Market Coupling

Market coupling can bring benefits to electricity producers. Obviously, electricity producers can benefit from a larger market for their generation capacity and different generation technologies. Increased use of implicit auctions (day-ahead markets) and continuous trading (intraday markets) across borders can increase liquidity and reduce volatility.² Moreover, access to cross-zonal trade in balancing services (Sect. 4.​10.​4) can help electricity producers to make better use of their flexible generation technologies.³

Market coupling can influence the bidding strategies of firms. It can increase the use of derivatives by reducing the cost of financial derivatives: market coupling increases liquidity and reduces spreads between the participating markets (Sect. 6.5). Financial instruments can also be used to replace physical flows (Chap. 12).

Market coupling can increase arbitrage. (a) Before market coupling, EU cross-border trade was mainly short-term arbitrage.⁴ (b) After market coupling, arbitrage is not limited to the day-ahead or intraday market. This is because access rights for long- and medium-term capacity allocations must be firm transmission capacity rights subject to the use-it-or-lose-it (UIOLI) principle or the use-it-or-sell-it (UIOSI) principle.⁵ Where transmission capacity rights sold in an explicit auction are subject to the UIOSI principle, the capacity is placed into an implicit auction should the holder fail to nominate any physical flows. The holder then receives the spread between the two markets (similar to the holder of financial transmission rights in the US). The fact that the holder can benefit from congestion financially can reduce the need for physical nominations and increase arbitrage.

Regardless of market coupling, balancing will still be carried out by TSOs within national transmission systems.⁶

The integration of national electricity markets would not be possible without cross-border interconnectors.⁷ The building of new interconnectors can give investment signals to electricity producers as price differences in the two price zones are likely to be reduced. In the higher price zone (with possibly too little generation capacity), prices are reduced and electricity producers have worse incentives to invest in generation installations. In the lower price zone (with possibly greater generation capacity), prices are increased and electricity producers are given better incentives to invest in generation installations. The building of interconnectors can thus increase both market integration and the generation imbalance between zones.⁸

One of the objectives of the Third Electricity Directive is to increase cross-border interconnection capacity. First, Member States are required to provide adequate economic incentives for the maintenance and construction of the necessary interconnection capacity.⁹ Second, transmission system operators must be required to comply with minimum standards for the maintenance and development of interconnection capacity.¹⁰ Third, transmission system operators must manage electricity flows on the system by considering exchanges with other interconnected systems.¹¹

On the other hand, the mere existence of interconnectors between two markets does not in itself mean market integration.

There is no cross-border trade without the co-operation of TSOs, that is, unless the TSO in the exporting control area allows a generation surplus and the TSO in the importing control area allows a corresponding generation deficit. TSOs manage cross-border flows by first calculating in a network model how big this surplus and deficit can be considering the technical constraints. The result of the calculation is a cross-border transmission capacity that can be offered to the market (for the methods, see Sects. 5.​3 and 5.​7).¹²

A cross-border trader needs transmission rights on the interconnector. In the past, cross-border trade was not possible unless traders bought transmission rights on the relevant interconnector directly from the capacity holder or on a transmission capacity auction. This did not ensure the optimal use of transmission capacity as congestion problems remained.

The purpose of market coupling is to allocate capacity by optimising the total economic surplus of the different coupled spot markets’ order books, while ensuring that the physical limits of the grid are respected. Particular market coupling mechanisms can thus be used to manage congestion problems and to determine the optimal direction, volume, and price of electricity flows between the markets.

In market coupling, co-operation between TSOs and power exchanges ensures, during every hour of operation, that all the available trading capacity is utilised with power flowing from the low-price area to the high-price area. Coupling can help to increase security of supply and reduce regional price differences without full integration of the markets. Existing electricity exchanges and TSOs have an incentive to promote market coupling as it does not require any structural changes in the market but enables the exchanges and TSOs to stay independent and continue their business.

There are various models for market coupling (Sect. 6.2). The agreed target design for day-ahead markets in Europe is price coupling (Sect. 6.3). The key rules are based on Regulation 714/2009, which replaced Regulation 1228/2003.¹³

The EU also has a target model for the allocation of transmission capacity. When the European Council set the target of 2014 for the completion of the internal electricity market in February 2011, the European Council asked regulators to contribute to a “European Energy Work Plan 2011–2014”. In July 2011, ACER therefore issued Draft Framework Guidelines on Capacity Allocation and Congestion Management for Electricity (CACM Framework Guidelines). The CACM Framework Guidelines identify four key elements for the design of the target model, namely: methods for calculating capacity and zone definition (either flow-based or available transfer capacity)¹⁴; forward markets for capacity allocation (a single platform for the allocation of long-term transmission rights—PTR and FTR—at European level)¹⁵; day-ahead capacity allocation (implicit auctions)¹⁶; and intraday capacity allocation (continuous implicit trading, direct explicit access as a transitional measure).¹⁷

The target model can only be implemented stepwise, “as the regulatory framework for electricity trade and the physical structure of the transmission grid are characterised by significant differences between Member States and regions”. Market coupling at the regional level may therefore be used as an intermediate step.¹⁸

The North-Western Europe (NWE) market coupling went live on 4 February 2014. NWE coupled the day-ahead markets across Central Western Europe (CWE), the UK, the Nordic countries, the Baltic countries, and the SwePol link between Sweden and Poland. NWE market coupling was therefore a significant achievement in the integration of European electricity markets (Sect. 6.4). NWE day-ahead market coupling uses the Price Coupling of Regions (PCR) solution. The full price coupling of the South-Western Europe (SWE) and NWE day-ahead electricity markets went live on 13 May 2014. On 19 November 2014, the 4M Market Coupling (4M MC) was launched. It prepares the way for the integration of the CEE region and the rest of Europe.

The CACM Regulation requires the designation of entities as NEMOs. The function of a NEMO is to perform the single day-ahead and/or intraday coupling. They are thus electricity exchanges.¹⁹

Subject to certain exceptions, a NEMO designated in one Member State has the right to offer day-ahead and intraday trading services with delivery in another Member State.²⁰ This means that the CACM Regulation increases competition by allowing power exchanges to compete within the same countries or bidding areas.

Each Member State and Norway must designate at least one NEMO within 4 months of the entry into force of the CACM Regulation. NEMOs shall be designated for an initial term of 4 years.²¹ The CACM Regulation also creates a governance framework for NEMOs.

The CACM Regulation defines MCO functions.²² However, there does not have to be any particular MCO (at least not in the short term). MCO functions are carried out by NEMOs jointly with other NEMOs. NEMOs must submit a plan that sets out how to jointly set up and perform the MCO functions not later than 8 months after the entry into force of the CACM Regulation.²³

According to the CACM Regulation, the joint performance of MCO functions “shall be based on the principle of non-discrimination and ensure that no NEMO can benefit from unjustified economic advantages through participation in MCO functions”.²⁴

If the co-operation between NEMOs fails, it is possible that the MCO functions will be taken over by ENTSO-E or another entity.²⁵

Table 6.1 shows the relationship between MCO functions (at the the European level), NEMOs (at the national level), and TSOs (at the national level).

A transmission capacity auction is “explicit” when transmission capacity and electricity are traded at two separate auctions.²⁶ Transmission capacity is normally auctioned in portions through annual, monthly and daily auctions.

In principle, explicit auctions are a simple method. In practice, however, there is a problem caused by lack of information. If transmission capacity and electricity are traded at two separate auctions, the price of one commodity cannot reflect the price of the other as closely as it could. This can lead to an inefficient utilisation of interconnectors.²⁷

An implicit auction provides a way to integrate electricity spot markets in two regions connected by an interconnector. A transmission capacity auction is “implicit” when the auctioning of transmission capacity is included in an electricity auction “implicitly”. Electricity buyers bid for electricity supplied by electricity generators from the other side of the interconnector and transmission capacity is included in the price. In other words, implicit auctioning reduces cross-border trade inefficiencies by internalising the arbitrage into the auction procedures of the power exchanges that are organising trade nationally.²⁸

First you need market data from the marketplaces in the connected markets. The flow on the interconnector is estimated on the basis of differences in bids. Electricity is expected to flow from the surplus area (low price area) to the deficit area (high price area). This flow is included in the market offering and made available to bidders. Implicit auctions can thus increase price convergence. The resulting prices reflect both the cost of electricity in each bidding area and the cost of congestion.

In practice, the coupling of markets that use implicit auctions means that market participants do not actually need to receive any cross-border capacity allocations. Instead, market participants can bid for generation or consumption in their own areas.²⁹

The existence of implicit auctions does not exclude the use of explicit auctions. Implicit auctions would not be possible, unless owners of interconnectors allocated transmission capacity to market participants. Transmission capacity can be allocated in explicit auctions before the implicit auctions.

Implicit auctions can be used either for market coupling or for market splitting. In market splitting, the implicit auction of transmission capacity is organised within the day-ahead electricity auction by one single power exchange.

Market splitting is caused by limited transmission capacity between the power exchange’s internal bidding areas. Because of limited transmission capacity, there can sometimes be different prices in different bidding areas. In other words, price convergence is not perfect, and there is a “split” between the markets.

However, market splitting is not the same thing as the separation of markets. Market splitting is a form of congestion management. It is used to level out price differences.³⁰ It increases the price in the low-price area and decrease the price in the high-price area. Market splitting is applied in the Nordic market³¹ and in the Iberian market between Portugal and Spain.³²

In market coupling, the implicit auction is organised in cooperation between two or more power exchanges. The exchanges are thus “coupled”.

Market coupling requires plenty of information. The necessary market information is provided by the participating exchanges. TSOs provide information about transmission capacity between the market areas. A central coupling algorithm delivers information about flows and prices in all market areas. This information can then be used in different ways depending on the way market coupling is implemented.

Market coupling can be implemented in various ways. One can distinguish between price market coupling, tight volume market coupling, and loose volume market coupling:

Regulation 714/2009 sets out the key rules at Community level. The purpose of Regulation 714/2009 is to: (a) provide directly applicable rules and principles; (b) set fair rules for cross-border exchanges in electricity; (c) establish a compensation mechanism for cross-border flows of electricity; and (d) set harmonised principles on cross-border transmission charges and the allocation of available capacities of interconnections between national transmission systems.³⁵

Fairness must be ensured by addressing network congestion problems with non-discriminatory market-based solutions.³⁶ The maximum capacity of the interconnections and/or the transmission networks affecting cross-border flows must be made available to market participants.³⁷ Congestion problems must “preferentially” be addressed by methods that do not involve a selection between the contracts of individual market participants (“non transaction-based methods”).³⁸ Capacity must be allocated to market participants for an operational period in an open, transparent, and non-discriminatory manner.³⁹ On the other hand, transactions that relieve congestion must never be denied.⁴⁰

The compensation mechanism is based on a number of rules. First, TSOs must receive compensation for costs incurred as a result of hosting cross-border flows of electricity on their networks,⁴¹ but revenues resulting from the allocation of interconnection must be used for certain purposes⁴² and the Commission decides on the amounts of compensation payments payable. Exemptions may be granted upon request for new interconnectors under certain circumstances.⁴³ Second, the compensation must be paid by the operators of national transmission systems from which cross-border flows originate and the systems where those flows end.⁴⁴ Third, the charges must not be distance-related, but the level of tariffs applied to producers and/or consumers should provide locational signals.⁴⁵ For this reason, there must not be any specific network charge on individual transactions for declared transits of electricity.⁴⁶ The level of the tariffs should nevertheless take into account the amount of network losses and congestion, including investment costs for infrastructure.⁴⁷ Fourth, compensation payments must be made on a regular basis with regard to a given period of time in the past.⁴⁸ Fifth, the Commission must adopt guidelines according to the principle of subsidiarity.⁴⁹ The Regulation and the guidelines are without prejudice to the rights of Member States to adopt detailed provisions.⁵⁰

The Commission’s guidelines are annexed to Regulation 1228/2003 and Regulation 714/2009.⁵¹ For purposes of market coupling, its most important provisions relate to congestion management methods. They must be market-based. Transmission capacity on an interconnector must be allocated by means of explicit (capacity) or implicit (capacity and energy) auctions, or a combination of explicit and implicit auctions. Continuous trading may be used for intraday trade.⁵²

The use of implicit allocation is the main rule cross-zonal capacity allocation in the day-ahead and intraday market timeframes according to the CACM Regulation.⁵³ Unless transitional arrangements apply, the method is implicit auctions on day-ahead markets and continuous implicit allocation on intraday markets.

Explicit allocation could be used as a transitional arrangement under the ENTSO-E Network Code that preceded the CACM Regulation.⁵⁴ The Network Code permitted system operators to use explicit allocation on those bidding zone borders where they are requested to do so by national regulatory authorities.⁵⁵ Explicit requests were not permitted for interconnections in other cases.⁵⁶

The CACM Regulation limits the use of explicit auctions as a transitional arrangement to intraday markets.⁵⁷

Explicit allocation is the main rule for long-term cross-zonal capacity allocation under ENTSO-E Network Code on Forward Capacity Allocation.⁵⁸

Congestion management mechanisms may need to allow for both short- and long-term transmission capacity allocation depending on competition conditions.⁵⁹ There are two permissible approaches for the calculation and allocation of long-term capacity: the coordinated net transmission capacity based approach and the flow-based approach.⁶⁰ Moreover, long-term capacity should be calculated and allocated at least for yearly and monthly timeframes.⁶¹

Each capacity allocation procedure must allocate a prescribed fraction of the available interconnection capacity plus any remaining capacity not previously allocated and any capacity released by capacity holders from previous allocations.⁶² The access rights for long- and medium-term allocations must be firm transmission capacity rights. They must be subject to the use-it-or-lose-it (UIOLI) or use-it-or-sell-it (UIOSI) principles at the time of nomination.⁶³

The main rule is that the highest value bids shall prevail. Capacity allocation may not discriminate between market participants that wish to use their rights to make use of bilateral supply contracts or to bid into power exchanges.⁶⁴ In principle, all potential market participants should be permitted to participate in the allocation process without restriction. However, the participation of some market players may be limited because of competition concerns.⁶⁵

In regions where forward financial electricity markets are well developed and have shown their efficiency, all interconnection capacity may be allocated through implicit auctioning.⁶⁶ Moreover, such regions may allocate all interconnection capacity through day-ahead allocation.⁶⁷

Although the starting point was that different congestion management methods have been used depending on the market, the ultimate goal of the Commission’s guidelines is forming “a truly integrated Internal European Electricity Market”. For this reason, the guidelines require “compatible congestion management procedures” and “compatible regional systems” in all existing regions.⁶⁸