The regulatory regime applicable to electricity interconnectors with third countries : research project report.
Date: 2025-07-25
Institutions: European University Institute
Subjects: cross-border transport, electrical energy, electricity supply, energy grid, energy market, report, third country, transport network

The regulatory regime 
applicable to electricity 
interconnectors with third 
countries

Alberto Pototschnig and Leonardo Meeus

Research Project Report 
July 2025

© European University Institute, 2025

Editorial matter and selection © Alberto Pototschnig, Leonardo Meeus, 2025

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Table of Content

Executive Summary 

1. 

2. 

3. 

4. 

5. 

6. 

Introduction 

Interconnectors with third countries and the electricity  
Directive and Regulation 

Interconnectors with third countries and the TEN-E Regulation  
(Projects of mutual interest) 

Possible regulatory models for interconnectors to import  
(renewable-based) electricity from third countries  

4.1.  The interconnector model   

4.2.  The integrated commercial project 

Transitioning from the integrated commercial project  
to the interconnector model 

Contracting with offtakers located beyond the neighbouring  
EU Member State. 

7. 

Conclusion and policy/regulatory recommendations 

4

5

5

7

9

10

13

14

15

16

We acknowledge the financial support of zhero Europe B.V. for the preparation of this report. 
The views expressed in this report are those of the authors and of the authors only.

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Executive Summary

Interconnectors with third countries are currently outside the scope of the Electricity Directive1 and of 
the Electricity Regulation. Therefore, the provisions contained in these acts regarding third-party ac-
cess and tariffs, unbundling, the destination of congestion income and capacity allocation do not apply 
to interconnectors with third countries.

The regulatory regime introduced for PMIs by the revised TEN-E Regulation is unclear, as it is based on 
an application mutatis mutandis of a regime defined for PCIs, which are infrastructure project located 
within the EU, to which the provisions of the Electricity Directive and of the Electricity Regulation do 
apply. However, it seems that interconnectors with third countries can apply for PMI status and in fact 
several interconnectors with third countries have been granted such a status.

Two possible models can be foreseen regarding the transport infrastructure needed to import electricity, 
and, in particular, renewable-based electricity, from third countries into the EU:

• 

• 

the ‘interconnector’ model, in which a cross-border transmission infrastructure is developed inde-
pendently from the deployment of renewable-based electricity generation capacity in the third coun-
try. The interconnector is developed by TSOs or by other project promoters;

the ‘integrated commercial project’, comprising a renewable-based generation plant, or a number of 
such plants connected to a dedicated renewable electricity ‘island’ network in the third country, but 
not connected to that country’s network2, and an interconnector linking the plant or the dedicated 
renewable ‘island’ network to the EU network and market. The renewable-based generation plant(s) 
and  the  interconnector  are  developed,  owned  and  operated  by  a  single  commercial  entity  or  by 
several commercial entities operating in coordination.

These models could represent blueprints for the development of (inter)connections between the EU 
and third countries. Their implementation would require an agreement between the EU and the third 
country concerned.

The business model and the way in which the interconnector model can operate greatly depend on 
the organisation of the electricity sector in the third country and two access regimes and remuneration 
approaches can be envisaged:

• 

• 

the interconnector could be subject to third-party access requirements (similar to those applied to 
interconnectors between EU Member States) and remunerated through charges levied for its use 
and set or approved by the regulatory authorities in the third country and in the neighbouring EU 
Member State; or

the interconnector could be developed as a ‘merchant’ initiative. in this case, it would not be subject 
to any third-party access requirements and it would not be remunerated by charges set or approved 
by the regulatory authorities, but rather from the commercial revenues obtained from its use.

In the case of the ‘integrated commercial project’, the interconnector included in such a project would be 
used exclusively to export to the EU the electricity produced by the generation plant or plants located in 
the third country and included in the project, and connected to the interconnector, directly or through a 
dedicated renewable ‘island’ network. Therefore, it could more aptly be referred to as a (long) ‘connec-
tor’ of a (remote) power plant, or several power plants, to the EU network.

Similarly  to  exempted  interconnectors  between  Member  States,  it  could  be  envisaged  that,  after  an 
initial period, a merchant interconnector with a third country or the connector included in an integrat-

1  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), as emended by Directive (EU) 2024/1711 of the European Parliament and of the 
Council of 13 June 2024 amending Directives (EU) 2018/2001 and (EU) 2019/944 as regards improving the Union’s electricity market 
design. 

2  Although a variant of this set-up could be considered in which the plant or the island network in the third country are also connected to 

the electricity network in that country, in order to inject some of the renewable-based electricity into such a network.

4

ed commercial project transition towards the regulated interconnector model. Such a transition would 
clearly require that the connector developed under an integrated commercial project be connected to 
the electricity network of the third country.

The promoter(s) of an integrated commercial project might want to sell the renewable-based electricity 
produced  in  the  third  countries  to  offtakers  located  beyond  the  neighbouring  EU  bidding  zone. This 
would involve flowing this electricity from the neighbouring EU bidding zone, where it is delivered by 
the connector, to the bidding zone(s) in which the offtaker(s) are located and therefore crossing bid-
ding-zone border(s). in this situation, the project promoter(s) would be exposed to the risk related to the 
uncertainty and variability of the price differential(s) between the bidding zone(s) in which the offtakes 
are located and the neighbouring EU bidding zone. Such a risk could be hedged by using physical or 
financial transmission rights. However, at present, only year-ahead long-term transmission rights are 
allocated in the EU, which is far too short a period in comparison to the length of any PPA required to 
support an integrated commercial project. The European Commission could consider requesting TSOs 
to be ready to issue long-term (obligation-type) financial transmission rights (FTRs) with a much longer 
timeframe (e.g. 8-10 years) for part of the expected cross-zonal capacity over the same time horizon. 
The allocation of such longer-term FTRs should be backed by a regulatory guarantee, provided by the 
regulatory authorities, that the TSOs will be compensated for any shortfall in congestion income with 
respect to the payments due to the holders of such FTRs.

Conclusions and recommendations are provided in Section 7.

1.  Introduction

This Report assesses the regulatory regimes which could be applied to electricity connections used to 
import electricity generated in third countries into the European Union (EU). It does not discuss other 
aspects related to electricity imports from third countries, such as their treatment under the Cross-Bor-
der Adjustment Mechanism (CBAM), any reciprocal conditions imposed on third countries or the shar-
ing of benefits between the EU and the third countries.

2.  Interconnectors with third countries and the electricity Directive  

and Regulation

At the moment it is unclear whether the EU electricity sector rules specified in the Electricity Directive3 
and the Electricity Regulation4, and the Guidelines and Network Codes adopted under them, apply to 
electricity interconnectors with third countries. 

In fact, two interpretations of the relevant provisions are possible. The key to these different interpreta-
tions rests on the different definitions of ‘interconnector’ in the Electricity Directive and in the Electricity 
Regulation. More specifically:

• 

in the Electricity Directive, an ‘interconnector’ is defined as “equipment used to link electricity sys-
tems”, which could also include the linking with electricity systems in third countries5;

3  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), as emended by Directive (EU) 2024/1711 of the European Parliament and of the 
Council of 13 June 2024 amending Directives (EU) 2018/2001 and (EU) 2019/944 as regards improving the Union’s electricity market 
design. 

4  Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (recast), 
as amended by Regulation (EU) 2024/1747 of the European Parliament and of the Council of 13 June 2024 amending Regulations (EU) 
2019/942 and (EU) 2019/943 as regards improving the Union’s electricity market design.

5  Article 2(39) of Directive (EU) 2019/944.

5

• 

in the Electricity Regulation, an ‘interconnector’ is defined as “a transmission line which crosses or 
spans a border between Member States and which connects the national transmission systems of 
the Member States”6. In this case, interconnectors with third countries are clearly excluded from the 
definition of ‘interconnector’7.

The two interpretations of these provisions depend on how such a difference in the definitions of ‘inter-
connector’ should be read:

•  on the one hand, as the Electricity Directive and the Electricity Regulation contain provisions which 
are closely intertwined, it could be considered  unlikely that the EU co-legislators  meant different 
‘interconnector’ notions in the two acts. In this case one would conclude that the more restrictive 
definition of interconnector in the Electricity Regulation is the one to prevail. In this case, intercon-
nectors  with  third  countries  would  fall  outside  the  scope  of  the  provisions  in  both  the  Electricity 
Directive and the Electricity Regulation;

•  on  the  other  hand,  the  Electricity  Directive  and  the  Electricity  Regulation  were  proposed  by  the 
European  Commission  and  adopted  by  the  EU  co-legislators  at  the  same  time  and  therefore,  if 
they provide different definitions of ‘interconnector’, it is because the EU co-legislators intended a 
different scope of application, with the provisions in the Electricity Directive also applying to inter-
connectors with third countries. 

It should be noted that, in the gas sector, the 2009 Gas Directive8 included a definition of ‘interconnector’ 
which was the same as the one provided by the Electricity Regulation (thus excluding interconnectors 
with third countries). This definition was extended to cover interconnectors with third countries, at least 
for their portions on EU territory and territorial waters, by the 2019 modification of the Gas Directive9 
(the new text was retained in the 2024 Decarbonised Gas and Hydrogen Market Package Directive10).

However, the 2009 Electricity Directive11, adopted at the same time, provided for the same, more ex-
tensive definition as in the 2019 Electricity Directive. The 2024 Electricity Amending Directive12 did not 
intervene in the definition of ‘interconnector’.

If the interpretation of a deliberate difference in the definition of ‘interconnector’ in the Electricity Direc-
tive and in the Electricity Regulation were to be followed, it would be necessary to see which provisions, 
related to infrastructure, and in particular to interconnectors, are contained in the Electricity Directive 
(which could therefore possibly apply also to interconnectors with third countries) and which ones are 
contained in the Electricity Regulation (which, in any case, irrespective of the interpretation of the differ-
ence in the definitions, would not apply to interconnectors with third countries). Of the provisions which 
are relevant for an interconnector with third countries:

6  Article 2(1) of Regulation (EU) 2019/943.

7  Note that Article 2(1) of 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 and repealing Regulation (EC) No 1228/2003 – the predecessor of the Electricity 
Regulation, explicitly acknowledged the difference in the definition of ‘interconnector’ with respect to 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, the predecessor of the Electricity Directive, which was adopted at the same time: “For the purpose of this Regulation, the definitions 
contained in Article 2 of 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 apply, with the exception of the definition of ‘interconnector’ which shall be replaced by the following:  
- ‘interconnector’ means a transmission line which crosses or spans a border between Member States and which connects the national 
transmission systems of the Member States”.

8  Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market 

in natural gas and repealing Directive 2003/55/EC.

9  Directive (EU) 2019/692 of the European Parliament and of the Council of 17 April 2019 amending Directive 2009/73/EC concerning 

common rules for the internal market in natural gas.

10  Directive (EU) 2024/1788 of the European Parliament and of the Council of 13 June 2024 on common rules for the internal markets for 

renewable gas, natural gas and hydrogen, amending Directive (EU) 2023/1791 and repealing Directive 2009/73/EC (recast) 

11  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

12  Directive (EU) 2024/1711.

6

• 

• 

• 

• 

the provisions on third-party access, based on published tariffs, approved by the regulator or based 
on methodologies approved by the regulator, and applicable to all customers objectively and with-
out dis crimination between system users, are contained in Article 6 of the Electricity Directive, and 
therefore could also apply to the interconnectors with third countries;

the provisions on unbundling of transmission system operators (TSOs) are contained in Chapter VI 
of the Electricity Directive, and therefore could also apply to the interconnectors with third countries;

the provisions on capacity allocation are contained in Chapter III, Section I, of the Electricity Regu-
lation, and therefore would not apply to the interconnectors with third countries;

the provisions on the destination of congestion income are contained in Article 19(2) and (3) of the 
Electricity Regulation, and therefore would not apply to the interconnectors with third countries. The 
amendment introduced to Article 19(2) by the 2024 Electricity Amending Regulation13 is not relevant 
for the current purpose.

Therefore, in case the difference in definitions of ‘interconnector’ between the Electricity Directive and 
the Electricity Regulation were to be interpreted as intentional, the provisions on third-party access and 
unbundling would also apply to interconnectors with third countries, unless an exemption is granted. 
However, the provisions on exemptions are contained in Article 63 of the Electricity Regulation which, 
following the same interpretation, would not be applicable to interconnectors with third countries.

The complexity and potential inconsistency of the regulatory framework resulting from an interpreta-
tion of the difference in the definition of ‘interconnector’ in the Electricity Directive and in the Electricity 
Regulation as intentional and consequential suggests that such a difference should be considered as 
having no material relevance and therefore interconnectors with third countries should be deemed to 
fall outside the scope of the provisions not only of the Electricity Regulation, but also of the Electricity 
Directive.

3.  Interconnectors with third countries and the TEN-E Regulation (Projects 

of mutual interest)

The 2022 revision of the TEN-E Regulation14 introduced the notion of Project of Mutual Interest (PMI). 

However,  the  definition  of  PMI,  provided  in Article  2(6),  does  not  specify  what  type  of  infrastructure 
could constitute a PMI; it only requires that it meets certain criteria specified in the same Regulation. 
However, Article 4(2), when listing the criteria which PMIs shall meet, requires that the PMI “is located 
on the territory of at least one Member State and on the territory of at least one third country and has a 
significant cross-border impact”15,16. Moreover, recital (20), introducing the notion of PMI in the pream-
ble, refers to “infrastructure projects linking the Union’s networks with third-country networks”. It seems 
therefore that interconnectors with third countries could fall within the notion of PMI. And in fact, the 
sixth list of Projects of Common Interest (PCIs) and PMIs17 in 2023 includes the following interconnec-
tors with third countries:

• 

Interconnection between Sicily (IT) and Tunisia node (TN) [currently known as “ELMED”] (already 
included in the fifth PCI list);

13  Regulation (EU) 2024/1747.

14  Regulation (EU) 2022/869 of the European Parliament and of the Council of 30 May 2022 on guidelines for trans-European energy infra-
structure, amending Regulations (EC) No 715/2009, (EU) 2019/942 and (EU) 2019/943 and Directives 2009/73/EC and (EU) 2019/944, 
and repealing Regulation (EU) No 347/2013

15  Article 4(2)(c) of Regulation (EU) 2022/869.

16  As set out in point (2) of Annex IV: the project increases the grid transfer capacity, or the capacity available for commercial flows, at the 
border of that Member State with one or more third countries and brings significant benefits, either directly or indirectly (via interconnec-
tion with a third country) at Union level.

17  Commission Delegated Regulation (EU) 2024/1041 of 28 November 2023 amending Regulation (EU) 2022/869 of the European Parlia-

ment and of the Council as regards the Union list of projects of common interest and projects of mutual interest

7

• 

• 

• 

• 

Interconnection  between  Zeebrugge  area  (BE)  and  Kemsley,  Kent  (UK)  [currently  known  as 
“Cronos”];

Interconnection between Emden areas (DE) and Corringham, Essex (UK) [currently known as “Tar-
chon”];

Interconnector between Subotica (RS) and Sándorfalva (HU);

Interconnection between Wadi El Natroon (EG) and Mesogeia / St Stefanos (EL) [currently known 
as “GREGY Interconnector”];

•  Multi-purpose  interconnector  between  Modular  Offshore  Grid  2  (BE)  and  Leisten  (UK)  [currently 

known as “Nautilus”] (already included in the fifth PCI list);

•  Multi-purpose HVDC interconnection between Great Britain and the Netherlands [currently known 

as “LionLink”].

However, one of the general criteria for a project to qualify as a PMI18 requires that “there is a high level 
of convergence of the policy framework of the third country or countries involved and legal enforcement 
mechanisms to support the policy objectives of the Union are demonstrated, in particular to ensure:

•  a well-functioning internal energy market;

• 

security of supply based, inter alia, on diverse sources, cooperation and solidarity;

•  an energy system, including production, transmission and distribution, moving towards the objective 
of climate neutrality, in line with the Paris Agreement and the Union’s 2030 targets for energy and 
climate and its 2050 climate neutrality objective, in particular, avoiding carbon leakage”.

It is far from obvious that all the third countries involved in the PMIs included in the sixth list meet the 
above criterion, but this has not prevented a pragmatic approach by the European Commission.

From a regulatory perspective it is to be determined whether and in which way the provisions in Article 
16 of the revised TEN-E Regulation (Enabling investments with a cross-border impact) apply to PMIs.

Such an Article applies, in the first instance, to PCIs and, according to Article 16(12), “mutatis mutandis” 
also to PMIs.

It is therefore necessary to assess how the provisions in Article 16, developed with PCIs in mind, can 
also be relevant for PMIs and which modifications would be necessary to reflect the different nature of 
PMIs (the ‘mutatis mutandis’).

To start with, it is useful to recall the purpose of Article 16. Beyond procedural provisions, this article 
governs:

• 

• 

• 

the coverage of efficiently incurred investment costs of PCIs. These costs “shall be borne by the 
relevant TSO or the project promoters of the transmission infrastructure of the Member States to 
which the project provides a net positive impact, and, to the extent not covered by congestion rents 
or other charges, be paid for by network users through tariffs for network access in that or those 
Member States”19:

the possibility to apply for and the approval of an investment request, including the cross-border 
cost allocation20;

the  requirement  that  national  regulatory  authorities  take  the  cross-border  cost  allocation  into  ac-
count when fixing or approving tariffs21;

18  Article 4(2)(e) of Regulation (EU) 2022/869.

19  Article 16(1) of Regulation (EU) 2022/869.

20  Article 16(4) of Regulation (EU) 2022/869.

21  Article 16(6) of Regulation (EU) 2022/869.

8

• 

the possibility for TSOs to apply and for regulatory authorities to approve charges for access to the 
networks, even in the presence of a cross-border cost allocation22.

It is clear, therefore, that Article 16 refers to projects (PCIs) which falls within the regulatory domain, 
irrespective of whether they are developed by TSOs or other project promoters. It is in the context of this 
approach that Article 16(10) excludes the application of the provisions in the same Article to PCIs which 
have obtained an exemption from the rules on the destination of congestion income, on unbundling, on 
tariff setting or on third-party access. 

However, when Article 16(10) is considered with reference to PMIs, and more specifically to any in-
terconnector  with  third  countries  included  in  them,  it  might  lose  relevance  if  the  interpretation  of  the 
perimeter of application of the Electricity Directive and the Electricity Regulation provided in  Section 2 
of this Report holds. In fact, exemptions should not be relevant for interconnectors with third countries, 
as these interconnectors are not subject to the corresponding provisions in the first place. In this case, 
there are two ways of understanding the relevance of Article 16(10) for PMIs:

•  PMIs, at least for the parts represented by interconnectors with third countries, not being subject 
to the provisions from which PCIs could be exempted, would be outside the scope of application of 
the whole Article 16. This possibility is supported by a systemic reading of the provisions in Article 
16(10) which leads to the conclusion that Article 16 only applies to regulated projects. However, this 
understanding seems at odds with the explicit reference, in Article 16(12), to the application of that 
Article to PMIs, mutatis mutandis;

•  Article 16(10) would not apply to PMIs, as a result of the application of the ‘mutatis mutandis‘ con-
dition. The application of the remaining paragraphs of Article 16 would need to be assessed on the 
basis of the same logics. Therefore, despite the provisions in the Electricity Directive and the Elec-
tricity Regulation not applying to interconnectors with third countries, there might be parts of Article 
16 which could be relevant for PMIs as well.

Moreover, considering that a positive cost-benefit analysis23 and a decision on cross-border cost alloca-
tion is a pre-requisite for a project to be eligible for Union financial assistance through the Connecting 
Europe Facility (CEF), and the fact that Article 18 of the revised TEN’E Regulation, setting the criteria 
for eligibility of projects for such an assistance, focusing mainly on PCIs, also explicitly applies, mutatis 
mutandis to PMIs24, it has to be concluded that PMIs might submit a cost-benefit analysis and apply for 
and obtain a cross-border cost allocation decision as provided for in Article 16. This is a further indica-
tion that Article 16 also applies to PMIs.

In conclusion, while there is a degree of inconsistency in the provision in the TEN-E Regulation when 
it comes to PMIs, it seems that interconnectors with third countries can apply for PMI status and in fact 
several interconnectors with third countries have been granted such a status.

4.  Possible regulatory models for interconnectors to import (renewable-

based) electricity from third countries

The previous sections have concluded that, at present, interconnectors with third countries seem to fall 
outside the scope of application of the Electricity Directive and the Electricity Regulation, even though 
a process similar to the one envisaged by the TEN-E Regulation for PCIs could be – and it is - also 
applied to PMIs.

22  Article 16(9) of Regulation (EU) 2022/869.

23  As referred to in Article 16(4) of the revised TEN-E Regulation.

24  Article 18(5) of Regulation (EU) 2022/869.

9

Against this background, at least two possible models can be foreseen regarding the transport infra-
structure needed to import electricity, and, in particular, renewable-based electricity, from third countries 
into the EU:

• 

• 

the ‘interconnector’ model, in which a cross-border transmission infrastructure is developed inde-
pendently from the deployment of renewable-based electricity generation capacity in the third coun-
try. The interconnector is developed by TSOs or by other project promoters;

the ‘integrated commercial project’, comprising a renewable-based generation plant, or a number of 
such plants connected to a dedicated renewable electricity ‘island’ network in the third country, but 
not connected to that country’s network25, and an interconnector linking the plant or the dedicated 
renewable ‘island’ network to the EU network and market. The renewable-based generation plant(s) 
and  the  interconnector  are  developed,  owned  and  operated  by  a  single  commercial  entity  or  by 
several commercial entities operating in coordination.

These models could represent blueprints for the development of (inter)connections between the EU 
and third countries. Their implementation would require an agreement between the EU and the third 
country concerned.

4.1.  The interconnector model

The business model and the way in which the interconnector model can operate greatly depend on the 
organisation of the electricity sector in the third country. 

The interconnector might well be developed by the TSOs of the third country and of the neighbouring 
EU Member States (i.e. the EU Member State in which the interconnector is connected with the EU 
system), even though it could also be developed by other project promoters. The distinguishing feature 
of this model, as opposed to the integrated commercial project, is that the interconnector generally links 
the electricity system of the third country with the EU electricity system, so that the cross-border capac-
ity provided by the interconnector could, at least in principle, be more generally used by different (com-
mercial) entities, not only those generating electricity from renewable sources in the third country26.

Under the interconnector model, two access regimes and remuneration approaches can be envisaged:

• 

• 

the interconnector could be subject to third-party access requirements (similar to those applied to 
interconnectors between EU Member States) and remunerated through charges levied for its use 
and set or approved by the regulatory authorities in the third country and in the neighbouring EU 
Member State; or

the interconnector could be developed as a ‘merchant’ initiative. in this case, it would not be subject 
to any third-party access requirements and it would not be remunerated by charges set or approved 
by the regulatory authorities, but rather from the commercial revenues obtained from its use.

From a systemic point of view, the interconnector will provide positive benefits as long as the value 
of  the  interconnection  capacity  that  it  provides  is  higher  than  the  costs  of  the  interconnector.  Such 
a value is, in a first instance, determined by the difference between the value of the electricity in the 
neighbouring EU bidding zone27, as expressed by the market price in that zone, and the value or the 
cost of production in the third country of the electricity exported to the EU. However, the distribution of 
such net value between the EU, the third country, the TSOs or the project promoters is different in the 
two approaches and would also depend on the organisation of the electricity sector in the third country.

25  Although a variant of this set-up could be considered in which the plant or the island network in the third country are also connected to 

the electricity network in that country, in order to inject some of the renewable-based electricity into such a network.

26  Even though the cross-border capacity on the interconnector could be at least in part reserved for exporting renewable-based electricity 
from the third country into the EU electricity market. However, this would be a policy or regulatory decision and not a technical feature 
of the interconnector.

27  A bidding zone is the largest geographical area in which bids and offers from market participants can be matched without the need to 
attribute cross-zonal capacity. Here and hereafter, the neighbouring bidding zone is the bidding zone in the neighbouring Member State 
in which the interconnector is linked to the EU network.

10

If the electricity sector in the third country is not liberalised and only one nominated entity is al-
lowed to trade across the border with the EU28, there will be no need to envisage an allocation mecha-
nism for the cross-border capacity provided by the interconnector even under the first approach outlined 
above. In fact, on the third country’s side, such a capacity will be fully used by the nominated entity29. 

On the EU side, under the first approach outlined above, two arrangements could be envisaged30. In the 
first one, there will be a nominated entity also on the EU side, having the exclusive right to trade with 
the third country’s nominated entity. Alternatively, the latter can offer (or bid) directly onto an organised 
market  place  (OMP)  in  the  EU  neighbouring  Member  State,  or  trade  electricity  bilaterally  with  some 
offtakers in the EU31. 

In  case  the  third-country’s  nominated  entity  were  to  sell  directly  the  electricity  into  the  EU 
market (bilaterally or through an OMP), the value of the interconnection capacity, net of the 
interconnection charges, would be appropriated by such an entity. Instead, in the case in which 
trading over the interconnector were to be concluded between two nominated entities, one in 
the third country and the other one in the EU, the split of the net value between the third country 
and the EU, through their respective nominated entities, would depend on the terms of trading 
between such nominated entities.

In the case of a merchant interconnector, the project promoter(s) would have to agree with the authori-
ties in the third country and in the EU the conditions for the use of the interconnector.

If the electricity sector in the third country is liberalised and a plurality of parties are allowed to 
trade across the border, the interconnector developed under the first approach outlined above should 
be subject to regulation, so as to ensure transparent and non-discriminatory third-party access and ca-
pacity allocation. In fact, the way in which the capacity of the interconnector could be allocated becomes 
a relevant consideration. At least three possible arrangements could be envisaged, depending again on 
the way in which electricity is traded, or allowed to be traded, in the third country.

• 

the  explicit  allocation  of  the  cross-border  capacity  provided  by  the  interconnector.  Under  this  ar-
rangement, trade is enabled by auctioning off the (physical) transmission rights to the interconnec-
tor capacity. This could be done jointly by the two TSOs, in the third country and in the neighbouring 
EU Member State, separately for each of the two directions, or for half of the cross-border capacity 
provided by interconnector by each of the two involved TSOs. Such an auctioning would be based 
on agreements between the EU and the government of the third country, and between regulators 
and/or TSOs in the third country and in the neighbouring EU Member State.  In case of joint auc-
tions, such agreements could also define how the revenues from the auction are divided between 
the  third  country  and  the  neighbouring  EU  Member  State  (most  likely,  but  not  necessarily,  on  a 
50:50 basis, or reflecting the way in which the cost of the interconnector were borne). The assignees 
of the capacity rights in the third country could then use the interconnector to bid or offer into the 
neighbouring EU bidding zone or trade with market parties in the EU (e.g. supply EU customers)32. 
Similarly, the assignees of the capacity rights in the neighbouring EU Member State could use the 
interconnector to trade electricity with parties in the third country. This is currently a widely used ap-
proach, for instance, for the interconnectors with the UK, with Switzerland and with Turkey, and for 
the interconnection between Italy and Montenegro. However, it has its limitations, as traders have 
to buy transmission rights separately and before they know their value, as they only have imperfect 

28  It might be possible that in some third countries, some limited liberalisation of the electricity sector has occurred, for example for the 
generation of electricity from renewable sources, but trading across the border is still a reserved activities entrusted on a nominated 
entity.

29  Here we do not consider any reciprocity requirement regarding market opening in the third country.

30  A third arrangement could envisage auctioning the right to trade with the third country’s nominated entity, and therefore to use the in-
terconnector for this purpose, among EU market participants. However, these participants would be forced to agree terms with the third 
country’s nominated entities and therefore will be subject to the conditions set by the latter.

31  If the offtaker is located in a bidding zone other than the one to which the interconnector in connected to the EU network, the rights to 

use cross-zonal capacity within the EU would be required. This aspect is considered in Section 6 below.

32  However, see Section 6.

11

information about the market conditions. This can even lead to trade over an interconnector in the 
‘wrong’ economic direction, with flows from a high-price zone to a low-price zone33.

• 

• 

the use of the cross-border capacity provided by the interconnector to support the operation of a 
third country’s bidding zone as part of the EU organised market. In this way, entities in the third 
country would be able to bid or offer into the organised market in a neighbouring EU Member State. 
If congestion on the interconnector were to emerge, there could be a price difference between the 
neighbouring EU bidding zone and the third country’s bidding zone. This arrangement would avoid 
the separate allocation of the capacity rights in an explicit auction, but it would not completely re-
move the risk of trade inefficiencies34. Note also that this approach requires that entities in the third 
country be allowed to participate in the organised market in the neighbouring EU bidding zone in 
a competitive manner (if not, and only one entity in the third country were allowed to participate in 
the organised market in the neighbouring EU bidding zone, this approach would revert to the ones 
outlined in the case in which the electricity sector in the third country has not been liberalised);

the use of the cross-border capacity provided by the interconnector to support the extension of the 
EU  (price-based)  market  coupling  to  the  third  country.  In  this  case,  the  interconnection  capacity 
would be used to allow the exchange of power between the organised markets in the third country 
and in the EU. In this way, the interconnection capacity would not be allocated to specific entities 
trading on the market; instead, each entity would bid or offer into the market in the bidding zone in 
which it is located, and the interconnection capacity would be used to link (‘couple’) the market in 
the third country’s bidding zone and the other bidding zones in the most efficient way. Market cou-
pling guarantees that electricity always flows in the ‘right’ economic direction.

These different ways of using the cross-border capacity provided by a regulated interconnector demand 
increasingly sophisticated electricity market arrangements in the third country:

• 

• 

• 

in  the  case  of  the  explicit  allocation  of  the  cross-border  capacity  provided  by  the  interconnector, 
authorities and TSOs in the third country and in the neighbouring EU Member State would have 
to agree on the organisation of the auctions and the entities in the third country would need to be 
allowed to participate in the auctions, alongside EU entities, and to use any capacity assigned to 
them to trade electricity into (or from) the EU market;

in the case of a third country’s bidding zone as part of the EU organised market, entities in the third 
country would need to be allowed to bid and offer into such a bidding zone and accept the rules 
governing the EU organised market;

in the case of market coupling, the third country would have to harmonise its trading rules with those 
of the EU market and accept its governance.

The regulatory authorities and the TSOs in the third country and in the neighbouring EU Member States 
would also need to agree on how to allocate the value of the interconnector between the two jurisdic-
tions. Such an agreement might require approval by the European Commission. This value would be 
collected through the auction proceeds, in the case of an explicit capacity allocation, or through the 
price  differential  between  the  neighbouring  EU  bidding  zone  and  the  bidding  zone  or  the  organised 
market in the third country.

In  the  case  of  a  merchant  interconnector,  the  cross-border  capacity  it  provides  could  be  physically 
reserved to the project promoter(s) who can allocate it freely on a commercial basis. Alternatively, the 
capacity could be allocated explicitly to market participants or used to support the integration of a third 
country’s bidding zone into the EU electricity market or market coupling, with the project promoter(s) 

33  This was not an infrequent situation in the European Union before price-based market coupling was implemented on all internal borders. 
See, for example, Figure 44, page 119, of ACER/CEER, Annual Report on the Results of Monitoring the Internal Electricity and Nat-
ural  Gas  Market  in  2013,  available  at:  https://acer.europa.eu/sites/default/files/documents/Publications/ACER_Market_Monitoring_Re-
port_2014.pdf. 

34  For example, if the third country has its own local organised market, that market could produce a different price from the third country’s 
bidding zone in the EU organised market, which has not been taken into account when scheduling the exchanges across the intercon-
nector.

12

receiving  the  proceeds  from  the  explicit  capacity  allocation  auctions  or  long-term  financial  transmis-
sion rights (FTRs)35 on the additional capacity provided by the merchant interconnector. However, the 
project promoter(s) would be fully exposed to the risk that such proceeds ended up not being sufficient 
to  recover  the  costs  of  the  interconnector,  but  they  would  retain  any  upside  provided  by  the  same 
proceeds.  In  a  sense,  the  regime  applicable  to  the  merchant  interconnector  would  be  analogous  to 
that applied to exempted new interconnectors in the EU36. This approach would require an agreement 
between the governments and regulatory authorities of the neighbouring EU Member State and of the 
third country, which will have to be approved by the European Commission, as well of the respective 
TSOs on implementation aspects.

In summary, while interconnectors with third countries are outside the scope of the Electricity Directive 
and of the Electricity Regulation, many of the regulatory conditions and requirements provided therein 
for interconnectors between EU Member States could apply, including the ‘exempted interconnector’ 
concept, by analogy, to the interconnectors with third countries developed under the ‘interconnector’ 
model.

4.2.  The integrated commercial project

In the case of the ‘integrated commercial project’, the interconnector included in such a project would be 
used exclusively to export to the EU the electricity produced by the generation plant or plants located in 
the third country and included in the project, and connected to the interconnector, directly or through a 
dedicated renewable ‘island’ network. In fact such plants, and any dedicated renewable island network 
might not be connected to the electricity network of the third countries and the interconnector would not 
be used to exchange electricity between the electricity network of the third country and the electricity 
network of the neighbouring EU Member State37.

As in this case the interconnector would be used only to transport electricity produced by the project 
promoter(s) in the third country, it could more aptly be referred to as a (long) ‘connector’ of a (remote) 
power plant, or several power plants, to the EU network. Seen in this way, it is clear that the provisions 
on interconnectors (or new interconnectors) in the Electricity Directive and the Electricity Regulation 
would not apply, irrespective on how the difference in the definitions of an ‘interconnector’ in these acts 
is interpreted. Instead, the usual terms and conditions for the connection of high voltage direct current 
systems and direct current-connected power park modules contained in the relevant Network Code38 
would seem more relevant.

With regard to the use of the capacity provided by the ‘connector’, in case the project included more 
generating plants connected to a dedicated renewable island network and operated by different project 
promoters, the latter would have to agree how to allocate the capacity provided by the connector among 
the production of the different plants. 

35  Financial transmission rights (FTRs) grant the holder the right to receive a payment equal to the price differential between the destination 
bidding zone and the source bidding zone, according to the zonal border and the direction defining them, whenever such a differential 
is positive. Obligation-type FTRs also require the holder to make a payment determined in a similar way when the price differential in 
negative.

36  Article 63(1) of the Electricity Regulation provides for the possibility of new interconnectors within the EU to be exempted from Article 
19(2) and (3) (on the destination of congestion income) of the same Regulation and from Articles 6 (on third party access) and 43 (on 
unbundling), and Article 59(7) and Article 60(1) (on regulated terms and conditions for access to cross-border infrastructure) of the Elec-
tricity Directive. For new interconnector in the EU, such exemptions are limited in time and are subject to conditions specified in the 
same paragraph. See Section 5 regarding the possibility of a merchant interconnector to transition, over time, towards the interconnector 
model.

37  In fact, the generating plants in the third country or any dedicated renewable island network could also be connected to the electricity 
network of the third country, however with such connections only used to sell part of the electricity produced by those plants into the 
third country’s market, but not to allow electricity exchanges between the third country and the EU.

38  Commission Regulation (EU) 2016/1447 of 26 August 2016 establishing a network code on requirements for grid connection of high 
voltage direct current systems and direct current-connected power park modules. In this respect, on 19 December 2024, ACER issued 
Recommendation No 01/2024 on reasoned proposals for amendments to Commission Regulation (EU) 2016/1447 of 26 August 2016 
establishing a network code on requirements for grid connection of high voltage direct current systems and direct current-connected 
power park modules.

13

In this set up, the project promoter(s) would have exclusive rights to the use of the capacity provided 
by the connector, which could not be used for any other purpose than to export the renewable-based 
electricity produced by the generating plants included in the project, and there would be no need to set 
explicit charges for its use. The cost of the connector, as well as the cost of the connected generating 
plant(s) located in the third country, would be recovered from the revenues derived from the sale on 
the EU electricity market of the electricity produced by the generation plant(s) included in the project 
and sold into the EU through the connector39. The project promoter(s) would be fully exposed to the 
risk that such revenues ended up not being sufficient to recover the costs of the generating plants and 
of the connector. On the other hand, they would retain any extra revenues attracted by the sale of the 
electricity produced by the generating plants included in the project. In a sense, the regime applicable 
to the connector included in an integrated commercial project would be analogous to that applied to 
exempted new interconnectors in the EU40.

Finally, the project promoters could be able to mitigate or hedge such a risk by entering in long-term 
Power Purchase Agreements (PPAs) with offtakers in the EU market, or by taking positions in electricity 
futures contracts in the neighbouring EU Member State.

5.  Transitioning from the integrated commercial project to the interconnector 

model

In Section 2 of this Report it was concluded that the provisions of the Electricity Directive and of the 
Electricity Regulation do not apply to interconnectors with third countries. Nonetheless, the regimes ap-
plicable to new interconnectors within the EU could inspire a regulatory framework for interconnectors 
with third countries.

In this sense, the interconnector model, in its two variants, and the integrated commercial project ap-
proaches  were  proposed,  the  first  one  mimicking  the  regime  applicable  to  interconnectors  between 
Member States and the second one combining elements of the framework for the connection of power 
parks and for exempted interconnectors.

In this latter respect, Article 63(1) of the Electricity Regulation envisages that exemptions for new inter-
connectors are granted for a limited period of time. Therefore, it could also be envisaged that, after an 
initial period, a merchant interconnector with a third country or the connector included in an integrat-
ed commercial project transition towards the regulated interconnector model. Such a transition would 
clearly require that the connector developed under an integrated commercial project be connected to 
the electricity network of the third country. At that point, the connector would fulfil a similar role to the 
one of hybrid projects in the case of offshore wind parks, by serving a double purpose: (i) to connect 
the renewable-based generation plant(s) included in the integrated commercial project to the electricity 
systems of both the third country and of the neighbouring EU Member States, and (ii) to allow power 
flows between these electricity systems (as in the case of the interconnector model).

The transition towards the regulated interconnector model does not require the transfer of the owner-
ship, to the TSOs of the third country and of the neighbouring EU Member State, of the interconnector 
or of the connector under the integrated commercial project. What would change is the way in which 
the interconnector or the connector are used and their capacity allocated.  If the ownership of the inter-
connector or of the connector is not transferred, the project promoter(s) would receive a fee for making 
the interconnector or the connector available (which might include an availability incentive component).

The issue then arises as to what is a reasonable initial period which would still make a merchant inter-
connector or an integrated commercial project attractive to their promoters, while ensuring that even-
tually the cross-border transmission capacity between the third country and the EU becomes available 
for a more general use to the benefits of market participants in both jurisdictions.

39  Or, possibly sold, in part, in the third country. See footnote 25 above.

40  See footnote 36, and Section 5 regarding the possibility of the interconnector included in an integrated commercial project to transition, 

over time, towards the interconnector model.

14

In principle, such an initial period should not be shorter than the one which allows the promoter(s) to 
recover the full costs of their investments, including an appropriate rate of return, considering the risk 
involved in the initiative. Such an assessment should be conducted ex-ante, on the basis of a business 
plan (presented by the project promoters and approved by the competent administrations, or regulatory 
authorities).  In  the  case  of  an  integrated  commercial  project,  the  business  plan  should  define  which 
share of the overall revenues that the project is expected to obtain from the sale on the EU market of 
the renewable-based electricity produced in the third country will be attributed to cover the cost of the 
power plant(s) and which remaining share will be attributed to cover the costs of the connector. As these 
two components of an integrated commercial project face the same risk, linked to the uncertainty and 
variability of the price at which the electricity produced by the renewable-based generation capacity in 
the third country could be sold on the EU market, it seems reasonable that such shares reflect the net 
present values of the investment and operating costs of the renewable-based generation capacity and 
of the connector.

If project promoters decide to enter into PPAs with offtakers in the EU, it is disputable whether the terms 
of these PPAs should enter into the business plan considered for the definition of the length of the initial 
period after which the transitioning towards the interconnector model might take place41. Instead, prices 
emerging from electricity futures markets in the neighbouring EU Member State could be used as a 
more relevant reference for the revenues which the integrated commercial project or the merchant in-
terconnector might expect to obtain from the sale onto the EU market of the renewable-based electricity 
produced in the third country or from the sale of the interconnector capacity42.

In case, the relevant authorities were to decide to implement the regulated interconnector model sooner 
than the initial period defined as described above, it would seem fair that the project promoter(s) were 
compensated by assigning them, for the remaining part of such an initial period, FTRs on the capacity 
provided by the interconnector. FTRs require, for their implementation, that reliable market prices are 
available for the two markets on either side of an interconnector. As indicated in Section 4, the existence 
of a liberalised and competitive electricity market cannot be given for granted in all third countries which 
might be able to host renewable-based generation capacity to produce electricity destined to be sold in 
the EU. However, it could be assumed that an early transitioning to the regulated interconnector model 
approach would be justified by a faster-than-expected liberalisation of the electricity sector in the third 
country and the opportunity for more participants in that market to trade with the EU. In that sense, it 
is likely that an earlier transitioning to the regulated interconnector model approach implies the estab-
lishment of an electricity market in the third country which can provide a reliable price reference for the 
implementation of financial transmission rights.

6.  Contracting with offtakers located beyond the neighbouring EU  

Member State.

The promoter(s) of an integrated commercial project might want to sell the renewable-based electricity 
produced  in  the  third  countries  to  offtakers  located  beyond  the  neighbouring  EU  bidding  zone. This 
would involve flowing this electricity from the neighbouring EU bidding zone, where it is delivered by 
the connector, to the bidding zone(s) in which the offtaker(s) are located and therefore crossing bid-
ding-zone border(s).

In this situation, the project promoter(s) would be exposed to the risk related to the uncertainty and 
variability of the price differential(s) between the bidding zone(s) in which the offtakes are located and 
the neighbouring EU bidding zone. Such a risk could be hedged by using physical or financial transmis-

41  In fact, if the terms of the PPAs were reflected in the business plan considered for the definition of the length of the initial period after 
which the transitioning towards the interconnector model might take place, the project promoter(s) might be subsidised in offering lower 
PPAs prices through a lengthening of such an initial period. This might result in unfair competition in the EU market.

42  However, currently, futures markets do not extend beyond three years (and only in the most liquid ones), which is too short a period with 
respect to the length of time over which the recovery of costs for an integrated commercial project or a merchant interconnector might 
be achieved.

15

sion rights. However, at present, only year-ahead long-term transmission rights are allocated in the EU, 
which is far too short a period in comparison to the length of any PPA required to support an integrated 
commercial project.

The issue has been indeed recently raised as to whether long-term transmission rights with a longer 
timeframe should be made available to market participants. In particular, the 2023 Proposal43 from the 
European Commission to amend the Electricity Regulation included44 the amendment of Article 9 of 
such a Regulation to provide, inter alia, that “the single allocation platform shall: […] offer trading of 
financial transmission rights that shall allow holders of these financial transmission rights to remove ex-
posure to positive and negative price spreads, and with frequent maturities of up to at least three years 
ahead”. However, the EU co-legislators eventually decided to postpone the decision on whether to offer 
longer-term transmission rights until the European Commission, after consulting relevant stakeholders, 
carried out an assessment of the impact of possible measures to improve the ability of market partici-
pants to hedge price risks in the internal electricity market. Such an assessment should be completed 
by 17 January 202645.

On the basis of the results of such an assessment, the European Commission, by 17 July 2026, should 
adopt an implementing act to specify measures and tools to improve the ability of market participants to 
hedge price risks in the internal electricity market.

In this context, the European Commission could consider requesting TSOs to be ready to issue long-term 
(obligation-type) FTRs with a much longer timeframe (e.g. 8-10 years) for part of the expected cross-zon-
al capacity over the same time horizon. The allocation of such longer-term FTRs should be backed by a 
regulatory guarantee, provided by the regulatory authorities, that the TSOs will be compensated for any 
shortfall in congestion income with respect to the payments due to the holders of such FTRs.

7.  Conclusion and policy/regulatory recommendations

The  following  conclusions  and  recommendations  emerge  from  the  considerations  developed  in  the 
previous sections.

1.  Interconnectors with third countries are currently outside the scope of the Electricity Directive and 
of the Electricity Regulation. Therefore, the provisions contained in these acts regarding third-party 
access and tariffs, unbundling, the destination of congestion income and capacity allocation do not 
apply to interconnectors with third countries.

2.  The  regulatory  regime  introduced  for  PMIs  by  the  revised  TEN-E  Regulation  is  unclear,  as  it  is 
based on an application mutatis mutandis of a regime defined for PCIs, which are infrastructure 
project located within the EU, to which the provisions of the Electricity Directive and of the Electricity 
Regulation do apply.

3.  It  would  be  valuable  to  clarify  how  the  TEN-E  Regulation,  and  in  particular  its Article  16, 
applies to PMIs, beyond the current approach based on a mutatis mutandis application of 
provisions primarily developed for PCIs.

4.  In any case, it is possible to define at least two models for the development of interconnectors with 
third countries: the interconnector model, in two variants, and the integrated commercial project. 
These models are inspired by the regulatory regimes for (new) interconnectors within the EU. Their 
implementation would require an agreement between the EU and the third country.

43  Proposal for a Regulation of the European Parliament and of the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well 
as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design, Strasbourg, 14.3.2023, COM(2023) 148 
final.

44  In its Article 1(6).

45  Article 9(3) and (4) of Regulation (EU) 2019/943, as amended by Article 2(6) of Regulation (EU) 2024/1747 of the European Parliament 
and of the Council of 13 June 2024 amending Regulations (EU) 2019/942 and (EU) 2019/943 as regards improving the Union’s electricity 
market design.

16

5.  The interconnector model could be implemented in two variants. In the first variant, the intercon-
nector will likely be developed by the TSOs in the third country and in the neighbouring EU Member 
State and would be subject to regulation similar to that applicable to interconnectors between EU 
Member States. However, the regime for access and the allocation of the capacity provided by the 
interconnector would much depend on the structure of the electricity sector in the third country and 
the degree of its liberalisation. In the second variant, the interconnection will be developed on a 
commercial basis by project promoter(s) and would be treated similarly to exempted interconnec-
tors within the EU.

6.  The  integrated  commercial  project  would  involve  a  connection  between  one  or  more  renew-
able-based generating plants located in the third country, but generally not connected to that coun-
try’s electricity network, and the neighbouring EU Member State. It would be very much akin to a 
long power plant connection to the EU electricity network.

7.  These models could be recognised by the European Commission as blueprints for future 

(inter)connectors between the EU and third countries.

8.  A merchant interconnection model and the connector included in an integrated commercial project 
might  transition  towards  the  interconnector  model,  after  an  initial  period,  which  should  allow  the 
project promoter(s) to recover their investment costs, including an adequate return on investments. 

9.  The possibility of acquiring cross-zonal long-term transmission rights is essential for project pro-
moter(s) to be able to sell the renewable-based electricity produced in the third country to offtakers 
located beyond the neighbouring EU bidding zone. These transmission rights should extend over 
a horizon which covers a significant portion of the period over which the investment costs of the 
merchant interconnector or of the integrated commercial project are recovered.

10. At present, long-term transmission rights are only available for the front year. The European Com-
mission is conducting an assessment on the existing tools available to market participants to hedge 
price risks in the internal electricity market. On the basis of the results of that assessment, the Euro-
pean Commission might adopt an implementing act extending the timeframe over which long-term 
financial transmission rights are issued. Three years, as suggested by the revised Electricity Reg-
ulation, are still too short a timeframe. The European Commission should consider requiring 
TSOs to be ready to issue long-term (obligation-type) FTRs over a much longer timeframe 
(e.g. 8-10 years) for part of the expected cross-zonal capacity, to enable cross-zonal trading of 
PPAs (including for renewable-based generation capacity located in the EU). In this case, regulatory 
authority should provide TSOs with a guarantee that they would be compensated for any shortfall in 
congestion income with respect to the payment due to the holders of such FTRs.

17

Research Project Report 
July 2025

doi:10.2870/5215688
ISBN:978-92-9466-725-0
QM-01-25-162-EN-N