representation of the grid by considering power transfer distribution factors and available margins on critical network elements (CNEs) thus “expanding the envelope” of the available cross-border capacity. FBMC is part of the EU Target Model and thus should ultimately substitute CNTC.

Since 2022, all borders within Core CCR use FBMC (see also Chap. 11) whereas capacity is calculated using CNTC in the rest of SDAC. Currently, SDAC allows for a combined NTC and flow-based allocation (“hybrid coupling”). In contrast, SIDC so far only allows allocation of NTCs. However, the CACM Guideline foresees flow-based allocation also in SIDC. An interested reader is invited to see more details on the two approaches in Chap. 3.

1.3 Key Enablers of European Electricity Market Integration

1.3.1 Transmission System Operators

TSOs, as regulated entities in charge of power system operation, were established through the process of unbundling that started in the 1990s (see also Fig. 1.9). They are regulated due to the fact that they hold the monopoly of access to the transmission grid. Hence, they are obliged to ensure non-discriminatory access to the transmission infrastructure to grid users. Activities of European TSOs are coordinated within ENTSO-E, which at the time of writing includes 40 TSOs from 36 countries, including outside the EU.

Fig. 1.9 Overview of ENTSO-E TSOs (observers are hatched). Source Author’s own illustration

Based on the System Operation Guideline (SOGL), two of the main responsibilities of (electricity) TSOs are:

• maintaining system operational security (the so-called N-1 principle) and, in the event of a contingency, returning to the normal state as soon as possible using remedial actions³ and
• ensuring security of supply, including security of (long-term) production and demand, of grid availability and of continuous grid balancing.

The processes of cross-zonal capacity calculation and consequent allocation in the day-ahead and intraday timeframes are within the realm of short-term operational planning. Short-term operational planning is, thus, essential to keep the power system running and prepare for challenges in real-time grid operations. Operational security is considered during cross-zonal capacity calculation, and market coupling is designed to make sure the load is covered by generation such that security of supply is guaranteed. At the same time, TSOs ensure that cross-zonal capacities are allocated in a non-discriminatory fashion – allowing access to the grid to those who are ready to pay for it.

TSOs are thus the main actors on the grid side of European market integration. They perform, with support from Regional Coordination Centres (RCCs, see Sect. 1.3.2 and also Chap. 5), the process of cross-zonal capacity calculation and provide the “scarce resource” (i.e. cross-zonal capacities) to market coupling.

Even though TSOs are not market players but rather market facilitators in the day-ahead and intraday markets, they are financially impacted by cross-zonal capacity allocation. From cross-zonal capacity allocation through (auction-based) market coupling, TSOs receive congestion income (see Chap. 10 for more details). This congestion income depends on the allocated flow and the clearing price difference on a given bidding zone border. Congestion income is to be used to (a) maintain firmness⁴ of allocated cross-zonal capacities, (b) develop grid infrastructure further, and (c) reduce grid tariffs (upon approval by the relevant NRA).

Beyond their role in SDAC and SIDC, TSOs are the main responsible for load–frequency control (LFC) in their respective LFC areas or blocks, that is, safeguarding that supply and demand are balanced by contracting and activating balancing reserves (Article 118, Regulation (EU) 2017/1485).

Beyond that, over the last five years, it has become evident that the growing volumes of energy resources connected on the distribution network level increase the need for TSOs’ coordination and data exchanges with DSOs as part of the so-called “active system management”.

1.3.2 Regional Coordination Centres

Regional Coordination Centres (RCCs) emerged from Region Security Coordinators (RSCs) introduced by the SOGL as an actor with functions complimentary to those of individual TSOs, namely for the matters of regional relevance. They are fully owned by TSOs; typically, by the TSOs with the intention of being serviced by the respective RCC(s). There are, however, a few TSOs who are shareholders of more than one RCC. Participation in at least one RCCs is mandatory for TSOs.

In the context of cross-zonal capacity calculation, the RCCs assume the role of the Coordinated Capacity Calculator (CCC) (Article 2(11), Regulation (EU) 2015/ 1222). This role implies that RCCs support the TSOs within a given CCR with the process of computing cross-zonal capacities while accounting for the TSOs’ operational security limits (Recital 20, Regulation 2019/943).

Beyond cross-zonal capacity calculation, RCCs are also responsible for coordinated security analysis, regional week-ahead, and day-ahead adequacy forecasts as well as regional outage planning, among others (Article 37, Regulation 2019/ 943). Note that RCCs do not play a role in the process of allocating cross-zonal capacities.

Figure 1.10 shows the current RCCs and their respective geographic coverage (based on their shareholder TSOs). Note that 50 Hertz is a shareholder of both TSCnet and Coreso; Terna of both Coreso and SEleNe CC; and Transelectrica of both TSCnet and SEleNe CC. In some CCRs, two RCCs perform the task of capacity calculation (e.g. Core and Italy North), either by splitting tasks or by following a rotational scheme of the main and a back-up CCC.

1.3.3 Nominated Electricity Market Operators

The entity of the Nominated Electricity Market Operator (NEMO) was created by the CACM Guideline (Articles 4–7). The main role of the NEMOs is to operate, maintain, and further develop SDAC and SIDC. However, they do not engage in the long-term timeframes (year-ahead and month-ahead) and are not obliged to operate both SDAC and SIDC simultaneously. That is, there are NEMOs-only active in the day-ahead timeframe but not in the intraday timeframe. Typically, NEMOs were power exchanges before seeking to become a NEMO.

After concluding a designation process with competent NRAs or ministries, a (power) exchange can become a NEMO (Arts. 4–5 Regulation (EU) 2015/1222).

Designations are timeframe-specific (day-ahead and/or intraday) and may be limited in time before re-designation is needed. Once an entity has been designated as a NEMO in (at least) one EU Member State, this NEMO can use the so-called “passport” to become active in any other EU member state. When “passporting” into another EU member state, the NEMO does not have to be (re-)designated locally and merely needs to notify its intention of wanting to be active to the relevant NRA or ministry. In this way, EU regulation ensures a level-playing field among NEMOs regardless of the country of operation.

Fig. 1.10 Regional Coordination Centres in Europe. Source Author’s own illustration

The CACM Guideline introduces competition between NEMOs or, more specifically, between the power exchange function of NEMOs. The rationale for this was to have NEMOs compete via the fees that they charge the market participants trading on their platforms. In member states with several competing NEMOs, so-called “Multi-NEMO Arrangements” (MNAs) have been agreed upon between the relevant TSOs and NEMOs and implemented. At the time of writing, MNAs are in place in Central Western Europe (Austria, Belgium, France, Germany, and the Netherlands), Poland, the Baltic countries, and the Nordic countries, including Norway. Figure 1.11 shows whether a Member State allows for competition among NEMOs or has a single monopoly NEMO. Note that some member states allow for competing NEMOs, but there is only one NEMO active and, at this stage, no MNA implemented. This is, for example, the case in Croatia and Slovenia. It is important to keep in mind that the NEMO status is required if cross-zonal capacity is to be allocated. Operating markets within a bidding zone (i.e. without allocating cross-zonal capacity), does not require the NEMO status (e.g. auctions within a bidding zone).

Fig. 1.11 NEMO market type in the EU and Norway. Source: Author’s own illustration

At the same time, in order to enable SDAC and SIDC, NEMOs take over the function of Market Coupling Operators (MCOs)⁵ that are in charge of using the MC algorithm for matching and allocating orders, of cooperating and sharing relevant information with TSOs in joint procedures (Article 7, Regulation (EU) 2015/1222) as well as with other NEMOs in a non-discriminatory fashion in order to jointly perform MCO functions (Recital 5 and Article 6(4), Regulation (EU) 2015/1222). For this, NEMOs must keep separate accounts for their power exchange and MCO functions (Article 6(1)(c)).

The competitive element between the power exchange function of a NEMO, and a NEMO’s obligation to collaborate with other NEMOs to jointly realize SDAC and SIDC, creates a conflict within one and the same company. Operating SDAC and SIDC is a regulated and monopolistic task (hence, the designation process to become a NEMO), because the “scarce resource” in market coupling (i.e. cross-zonal capacity) is to be allocated in a fair, transparent way that maximizes social welfare in the EU, based on a non-discriminatory process. To ensure this, NEMOs are forced to cooperate. On the other hand, NEMOs are power exchanges in competition with each other, mainly via their fees and areas of operation.

In the post-coupling process step (i.e. after-market coupling, either SDAC or SIDC), NEMOs are responsible for nominating cross-zonal capacity to the relevant TSOs (i.e. physical delivery). Central counter parties (CCPs) are responsible for financial shipping and clearing, including transferring congestion income to TSOs (Article 68(8), Regulation (EU) 2015/1222). This role is in practice often performed by NEMOs, however it can also be outsourced to third parties.

As mentioned above, NEMOs operating as a monopoly, and—so far—without any activity outside their respective Member State, are fully regulated. Competitive NEMOs operating in the same Member State together with other NEMOs are both a partner to work together with but also as a competitor. This situation was addressed in ACER’s proposal for a revision of the CACM Guideline (so called “CACM 2.0”), which was published and submitted to the European Commission in 2022.

ACER maintains an overview on its website with the designated, passporting, and active NEMOs per EU Member State and Norway. This overview distinguishes between day-ahead and intraday timeframes. Also, the All NEMO Committee keeps an overview of which NEMO is designated in which member state on its website (see Fig. 1.12).

1.4 Current and Upcoming Developments and the Future of Market Coupling

During the energy crisis of 2022 provoked by the war in Ukraine and the shortages of natural gas, the coupled European electricity markets were put through a major test. Low availability of nuclear power generation in France and negative weather effects during an exceptionally hot summer contributed to exacerbating the already complicated situation. These events raised serious questions about the fundamental value of European electricity market integration and whether the market design as it is known today was still fit for purpose.

Fig. 1.12 Number of NEMOs operating in each country; per timeframe (Day-ahead and Intraday). Source: Author’s own illustration

Among other challenges, the crisis led to the reduction of cross-border capacities in some Member States to reduce the impact of extreme prices, several instances of hitting the price ceiling and thus increase of maximum market prices and the introduction of several emergency measures to tackle price hikes. Despite multiple critical voices and drastic proposals, the value of cross-border cooperation and coupled electricity markets as well as their crucial role in averting the worst effects of the crisis was recognized by stakeholders across the board⁶. This is reflected in the current proposal for Electricity Market Design Reform⁷, which preserves current market design and the main pillars of the European electricity market functioning. The adoption of the final reform is expected at the beginning of 2024.

Beyond that, market coupling expected is evolved further in 2024–2027 in a number of important ways.

In SDAC, the most important developments concern the introduction of the 15- min MTU, flow-based allocation in Nordic CCR, Advanced Hybrid Coupling as well as the merger of Core and Italy North CCRs.

Currently, the cross-zonal markets work on an hourly granularity, while several national markets already employ 15-min granularity in XBID. The introduction of the 15-min MTU² in cross-zonal markets results is meant to accommodate more dynamic (and volatile) generation and consumption patterns and allow for more flexible trading. At the same time, higher granularity is expected to put a strain of EUPHEMIA while some implementation challenges still exist with regard to accommodating multiple-MTU bids, such as exclusive or linked block bids. The go-live of the 15-min MTU is expected for Q1 2025.

The introduction of flow-based allocation in Nordic CCR is motivated by its (generally) superior results compared to CNTC, particularly in highly meshed grids, delivering a larger solution domain for the market coupling algorithm. The implementation is expected in late 2024 at the earliest.

A major development is the planned merger of Core and Italy North CCRs (into what is provisionally called “Central Europe” CCR). The new CCR would combine the highly meshed grid of Northern Italy and that of Core, resulting in significant efficiency gains in cross-zonal allocation between France, Germany, Austria, Slovenia, and Italy. In this context, it is still being discussed how to improve the consideration of Swiss borders, since Switzerland would be strongly affected by the power flows computed in the new CCR, in which it would represent a gap for the optimization algorithm. This merger is foreseen to happen after 2026.

Consolidating CCRs, i.e. having fewer and larger CCRs, has been recognized as one of the ways to boost the efficiency of the European electricity market. An important complementary measure is to improve the interaction between CCRs.

Advanced hybrid coupling (AHC) involves consideration of the external borders of a CCR more similarly to internal ones, such that cross-CCR flows can be optimized to a certain extent. AHC is particularly relevant for the borders with HVDC interconnectors between Core and Nordic CCRs. For reference, the current solution is called Simple Hybrid Coupling, in which a forecasted flow across an HVDC interconnector is considered as a load (or generator, for imports) at the border. As a result, rather than being optimized, it is a fixed input. Currently, the expected go-live is set to mid-2025, but is highly dependent on the timely go-live of previous implementations. Further details can be found in Chap. 3.

In SIDC, the most relevant developments include the introduction of Intraday Auctions and flow-based allocation (currently only available in day-ahead), resulting in the intraday market becoming more similar to the current day-ahead market.

Three Intraday Auctions (IDAs) will take place, at 15:00 D-1, 22:00 D-1, and 10:00 D, lasting 30 min, during which continuous trading will be suspended. Important reasons for the introduction of IDAs are the pricing cross-zonal capacity and allowing TSOs to collect congestion income. Both elements are absent in the current XBID solution. IDAs will go-live on a 15-min MTU granularity, expected in Q2 2024.

Similarly, to the introduction of flow-based in Nordic CCR for the DA market mentioned above, FB allocation in intraday is expected to result in higher social welfare in Europe. Currently, the go-live is expected after 2025.

The development of offshore hybrid systems also introduce a new layer of complexity in terms of how they fit into a bidding zone model and how the 70% rule might apply to so-called offshore bidding zones.

Another project under development, with lower impact on the markets yet very important for reasons of operational security is the Regional Operational Security Coordination (ROSC). This encompasses a series of operational security assessments and sessions to coordinate the dispatch of remedial actions needed to relieve grid congestion. ROSC is aimed at increasing the operational security of the European grid and at distributing the costs of the remedial actions applied more fairly. At the moment, ROSC is planned for implementation at the end of 2025.

Finally, market integration and coupling does not stop with short-term wholesale markets. Increasing amounts of variable renewable generation are being progressively integrated in the energy system, while the supply of flexibility is relatively limited. In this context, system balancing is becoming ever more challenging, and cross-border cooperation ever more essential for European power system stability. These developments already created the impetus for TSOs to cooperate for imbalance netting and joint procurement of Frequency Containment Reserve (FCR), as well as to create European balancing energy platforms (PICASSO, MARI, TERRE). The latter has been mandated by the European Balancing Guideline and the roadmaps for their go-live and TSO accessions were formulated. The next stepping stone for the integration of the balancing market is the regional procurement of balancing capacity, based on the methodologies approved by ACER in July 2023 (ACER, 2023a). These methodologies, including harmonized market-based allocation of cross-zonal capacity, are expected to be jointly implemented by ENTSO-E, TSOs, and RCCs within two years.

About the author of this chapter

Dr. Ksenia Tolstrup is a Principal at Magnus Energy. She co-leads Magnus Energy’s Technical Advisory practice and is heavily involved in several projects related to electricity market and regulatory analysis, balancing, flexibility, and hydrogen transition. Ksenia has almost a decade of experience in the energy sector—in consulting and in research. As a Senior Research Engineer at AIT Austrian Institute of Technology she focused on the analysis and simulation of electricity markets in all timeframes, from forward to balancing and congestion management, led multiple national and international projects and authored over 30 top-journal articles, conference papers and project reports. In 2021 she obtained her PhD cum laude in energy economics from Delft University of Technology.

About the editors of the book

Dr. André Estermann has more than 20 years of experience in energy sector and currently leads at the German TSO 50Hertz Transmission GmbH a team in system operations responsible for cross-border activities. Furthermore, he is the TSO Chairman of the Market Coupling (MCSC), in the Single Day-Ahead Coupling (SDAC) and Single Intraday Coupling (SIDC) Steering Committees. André holds a Ph.D. in economics at the European University Viadrina Frankfurt, Oder and received an MBA at the University of Southampton, UK. Moreover, he holds a degree in international politics from the University of Potsdam.

Marius Schrade is an Expert in European Market Coupling projects at 50Hertz Transmission GmbH, one of the four transmission system operators in Germany, within the System Operations Concepts and Analytics department since 2019. At 50Hertz, he started his career as project lead for the integration of the German–Czech and German–Polish border into Single Day-Ahead Coupling, which was completed in 2021. Since then, he focuses on cooperation between TSOs and NEMOs in the Market Coupling Steering Committee where he also lead a task force on day-ahead simulation software. Marius holds a Double Degree in European Economics from the Universities of Maastricht in The Netherlands and
Louvain-La-Neuve in Belgium.

Louise Anderson currently works with Hitachi Energy as an Assistant Vice President in the Government and Institutional Relations department. Previously, Louise spent 5 years managing the World Economic Forum’s Electricity Industry Community, while also launching the WEF’s global initiative on Accelerating Industrial Clusters. Louise started her career working in a power plant before moving to work for EirGrid, Ireland’s Transmission System Operator, managing high voltage asset outage planning until 2014. Louise also spent some time in Belgium working for ENTSO-E on different aspects of the implementation of the CACM Guideline. Louise has a bachelor’s degree in Mechatronics and an MBA specializing in International Business.

Bibliography

Association for the cooperation of the European transmission system operators (ENTSO-E). (2023). Market Report 2023. https://eepublicdownloads.blob.core.windows.net/public-cdn-container/clean-documents/nc-tasks/ENTSO-E_Market_Report_2023.pdf. Accessed June 2024.

European Commission. (2013). Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission and publication of data in electricity markets and amending Annex I to Regulation (EC) No 714/2009 of the European Parliament and of the Council. OJ L 163, 15.6.2013, pp. 1–12. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32013R0543

European Commission. (2015). Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion management. OJ L 197, 25.7.2015, pp. 24–72. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32015R1222

European Commission. (2017). Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation. OJ L 220, 25.8.2017, pp. 1–120. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32017R1485

European Parliament and European Council. (2009a). Directive (EU) 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market for electricity and repealing Directive 2003/54/EC. OJ L 211/55, 14.8.2009. https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32009L0072&from=BG

European Parliament and European Council. (2009b). Regulation (EC) No 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity. OJ L 211/55, 14.8.2009. https://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0015:0035:EN:PDF

European Parliament and European Council. (2019a). Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity. OJL 158, 14.6.2019, pp. 54–124. https://eurlex.europa.eu/legalcontent/EN/TXT/uri=CELEX%3A32019R0943&qid=1715683977934

European Parliament and European Council. (2019b). Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast). OJ L 158, 14.6.2019, pp. 125–199. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=celex%3A32019L0944

European Union Agency for the Cooperation of Energy Regulators (ACER). (2022a). Definition of System Operation Regions in accordance with Article 36 of the Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity, Decision. https://www.acer.europa.eu/sites/default/files/documents/Individual%20Decisions_annex/ACER%20Decision%2005-2022%20-%20Annex%20I%20-%20Definition%20of%20SORs_0.pdf

European Union Agency for the Cooperation of Energy Regulators (ACER). (2022b). Decision on the alternative bidding zone configurations to be considered in the bidding zone review process. Annex 1. List of alternative bidding zone configurations to be considered in the bidding zone review, Decision. https://www.acer.europa.eu/sites/default/files/documents/Individual%20Decisions_annex/ACER%20Decision%2011-2022%20on%20alternative%20BZ%20configurations%20-%20Annex%20I%20-%20rectified.pdf

European Union Agency for the Cooperation of Energy Regulators (ACER). (2023a). Decision No 11/2023 on the TSOs’ proposal for the harmonised cross-zonal capacity allocation methodology, Decision. https://acer.europa.eu/sites/default/files/documents/Individual%20Decisions/ACER_Decision_11-2023_on_Harmonised_Cross-Zonal_Capacity_Allocation_Methodology.pdf

European Union Agency for the Cooperation of Energy Regulators (ACER). (2023b). Security of EU electricity supply. https://acer.europa.eu/sites/default/files/documents/Publications/Security_of_EU_electricity_supply_2023.pdf

Hurta, A., Žilka, M., & Freiberg, F. (2022). Impact of the splitting of the German-Austrian electricity bidding zone on investment in a grid-scale battery energy storage system deployed for price arbitrage with gray and green power in Austrian and German day-ahead power markets. Energy Reports, 8, 12045–12062. https://doi.org/10.1016/j.egyr.2022.09.045

Poplavskaya, K. (2021). Balancing and redispatch: The next stepping stones in European electricity market integration: Improving the market design and the efficiency of the procurement of balancing and redispatch services (PhD thesis). https://doi.org/10.4233/uuid:fb8c99cc-24d6-4718-8986-95833ffc1f49

Notes

1. Note that ENTSO-E also includes non-EU members.
2. Note that national intraday auctions have been used in Austria, Belgium, France, Germany, Italy, the Netherlands, and Spain.
3. Pursuant to Article 2(13), Regulation (EU) 2015/1222, remedial actions refer to “any measure applied by a TSO or several TSOs, manually or automatically, in order to maintain operational security”, such as redispatching, countertrading, or topological actions.
4. According to Article 2(44) Regulation (EU) 2015/1222, firmness refers to “a guarantee that cross-zonal capacity rights will remain unchanged and that a compensation is paid if they are nevertheless changed”.
5. The CACM Guideline does in fact allow for the Commission, in cooperation with ACER, to “create or appoint” a single regulated MCO (Recital 15, Regulation (EU) 2015/1222), a provision which did produce a lot of debate between ACER and NEMOs.
6. A detailed analysis of the measures adopted during the crisis can be found in ACER (2023b)
7. Reform of electricity market design: Council and Parliament reach deal—Consilium (europa.eu)