Market coupling in the European Union Internal Electricity Market (IEM) refers to the integration of two or more electricity markets from different areas through an implicit cross-border allocation mechanism.




8 June 2022


Launch of Flow-Based Market Coupling in the Core region

17 December 2021


ACER Recommendation No 02/2021 of 17 December 2021 on reasoned proposals for amendments to the CACM Regulation proposes changes to a wide range of topics, including market coupling governance and operations

The target model for market coupling of the current regulation envisages implicit auctioning with a single price per bidding zone in the day-ahead timeframe and continuous trade with continuous capacity allocation in the intraday timeframe (ACER Recommendation No 02/2021 of 17 December 2021 on reasoned proposals for amendments to the CACM Regulation).

Market coupling, from the onset of the European energy regulatory agencies, was perceived as the key instrument for the integration of EU wholesale power markets (see, for example, ACER's annual report on its activities under REMIT in 2012).


Instead of explicitly auctioning the cross-border transmission capacities among the market participants, market coupling makes the capacities implicitly available on the power exchanges of the various areas.


Annual Report of the ACER and CEER on the Results of Monitoring the Internal Electricity and Gas Markets in 2016 (Electricity Wholesale Markets Volume) published in October 2017 mentions (p. 49) that cross-zonal capacity was used more efficiently in 2016 in the intraday timeframe on borders where the capacity was allocated by using implicit allocation methods (61% of efficiency) as opposed to explicit or other allocation methods (40%).

The role of the market coupling in the integration of the EU wholesale electricity markets has been prominently accentuated by the so-called Winter Energy Package of 30 November 2016.


Article 6
(1) of the European Commission's Proposal of 30 November 2016 for a Regulation of the European Parliament and of the Council on the internal market for electricity (recast,  COM(2016) 861 final) stipulates that:


Transmission System Operators (TSOs), and 


Nominated Electricity Market Operators (NEMOs);

 market coupling lower price higher price

jointly organise the management of the integrated day-ahead and intraday markets based on market coupling as set out in CACM Regulation.


The plain language description of the market coupling is that it consists in selling electricity together with interconnection capacity, instead of separately (Energy: New market design to pave the way for a new deal for consumers, the European Commission MEMO/15/5351, 15 July 2015).


The purpose of market coupling is to maximise the economic welfare of all players.


The mechanism aims to enable the free movement of electricity between the integrated markets.


Already in 2012 the following power regions and the following power exchanges were applying market coupling: Central Western Europe (EPEX Spot (German-Austrian and France), Belpex (Belgium) and APX-ENDEX (Netherlands)), Nordic region (Nord Pool Spot (Norway, Sweden, Finland, Denmark, Estonia, Lithuania)), Central-Eastern Europe (OTE (Czech Republic and Slovakia) and HUPX (Hungary)), South Western Europe (OMIE (Spain and Portugal)) and Central-South Europe (GME (Italy) and Borzen-BSP SouthPool (Slovenia)).


Commission Staff Working Document "Generation Adequacy in the internal electricity market - guidance on public interventions" (Accompanying the Communication from the Commission Delivering the internal electricity market and making the most of public intervention) released in November 2013 also underlined the fact that in the European Union the very large majority of EU Member States had their electricity markets coupled with at least one other Member State and that in Central West Europe, electricity markets were deeply connected through price coupling, this practice was expected to expand throughout the Union.


Pursuant to the said Commission Staff Working Document of November 2013, coupled markets imply that power flows out of a market when prices in a neighbouring market are higher, inversely, power will be imported when domestic prices are higher.


The traded volumes can constitute a multiple of the interconnection capacity available but physical flows will be limited to the available capacity on the given interconnectors.


Market coupling is perceived as a first step towards a fully integrated market allowing short and long term trading of energy, renewable energy sources (RES), balancing services and security of supply across borders.


Target model for the day-ahead timeframe is a European Price Coupling (EPC) which simultaneously determines volumes and prices in all relevant zones, based on the marginal pricing principle.


In case long term cross-zonal capacities are allocated implicitly via market coupling, the underlying products are by default Financial Transmission Rights Obligations (ACER and CEER, Draft Policy Paper on the Further Development of the EU Electricity Forward Market for Consultation, 1 June 2022, p. 23).


The two market time-frames are differentiated:

What is bidding zone 

- ’single day ahead coupling' (SDAC) meaning a coordinated electricity price setting and cross-zonal capacity allocation mechanism, which simultaneously matches orders from the day-ahead markets per bidding zone, respecting cross-zonal capacity and allocation constraints between bidding zones; and 

- 'single intraday coupling' (SIDC) meaning an implicit cross-zonal capacity allocation mechanism which collects orders for each bidding zone from wholesale market participants and matches them continuously into contracts to deliver electricity while respecting cross-zonal capacity and allocation constraints, and is available in the intraday market timeframe once the day-ahead market allocation process has taken place (Article 2(27) of the CACM Regulation: 'single intraday coupling' means the 'continuous process where collected orders are matched and cross-zonal capacity is allocated simultaneously for different bidding zones in the intraday market').


As the Commission Staff Working Document of 13 April 2016 (Accompanying the Report from the Commission, Interim Report of the Sector Inquiry on Capacity Mechanisms {C(2016) 2107 final}, SWD(2016) 119 final, p. 134, 135) observes, market coupling is an effective way of ensuring the most efficient use of interconnection, but creates a certain challenge for enabling foreign participation in capacity mechanisms in Europe, because interconnectors have no influence over which direction power flows between markets, and individual capacity providers in a coupled market have very little influence on which direction power flows.


However, market coupling eliminates the remaining "wrong-way flows" (a 'wrong-way flow' hour occur when the final net nomination on a given border takes place from the higher to the lower price zone, with a price difference of at least one euro/MWh).


This has been applied firstly for the Spanish-French, Austrian-Italian, French-Italian and Hungarian-Romanian borders, following the relevant extension of market coupling.


European Commission in the Annex 2 to the Third Report on the State of the Energy Union of 24 November 2017 refers to 30 out of the 42 EU borders participating in day-ahead market coupling - this included Austria, Belgium, the Czech Republic, Germany, Denmark, Estonia, Spain, Finland, France, Hungary, Italy, Lithuania, Latvia, the Netherlands, Norway, Poland, Portugal, Romania, Sweden, Slovenia, Slovakia and Great Britain (remaining European borders were at that time still applying explicit day-ahead auctions). 



See also:


Joint Allocation Office


Market Coupling Operator (MCO) function

With market coupling, it is not possible for a generator or demand response provider in a neighbouring zone to guarantee that its power will flow to consumers in another bidding zone.


Under market conditions, power will flow to the bidding zone which offers the highest electricity price.

A brief overview of early market coupling developments for the European day-ahead and intra-day market



Important milestones for the development of the European market coupling were:

- in May 2014 Southwest Europe (SWE) joined Northwest Europe (NWE) day-ahead coupling and renamed the project to Multi-Regional Coupling (MRC), giving an important step forward towards the European Union Internal Electricity Market.


- in November 2014, the 4M Market Coupling Project implemented DA ATC-based price coupling covering Czech–Slovak–Hungarian plus Romanian market areas based also on the Price Coupling of Regions (PCR) solution, to facilitate the integration of the MRC project with the 4M project,


- on 24 February 2015, Italian borders (Italian–Austrian, Italian–French and Italian–Slovenian) have been coupled with the MRC,


- on 21 May 2015, the Central-Western European Region implemented flow-based capacity calculation (flow based market coupling - FBMC) for the first time in Europe.


North-Western Europe (NWE) Price Coupling was a project initiated by the Transmission System Operators and Power Exchanges of the countries in North-Western Europe. The 17 partners of this project comprised APX, Belpex, EPEX SPOT and Nord Pool Spot from the Power Exchanges' side; 50Hertz, Amprion, Creos, Elia,, Fingrid, National Grid, RTE, Statnett, Svenska Kraftnät, TenneT TSO B.V. (Netherlands), TenneT TSO GmbH (Germany) and TransnetBW from the TSO side. The cooperation was dedicated to the price coupling of the day-ahead wholesale electricity markets in this region, increasing the efficient allocation of interconnection capacities of the involved countries and optimising the overall social welfare. A single algorithm, calculating simultaneously the electricity market prices, net positions and flows on interconnectors between bidding zones was used, based on implicit auctions and facilitated through the Price Coupling of Regions solution.


Price Coupling of Regions (PCR) was the initiative of seven European Power Exchanges (APX, Belpex, EPEX SPOT, GME, Nord Pool Spot, OMIE and OTE), to develop a single price coupling solution to be used to calculate electricity prices across Europe and allocate cross-border capacity on a day-ahead basis. This was crucial to achieve the overall EU target of a harmonised European electricity market. The integrated European electricity market was expected to increase liquidity, efficiency and social welfare. PCR was open to other European Power Exchanges wishing to join. 


South-Western Europe (SWE) Price Coupling Project was a joint project between the French, Spanish and Portuguese TSOs, RTE, REE, REN, and the Power Exchanges OMIE in Spain and Portugal and EPEX SPOT operating the French market. This project aimed to define the pre-coupling, post coupling and exceptional situations processes that were necessary to allow the implementation of price coupling between NWE region and the Iberian day-ahead markets.


With FBMC, the remaining margins available on critical branches of the network are allocated to where they are most valuable.


In theory, FBMC should render more tradable capacities (i.e. minimum and maximum net positions) compared to the available transmission capacity (ATC) method (ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity Market in 2015, September 2016, p. 44).


ACER/CEER Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2014, November 2015 (p. 15) referred to folowing dates in the context of the market coupling implementation in the EU:


- 4 February 2014 - the go-live of the North-West Europe (NWE) day-ahead market coupling project,


- 13 May 2014 - the NWE extension to the Iberian market,


- 19 November 2014 - the extension of market coupling of the Czech Republic, Slovakia and Hungary to Romania.


For more recent steps in the SIDC and SDAC developments see the relevant articles as linked above.


Drawbacks of the current market coupling organisation



In the organisation of market coupling, many risks have been identified (see Annex 3 to the ACER Recommendation No 02/2021 of 17 December 2021 on reasoned proposals for amendments to the CACM Regulation (Initial impact assessment on the market coupling organisation), which can lead to market coupling failures.


In principle, the market coupling is organised in a way where only the calculation of market coupling results is centralised to some degree, whereas all other activities for market coupling operations are decentralised meaning that they are performed by individual NEMOs.


This requires each NEMO and each TSO to establish bilaterally or regionally agreed arrangements with each NEMO and each TSO on the other side of each border (‘NEMO2NEMO approach’) which is also hindering third party access for new NEMOs entering the market coupling.


The arrangements that enable operation of multiple NEMOs in a single bidding zone are not harmonised nor governed at EU-level.

As a result, when a new bidding zone with multiple NEMOs is integrated into market coupling, this requires a specific national project to establish the relevant legal, IT and contractual arrangements, which causes significant delays.


Similarly, when a new NEMO wants to operate in a bidding zone where previously only one NEMO operated, such NEMO needs to wait for the establishment of multi-NEMO arrangements which can take a significant amount of time and may discourage the additional NEMO from making such attempt.


The multi-NEMO arrangements are adopted nationally by national regulatory authority/-ies, but they significantly affect also neighbouring entities.


The missing involvement of potentially impacted and not legally bound neighbouring entities in the legal process for establishing these rules can result in disputes and problems.


Therefore, this represents an entry barrier and hampers further development of NEMO competition.


Among other flaws of the market coupling organisation the ACER Recommendation indicates:


a. Each NEMO and each TSO (or RCC) needs to collect the relevant market coupling inputs (namely orders, cross-zonal capacities or allocation constraints).


b. The market coupling operator (being the NEMO currently in charge of performing based on the rotational scheme) calculates the results of the day-ahead market coupling and the process finishes with the submission and publication of results. This process takes a lot of time (one hour from the time when the gate for bidding closes till the time when results are published10), partly due to the coupling calculation and its complexity via the Euphemia algorithm and partly due to many confirmations required by each TSO and NEMO. It could be simplified and sped up: Especially the core calculation - being the algorithm execution - is becoming more and more complex. This is due to the increasing number of constraints and requirements on the algorithm but specifically because NEMOs are unable to agree to restrict the use of products which introduce high complexity to the algorithm.


c. Clearing and settlement between NEMO trading hubs and scheduling: Individual TSOs and NEMOs perform the necessary arrangements in the current decentralised set-up. This requires each NEMO and TSO to set-up bilateral contracts for such activities including respective national requirements, which could be simplified by applying a centralised approach minimising risks of failure but also applying a robust backup. Furthermore, this set-up is a barrier to third party access for new NEMOs entering the market as it requires not only necessary contractual relations to one but all involved parties.


d. In general, the currently used decentralised approach including all individual NEMOs in daily operations of joint responsibilities implies a high risk of interoperability and data flow problems for the whole market coupling operation/process.


Decoupling incidents



The NEMO Committee Communication note of 11 June 2019 mentioned that, apart from of the incident of 7th of June 2019 (see below), the Day-Ahead MRC had been operating successfully since its launch in February 2014.


However, Annex 3 to the ACER Recommendation No 02/2021 of 17 December 2021 on reasoned proposals for amendments to the CACM Regulation (Initial impact assessment on the market coupling organisation) observes, there is “a high risk of one individual TSO’s or NEMO’s failure leading to a partial or full decoupling (partly addressed by back-up and fallback procedures), thereby impacting wider regions or the whole EU”.


The said ACER document also enumerates three partial decouplings in the period 2019 - 2021 leading to major market disruptions and causing huge financial losses:


a. June 7th 2019: A corrupt order entered into EPEX Spot’s local trading system hindered EPEX to provide its order book for CWE and GB. This led to a partial decoupling of those markets from MRC. Shadow auctions and local auctions were run for each local national market area. Following a delayed declaration of the partial decoupling, the shadow auction results were sent to market participants with delay, making it very difficult to nominate volume granted in shadow auctions and leading to very high prices in some bidding zones.


b. February 4th 2020: A specific bid caused a problem in EMCO’s local trading system. EMCO’s missing order books for CWE then led to a partial decoupling of MRC. For the affected interconnectors DK2-DE and DK1-NL shadow auctions were triggered. For the third interconnector DE-SE4, the capacity was given back to the owners. Local auctions run by EMCO for CWE were cancelled due to technical issues.


c. January 13th 2021: An unexpected technical issue related to GME's local trading system prevented GME from creating the order books. The problem was solved only after the declaration of the partial decoupling of GME, BSP, EXAA, HEnEx and CROPEX.8 For the decoupled interconnectors IT-FR, IT-AT, SI-AT, SI-HR and IT-GR shadow auctions were held.


All decoupling incident reports can be found on


As an example for the financial consequences the said document of 17 December 2021 indicates the annual congestion income for the border HR->SI was 261k€ in 2020 while the FTR payment for one day due to decoupling was 2.977k€ in January 2021.


Responsibility for decoupling events



The question arises where such financial losses should be allocated.


The answer needs to be sought having:




at hand.


The latest version of the HAR is laid down in the ACER Decision No 15/2021 of 29 November 2021 on the TSOs’ proposal for amendment of the harmonised allocation rules for long-term transmission rights, and, in the transition from the previous edition (stipulated in the ACER Decision 14/2019 of 29 October 2019), such allocation of financial responsibility for decoupling events was the major source of discontent between energy regulators and TSOs.


In the approval process ACER generally agreed with the TSOs' proposal - with the key exception, however - of the amendments regarding proposed a cap on remunerating the long-term transmission right holders in case of triggering fallback procedures during the day-ahead capacity allocation.

According to the ACER’s communiqué, the Agency believes this is not in line with the FCA Regulation as it clearly states that, under the current conditions in the day-ahead timeframe (i.e. using implicit auctioning), the remuneration principle is based on market spread – even in case of fallback. Therefore, ACER considers any remuneration different from a market spread as lacking legal basis.
As evidenced by supporting documents to the above ACER Decision ACER Decision No 15/2021 of 29 November 2021, Article 59(5) of the Proposal for amendment, the TSOs added a new principle for the remuneration of LTTRs, which introduces a cap on the remuneration of the LTTR holders:

‘Irrespective of whether it is a Direct Current interconnector or not, the caps described in paragraphs 2 and 3 of this Article shall also apply to the remuneration of Long Term Transmission Rights holders for non-nominated Physical Transmission Rights and Financial Transmission Rights in case of fallback Allocation for Implicit Allocation.’


This new principle aims to apply the rules for caps on the compensation for curtailments necessary to ensure operation remains within operational security limits before the day-ahead firmness deadline (‘compensation for curtailments’) also to the remuneration of LTTR in case of fallback allocation.


The TSOs justified this new cap in essence by arguing that, in case of a decoupling event, remunerating LTTRs holders with the market spread using the explicit fallback revenues is inconsistent with the objectives of Regulation (EU) 2019/943 and the FCA Regulation and that the proposed cap addresses this inconsistency.


According to the TSOs, ‘[a]s there is no consensus (yet) on TSOs’ proposal and the option to cover decoupling events in Article 48 and 59 of the HAR seems only possible if Article 35 of the FCA Regulation is amended, TSOs propose as an improvement until a more structural solution is implemented to extend to the remuneration of LTTRs in case of decoupling events the applicability of a cap on compensation for curtailment according to Article 59 (i.e. to limit the compensation to LTTR holders in case of missing income from DA due to unexpected outages and incident out of TSOs ‘domain’).’


In the TSOs’ view, ‘nothing in the legal and regulatory framework prohibits the imposition of a remuneration cap’.


The general public response to the above TSO’s conclusion was in the negative - many respondents (Eurelectric, Edison, Österreichs E-Wirtschaft, EDF, CRE, TIWAG, Europex, ČEZ, Energie-Nederland, EFET and AIGET) agreed with the ACER as to the necessity of deletion of the remuneration cap.


Only one respondent (ENTSO-E on behalf of all TSOs) did not agree and would like to keep the remuneration cap since the existing remuneration mechanism in case of an explicit fallback procedure does not rely on market fundamentals and the underlying price against which LTTRs are settled, the LTTRs remuneration is no longer representing the value of day-ahead cross border capacity and cannot be considered as hedging opportunity.


The decoupling event of January 13th 2021 was also referred to, which caused around 24M€ of additional costs on society, because the holders of the LTTRs were remunerated by the market spread using explicit capacity allocation.


This revenue inadequacy and non-correlation between the remuneration of LTTRs holders and market fundamentals is in clear contradiction with the principles governing the operation of electricity markets.


In its Decision the ACER assessed that the inclusion of a cap for remuneration of LTTRs in the HAR lacks legal basis and that, consequently, the proposed cap could not be part of the HAR.


According to the ACER:

- Compensation of capacity curtailments and remuneration of LTTRs are fundamentally different events taking place before and after, respectively, of the day-ahead firmness deadline and cannot be compared or assessed together.

- The provisions determining the remuneration of LTTRs cannot illegally profit from being placed to a section covering the caps for compensation of capacity curtailments, just to enjoy the benefits of its provisions, because the FCA Regulation only allows the introduction of a cap on compensations.

- Article 35 of the FCA Regulation, as well as Article 48 of the HAR envisage the remuneration of LTTRs based on market spread, therefore no cap is possible.

- A modification of the HAR to allow caps on the remuneration of LTTRs in case of decoupling would require amendments to the FCA Regulation.

- The wording of Article 35(3) of the FCA Regulation clearly states that the prescribed remuneration regime is an obligation (‘shall comply with’, ‘shall be equal to market spread’), which does not provide flexibility for alternatives.


According to the ACER, the fact that the explicit auctions in case of fallback perform poorly should not be a reason to conclude that the remuneration mechanism has been set in a wrong way.


Such finding should rather trigger an improvement of the fallback mechanisms.


The necessity for an introduction of a cap for remuneration in case of decoupling was justified by TSOs by the missing congestion income (i.e. the negative difference between collected congestion income from fallback explicit allocation and the remuneration of LTTRs), which has negative impact on consumers in terms of increased tariffs, but there are many other aspects and possible side effects not taken into account (increased hedging risks for market participants, lower future value of cross-zonal capacity resulting in lower collected congesting income).


ACER finds that the reasoning provided by all TSOs misses some crucial parts that would enable the identification of possible side effects of the introduction of a remuneration cap.


The TSOs omitted in their analysis some elements that could have detrimental effects on the markets.


Firstly, the introduction of the remuneration cap would deteriorate the quality of hedging.


This reduction of firmness could result in a decreased value of LTTRs and, in turn, lead to a decreased amount of the collected congestion income in the future.


Challenging firmness (by an introduction of a cap) could have detrimental effects on:

- the market participants for the period of decoupling, as they cannot fully hedge themselves;

- the tariff payers, because TSOs could collect less congestion revenues from LTTR auctions due to a decrease in capacity prices caused by less reliable hedging.


The ACER concludes that:

- an introduction of a cap for remuneration is not an appropriate solution to address the malfunctioning of shadow auctions (it is suggested to improve communication with the market participants and to train them more for being ready for such events);
- the remuneration of LTTRs should be equal to the market spread to foster the efficiency of the LTTRs themselves;
- the hedging opportunities for market participants should be provided in full scope and should not be limited by a potential application of a cap.


Last but not least, it is the ACER's observation that: "In the current legal and governance framework, where the day-ahead coupling is operated by all NEMOs, it is not possible to hold a single party liable for decoupling".


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