COMMISSION STAFF WORKING DOCUMENT Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMIITTEE OF THE REGIONS An EU strategy to harness the potential of offshore renewable energy for a climate neutral future
Date: 2020-11-19
Institutions: Directorate-General for Energy, European Commission
Subjects: EU energy policy, energy grid, energy production, energy research, energy technology, investment, littoral, marine energy, renewable energy, wind energy

EN 

  EN 

   EUROPEAN COMMISSION  Brussels, 19.11.2020  SWD(2020) 273 final  COMMISSION STAFF WORKING DOCUMENT Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMIITTEE OF THE REGIONS An EU strategy to harness the potential of offshore renewable energy for a climate neutral future {COM(2020) 741 final}  
 
 
Guidance on electricity market arrangements: A future-proof market 
design for offshore renewable hybrid projects 

I. 

Introduction  

The European Union is set to become the first climate neutral continent by 2050, delivering 
on  the  commitment  to  achieve  an  inclusive,  affordable  and  green  transition.  Offshore 
renewable energy will play a key role in transforming our energy sector and the Commission 
communication attached sets out the extent of the challenge this presents. A huge up-scale is 
needed to achieve the objective of a fivefold increase by 2030 and a 25-fold increase by 2050 
to reach approximately 300 GW of installed capacity, and this is just for offshore wind. Other 
technologies  at  earlier  stages  of  development  also  have  a  part  to  play.  To  achieve  these 
ambitious  objectives,  there must be a significant  step change in  how we  work to  enable the 
cross-border cooperation required to deploy the levels of offshore renewable energy needed.  

Today,  offshore  wind  energy  is  deployed  mainly  through  national  projects,  with  offshore 
windfarms  connected  radially  to  the  shore  and  cross-border  interconnectors  developed 
separately. Although  a significant proportion of  offshore projects  is  likely to continue to  be 
developed  in  this  way1,  some  projects  are  expected  to  progress  more  efficiently  and  with 
significant welfare gains if they are developed as generation hubs connected to two or more 
Member  States.  These  projects,  known  as  hybrid  projects  because  they  combine  energy 
generation and interconnection, can yield estimated cost savings of up to 10%2 but also come 
with additional risks due to legal uncertainties related to regulatory treatment and other issues 
such  as  the  distribution  of  costs  and  benefits  among  project  partners.  This  moment  in  time 
represents a unique opportunity to prepare for a large up-scale of renewable energy and avoid 
sub-optimal growth due to fragmented national approaches in scarce maritime space.  

The  key  challenge  is  how  to  deploy  these  projects  in  a  way  that  achieves  the  least-cost 
transition for consumers and maintains social acceptance of the energy transition as a whole. 
Although  there  are  clear  benefits  to  a  more  integrated  offshore  grid  for  renewable  energy 
production, these projects are complex to set up. In addition, the market rules governing the 
electricity  system  have  been  designed  for  a  renewables-based  future  in  a  way  that  supports 
security of supply and the integration of large volumes of renewable energy over a wide area. 
However, they were not designed specifically with offshore hybrid projects in mind. 

1 “Progress on Meshed HVDC Offshore Transmission Networks” modelled a large scale up of offshore wind 
energy projects and energy hubs in the North Sea: www.promotion-offshore.net  
2 Roland Berger GmbH (2019), Hybrid projects: How to reduce costs and space of offshore developments, North 
Seas Offshore energy Clusters study:  
https://op.europa.eu/en/publication-detail/-/publication/59165f6d-802e-11e9-9f05-01aa75ed71a1  

1 

 
 
 
 
 
                                                           
This paper focuses mainly on the specific category of offshore hybrid projects. These projects 
raise  complex  questions  to  be  addressed  to  ensure  that  the  regulatory  framework  is  not  a 
barrier to deployment. The objective of this guidance is to address some of the key questions 
facing  Member  States,  regulatory  authorities,  TSOs  and  project  promoters  concerning  the 
application of the electricity market legislation to offshore developments. In particular: 

 

 

 

It explains how to design offshore projects in line with the current rules, in particular 
unbundling, market dispatch and cross-border trading rules;  

It  considers whether  an adaptation  of the current regulatory framework is needed to 
address the specific needs of investment incentives for hybrid projects; 

It examines the need for coordination on technical rules regarding connection to the 
electricity grid.  

This guidance is technology-neutral, though it may be primarily of interest to offshore wind, 
which is currently the most mature offshore renewable energy technology. In addition, some 
of  the  elements  outlined  below  can  also  be  applied  to  more  traditional  offshore  generation 
projects connected only to one market.   

II. A market framework for offshore renewable energy  

The  EU  rules  governing  the  electricity  market  (namely  Electricity  Directive  (EU)  944/2019 
and  Regulation  (EU)  943/2019)  aim  to  ensure  that  the  integrated  EU  electricity  market 
operates  in  a  way  that  is  fair  and  fit  for  renewable  energy.    In  particular,  the  Regulation 
strengthens  shorter-term  markets,  which  will  provide  several  benefits  for  renewable  energy, 
enabling variable renewables to participate on a more equal footing as the markets close at the 
day-ahead and intraday stages when more accurate forecasting of generation is possible. This 
allows  power  generation  using  variable  renewable  sources  to  manage  their  risks  and  it  also 
supports  security  of  supply  by  allowing  the  full  flexibility  of  our  interconnected  electricity 
system to integrate renewables over a wider area and respond to unforeseen events. The aim 
of these rules is to enable renewable energy to become the backbone of our electricity system.  

This  paper  recognises  that  the  electricity  market  rules  were  not  designed  with  the  specific 
needs  of  offshore  hybrid  projects  in  mind  and  therefore  describes  the  current  market 
framework. It sets out the Commission’s view on certain areas where stakeholders have raised 
questions  on  complex  topics  such  as  market  dispatch,  unbundling,  cross-border  electricity 
trading and bidding zone configuration. It also  analyses the rules on congestion income and 
the  grid  connection  Network  Codes  to  determine  whether  adaptations  are  needed  to  ensure 
that these rules are fit for purpose for a large scale-up of offshore renewable energy projects.  

2 

 
 
 
 
 
 
I. Explanation of the main market rules applicable   

a) Market dispatch and balance responsibility 

In  the  early  days  of  renewable  energy  deployment,  renewable  energy  was  an  emergent 
technology,  protected  from  competition  and  market  dynamics  on  the  wholesale  electricity 
market by support mechanisms, priority dispatch, priority access, and other types of specific 
frameworks.  Nowadays,  although  not  all  renewable  technologies  are  at  the  same  stage  of 
development,  technologies  such  as  wind  and  solar  are  highly  competitive  and  renewable 
energy  constitutes  around  one-third  of  all  electricity  generation  in  the  EU3.  The  current 
market  framework, in  particular the recast  Electricity Regulation,  therefore takes account  of 
the  considerable  progress  made  over  recent  years  and  recognises  that  renewable  energy  is 
becoming the foundation of our electricity system. 

This  is  a significant  change in  the  regulatory  framework for producers of renewable energy 
because,  in  the  past,  they  were  often  not  exposed  to  market  dynamics  and  obligations.  The 
Electricity Regulation does not put an end to existing support schemes, indeed Article 12(6) 
provides a guarantee that producers on existing schemes may continue to benefit from priority 
dispatch  granted  under  those  schemes.  However,  though  there  are  exemptions  for  small 
generation  assets  and  demonstration  projects4  –  especially  important  in  the  context  of 
emerging  offshore  technologies  –  there  are  now  clear  rules  on  how  large  new  investment 
projects should operate. 

Article 12 of the Electricity Regulation sets out the rules on power generation dispatch. Large 
new renewable energy installations no longer benefit from priority dispatch, which means that 
future  offshore  wind  generation  will  need  to  operate  according  to  market  based  dispatch. 
Existing installations that already benefit from priority dispatch can continue to do so. Priority 
dispatch  is  also  maintained  for  new  small-scale  installations  up  to  400 kW  (decreasing  to 
200 kW  from  January  2026)  and  for  demonstration  projects  for  innovative  technologies, 
therefore potentially for innovative tidal or wave offshore investments.  

It is worth noting that, for hybrid projects, the issue of priority dispatch is not simply about 
access to a market. It is inherently linked to issues of third-party access and cross-border trade 
flows.  In  order  to  allow  all  generation  to  be  able  to  compete  for  scarce  interconnection 
capacity,  fair  and  non-discriminatory  treatment  is  critical.  Article  12(7)  of  the  Electricity 
Regulation  states  that  priority  dispatch  must  not  be  used  to  reduce  cross-border  capacities. 
This is to ensure that the cheapest sources of renewable energy will be dispatched and traded 
throughout the EU.   

Article 5 of the Electricity Regulation sets out rules on balancing responsibility. In principle, 
all market participants must be responsible for the imbalances they cause in the system. For 
renewable energy producers active on the market, this means that they need to bear the risk of 

3 Source: Eurostat, 2018. 
4 Small generation assets and demonstration projects may be granted priority dispatch and an exemption from 
balancing responsibility under the Electricity Regulation.  

3 

 
 
                                                           
incorrect  predictions  for  production,  e.g.  due  to  incorrect  wind  forecasts.  This  creates 
incentives to improve forecasts or pay for better forecast services. Derogations from balancing 
responsibility  may  be  maintained  for  small  installations,  demonstration  projects  and 
installations benefiting from support already approved under EU State aid rules commissioned 
before 4 July 2019.  

These provisions mean that, as a starting point, electricity producers bear the responsibilities 
related  to  buying  and  selling  the  electricity  they  generate.  The  electricity  producer  can  bear 
the  responsibilities  and  complexities  of  operating  in  the  wholesale  market  itself  or  delegate 
them  contractually  to  a  third  party  (an  aggregator,  a  supplier,  or  another  type  of  service 
provider). It would, of course, be a commercial decision to outsource to a third party service 
provider. 

Another aspect of market operation crucial for offshore hybrid renewables is curtailment (or 
other  forms  of  downward  re-dispatch),  especially  as  we  achieve  higher  levels  of  renewable 
energy integration into our electricity systems. The Regulation distinguishes between market-
based  re-dispatch  and  non-market-based  re-dispatch.  Market-based  redispatch  will  always 
require the agreement of the operator of the facility to be redispatched, e.g. by having made an 
offer  for  redispatch  services  (or  using  offers  from  other  markets  such  as  the  balancing 
market).  If  however,  exceptionally,  non-market-based  re-dispatch  is  used,  the  Regulation 
provides  strong  protection  for  renewables,  which  should  only  be  subject  to  downward  re-
dispatching as a last resort once all other technologies that can reasonably respond have been 
exhausted first. Any such curtailment should also be suitably compensated pursuant to Article 
13(7). It should be noted that compensation is linked to the price at the day-ahead level in the 
bidding zone of the renewable energy producer, and therefore impacted  by the definition of 
bidding  zones.  It  should  also  be  noted  that  a  renewable  energy  producer  would  not  be 
remunerated if a commercial decision is made not to generate due to low or negative market 
prices. 

In addition, one provision is especially relevant for large renewable energy installations with a 
significant  impact  on  cross-border  electricity  trading.  Article  12(7)  expressly  sets  out  that 
priority dispatch is no justification for reductions in cross-border capacity available for trade5. 
Therefore,  where  priority  dispatch  creates  internal  congestion,  this  does not  allow  deviation 
from  the  cross-border  trading  requirements  under  Article  16,  which  are  explained  further 
below in point c of this section. 

Lastly,  it  is  important  to  acknowledge  that  in  a  system  based  on  market  dispatch  with  full 
balancing  responsibility,  renewable  energy  producers  are  exposed  to  several  types  of  risks. 
The main risks are price risks (if the market price is lower than expected, reducing revenue) 
and imbalance risks (if production is not as forecast and scheduled, thus creating imbalance 
costs).  Producers  can  reduce  those  risks,  and  partly  hedge  against  their  impact,  either 
themselves or through third-party service providers. Lower than expected prices on short-term 

5 Always with the caveat that system operators may take the measures that are necessary to maintain system 
security, in accordance with the Electricity Regulation. 

4 

 
 
                                                           
markets  can  be  hedged  by  trading  electricity  on  long-term  markets  (e.g.  either  via  specific 
power  purchase  agreements  selling  renewable  electricity  or  on  general  forward  markets).  If 
the  expected  risks  are  due  to  price  differences  between  different  geographical  areas  (e.g. 
between  an  offshore  bidding  zone  and  a  neighbouring  market),  they  can  be  mitigated  by 
trading  forward  transmission  capacity  (be  it  financial  or  physical  transmission  rights).  To 
mitigate  imbalance  risks,  producers  of  weather-dependent  energy  generation  should  use  the 
best  forecasting  methods  available  as  a  basis  for  scheduling.  Relevant  national  authorities 
should  also  consider  providing  clear  explanations  of  how  the  market  rules  will  affect 
producers6 in their specific bidding zone and circumstances.  

b) Unbundling 

Unbundling,  in  application  since  the  Third  Energy  Package  of  20097  to  ensure  non-
discriminatory system operation and third-party access, also applies to the offshore renewable 
electricity sector. That means that there must be a separation between electricity transmission 
on  one  hand,  and  electricity  production,  as  well  as  storage  or  hydrogen  production  on  the 
other  hand.  Therefore,  although  owners  of  offshore  energy  generation  can  also  own  and 
operate  storage  or  electrolysers,  for  example,  this  is  in  principle  not  allowed  for  system 
operators.  

Indeed, the fundamentals of third-party access and ensuring non-discriminatory treatment will 
become increasingly important as the offshore sector grows. Unbundling is crucial to create a 
level  playing  field  and  to  set  the  right  incentives  for  TSOs  to  take  decisions  independently, 
ensuring transparency and non-discrimination towards network users and as regards extending 
these grids where necessary. Importantly, even under a full ownership unbundling regime, it 
is not only the incumbent TSOs who are allowed to build networks, provided there is separate 
ownership and operation of generation and transmission assets once projects are operational. 
This separation requirement is due to the potential for distorting the market if the transmission 
owner  operates  generation  assets  in  connecting  markets  or  hampering  competition  by 
restricting third-party access to the transmission network.  

There are alternatives to the traditional TSO model (where solely the TSO builds and operates 
the grid) that satisfy the unbundling rules as interpreted and applied by the Commission and 
that  avoid  conflicts  of  interest  or  incentives  for  discriminatory  behaviour.  The  Commission 

6 For example, an industry guide to new market rules was provided in Ireland in 2017:  
   https://www.sem-o.com/documents/general-publications/I-SEM-Industry-Guide.pdf  
7 In order to respond to the shortcomings identified in the 2007 Sector Inquiry and improve the functioning of 
the internal energy market, notably by addressing the problem of systematic network foreclosure through 
generator-owned grid operators, the operation of transmission networks was fully separated from the 
activities of energy supply and generation, thereby opening up European electricity markets to competition, 
innovative business models and increased transparency and oversight. System operators must apply for 
certification as an unbundled operator with their national regulatory authority and the Commission provides its 
opinion on the certification procedure. 

5 

 
 
 
                                                           
has published a staff working paper8 on “Ownership Unbundling: The Commission’s practice 
in assessing a conflict of interest including in the case of financial investors” to set out these 
alternatives  in  more  detail.  One  such  example  is  the  UK’s  Offshore  Transmission  Owner 
(OFTO) regime, which allows project developers to design, install and connect each project to 
shore with its own transmission link. The ownership of the finished cable is then tendered by 
the national regulatory authority (NRA) to a separate transmission operator (or OFTO), which 
can earn a regulated rate of return on the costs of operating these networks. The structure of 
this  model  works  well  and  the  UK  has  seen  a  reduction  in  the  cost  of  building  these 
transmission  cables  due  to  competitive  downward  pressure.  Recent  opinions  issued  by  the 
Commission on certification have highlighted concerns about  the tenders awarded to  OFTO 
companies  that  also  have  a  commercial  interest  in  the  electricity  market  and  potentially  an 
ability to exert their influence on that market9. It is important to note that offshore wind assets 
in  particular  are  often  considerable  in  size  and  could  therefore  have  a  significant  market 
impact.  This is something that the Commission continues to follow closely.   

It  is  currently  not  clear  whether  the  benefits  of  a  model  where  the  investor  builds  both  the 
generation  asset  and  the  grid  or  the  planned  deployment  undertaken  by  the  national  TSO  is 
more  conducive  to  the  scale  of  the  decarbonisation  challenge.  The  former  may  result  in  a 
speedier build-out due to less of a need to coordinate between stakeholders, though the latter 
may result in better optimisation in a limited maritime space and potentially more deployment 
than  a  project-by-project  approach.  The  Commission  will  continue  to  monitor  the 
performance of all approaches, including the degree to which they help bring to market new 
solutions such as HVDC and digital services as well as storage and conversion investments. 

In the longer term and looking ahead to the development of meshed and integrated offshore 
grids, models that work well in other sectors or geographic regions could also be considered. 
For example, a group of TSOs could plan, build and operate meshed assets, with support from 
the  competent  Regional  Coordination  Centre.  They  could  propose  the  bidding  zone 
configuration,  including  designating  a  TSO  to  manage  the  bidding  zone(s),  and  relevant 
NRAs and Member States would approve the deployment plans. Today this way of working is 
established  practice  when  Member  States  build  interconnectors  between  countries,  but  it 
would be a more complex model, with more parties involved, additional responsibilities and 
operational tasks to be carried out by a designated TSO. Alternatively, a common model used 
often in the US is that of an Independent System Operator (ISO)10. In Europe, it would mean 
relevant  Member  States  or  relevant  system  operators  setting  up  an  ISO  together  to  develop 
and  operate  offshore  assets  in  a  well-coordinated  manner,  including  managing  the  bidding 
zone and ensuring operational security. Commercial parties would own the infrastructure and 

8 https://ec.europa.eu/transparency/regdoc/rep/10102/2013/EN/10102-2013-177-EN-F1-1.PDF  
9 The Commission has remarked that, given the increasing share of renewable electricity production and the 
increasing importance of energy storage solutions, the accumulation of smaller generation capacities should be 
fully taken into account when assessing whether there is an incentive and ability for a shareholder in a TSO to 
influence the TSO’s decision-making to the detriment of other network users.   
https://ec.europa.eu/energy/sites/ener/files/documents/2019_157_walney_uk_en.pdf  
10 PJM, ISO New England, CAISO, for example. This should not be confused with the ISO model under the EU 
Electricity and Gas Directives. 

6 

 
 
                                                           
receive a regulated return.  Such a model is also used for gas infrastructure in the North Sea 
region. This model could be used on a multilateral basis in the electricity sector, in a way that 
is fully compliant with unbundling requirements.  

c) Cross-border electricity trading through an offshore hybrid asset 

The free flow of electricity across the European Union is key to achieving secure, affordable 
and  clean  energy  for  EU  citizens  and  businesses.  To  support  the  integration  of  electricity 
markets,  increase  flexibility  and  ensure  that  larger  volumes  of  renewable  energy  can  be 
connected  over  wider  areas,  billions  of  euro  are  spent  each  year  on  cross-border 
interconnection projects. This is primarily paid for by European consumers through tariffs on 
their electricity bills,  but also  with  significant  EU funding.11  It  is  important  that,  once built, 
interconnectors  between  EU  Member  States  are  used  in  the  most  efficient  way  possible  to 
deliver  the  intended  benefits  to  consumers,  to  support  a  greener  electricity  system  and  to 
ensure that all Member States can rely on imports to support security of supply when needed. 
This should also apply to interconnectors combined with renewable generation assets (hybrid 
projects). 

In the EU, the schedules for cross-border trading are calculated through a joint process known 
as market coupling. Market coupling uses bidding zone prices, which have been calculated via 
marginal  pricing,  combined  with  cross-border  grid  constraints  to  determine  the  trade  flows 
between transmission systems. These bidding zones (or price zones) are market areas within 
which  electricity  must  be  able  to  flow  freely  without  encountering  structural  congestion. 
Therefore, there is a single wholesale electricity price within a bidding zone. When there are 
differences in prices in neighbouring bidding zones, the electricity trade flows from the lower 
to higher priced zone.   

In  the  past,  there  have  been  problematic  cases  of  TSOs  closing  their  borders  to  electricity 
imports, even renewable electricity imports, in a structural way to manage congestion within 
their own control areas12.  This runs counter to key principles of the Treaty on the Functioning 
of  the  European  Union  (TFEU)  regarding  electricity  market  design,  which  include  the 
principles of the free movement of goods and non-discrimination between internal and cross-
zonal  exchanges. Any such action may  also  be  considered  contrary to  the competition  rules 
enshrined in the Treaty, in particular Article 102 TFEU. These principles and rules deriving 
from the TFEU apply to the electricity sector and are specifically set out in Article 16 of the 
Electricity Regulation, which obliges TSOs to maximise the available capacity for trade and 
to ensure non-discrimination between internal and cross-zonal exchanges.  

11 From the Commission alone, the total grant budget to support energy projects for the 2014-2020 period 
under the Connecting Europe Facility Energy programme was €4.7 billion. 
12 See, for example, the recent Commission Decision on case AT 40461 DE/DK Interconnector: 
https://ec.europa.eu/competition/antitrust/cases/dec_docs/40461/40461_462_3.pdf  

7 

 
 
 
                                                           
Article 16 of the Electricity Regulation also sets an explicit target for cross-zonal trade. The 
rules  state  that  TSOs  can  make  no  more  than  30%  of  deductions  from  the  interconnector 
capacities13. The rest (a minimum 70% of capacity) should be made available for trade. This 
gives  TSOs  the  flexibility  to  make  deductions  for  specific  reasons,  namely  loop  flows, 
internal  flows  and  reliability  margins,  and  ensures  that  there  is  a  guaranteed  minimum 
capacity  available  for  trade  applying  to  all  Member  States  from  January  2026  at  the  latest. 
These rules are crucial for the proper functioning of the EU electricity market, as electricity 
must be able to flow to where it is most needed without undue barriers. 

Furthermore, all renewable energy projects, both offshore and onshore, should have fair and 
non-discriminatory access to the transmission network and electricity markets14. Therefore, in 
order  to  keep  the  transition  affordable  and  to  ensure  fair  competition,  it  is  crucial  that 
renewables  are  fully  integrated  into  the  electricity  market  in  a  non-discriminatory  manner. 
The competition, trade and export of electricity generated from renewable sources, based on 
demand  and  supply  rather  than  on  pre-defined  flow  patterns,  is  crucial  to  the  effective 
functioning of the internal energy market and to achieve the EU’s decarbonisation goals.  

2. Offshore bidding zones – a way forward  

a) The concept of offshore bidding zones  

The current approach to onshore renewable generation, where generation is considered part of 
an existing ‘home’ electricity market,  is  not  well suited to  offshore hybrid projects,  and not 
conducive to the large scale-up necessary to achieve our climate objectives. This is because, 
in  line  with  the  principle  of  non-discrimination  of  cross-zonal  flows,  hybrid  projects  would 
either need to be curtailed to allow imports and exports over the interconnectors, or the cables 
would need to be oversized to make capacity available for trade. In principle, the integration 
of high volumes of offshore renewable energy generation will be difficult if hybrid projects 
need  to  rely  on  exemptions  or  derogations  under  EU  law15.  Long-term  projects  require  a 
predictable and conducive legal and regulatory framework to  allow them to expand and up-
scale. However, individual projects may exceptionally qualify for exemptions or derogations, 
which require case-by-case approvals. 

To achieve cost-effective decarbonisation and to provide a level playing field for all forms of 
energy  generation  and  demand  response,  it  is  the  Commission’s  view  that  establishing 

13 The capacity offered can be reduced for specific reasons, namely loop flows, internal flows and reliability 
margins up to a maximum of 30%. The rest of the capacity (minimum 70% of capacity) should be made 
available for trade by offering it to the Regional Coordination Centre for capacity calculation – where further 
deductions for the N-1 standard and transit flows are possible. See Article 16 of the Electricity Regulation. 
14 Non-discrimination and fair competition are fundamental market principles. See Article 3 of Regulation (EU) 
943/2019. 
15 The Commission notes in this context that it has received a derogation request under Article 64 of the 
Electricity Regulation for the Kriegers Flak project, which is an offshore wind installation connected to both the 
German and Danish markets. A request was submitted in July 2020 for a derogation from certain articles in the 
Electricity Regulation.   

8 

 
 
 
                                                           
offshore  bidding  zones16  provides  a  good  approach  to  ensure  compliance  with  the  cross-
border  trading  rules.  Modelling  results  and  a  detailed  assessment  of  the  available  options17 
show that, from the models under discussion, offshore bidding zones achieve a higher degree 
of overall efficiency than the ‘home zone’ approach. This is because they lower costs to TSOs 
due  to  a  reduced  need  for  after-market  corrective  action,  they  support  regional  security  of 
supply and system operation by ensuring that electricity flows to where it is most needed, and 
they are more future-proofed to cope with a large up-scale of offshore projects. The extent of 
the benefits depends on the degree to which lower priced trade is displaced and the extent of 
the resulting costs to TSOs and consumers for correcting inefficient market outcomes.  

An offshore bidding zone ensures that generation from the offshore project is fully integrated 
into the market, that the total volume of energy generation can be exported from its own zone 
and dispatched according to market coupling schedules throughout Europe.  

The offshore bidding zone approach is better suited to a large scale-up of offshore renewable 
energy as it ensures that renewables can be fully integrated into the market. In the short term, 
it  ensures  that  offshore  generation  can  flow  to  where  it  is  needed,  becoming  part  of  the 
electricity  schedules  and  supporting  regional  security  of  supply  rather  than  becoming 
something for which TSOs have to correct, which limits how much can be deployed. This will 
become  increasingly  important  as  the  share  of  renewable  energy  increases  and  becomes  the 
backbone  of  our  electricity  system  and  we  move  towards  climate  neutrality  by  2050. 
Furthermore,  this  model  does  not  discriminate  in  favour  of  technology  types,  it  is  fully 
compliant  with  competition  law  and  therefore  provides  the  legal  certainty  needed  for  long-
term  and  large-scale  projects.  In  the  medium  to  longer  term,  offshore  bidding  zones  create 
locational  incentives  for  the  installation  of  new  demand,  e.g.  for  storage  or  green  hydrogen 
production via electrolysis.  

However,  offshore  bidding  zones  can  result  in  a  changed  incentive  structure.  Modelling 
results indicate that a redistribution of parts of the revenue from offshore generation assets to 
transmission  system  operators  can  be  expected.  The  extent  of  redistribution  depends  on  the 
topology. Based on a recent study18, for over half of the projects, the redistribution accounts 
for  less  than  1%  of  total  revenue,  but  for  a  small  share  of  projects,  this  can  rise  to  11%  of 
revenue. This redistribution effect needs to be addressed to ensure that projects beneficial for 
society can be carried out. This is discussed in more detail further on in this paper in section 
III.   

16 It should be noted that offshore bidding zones can also include near-shore onshore areas. Bidding zones 
should be based on where congestion occurs, so if the congestion occurs when transporting electricity further 
from the shore, the areas before the congestion could be seen as part of the offshore zone, thereby 
incentivising investment in electricity intensive demand in those areas. 
17 Market Arrangements for Offshore Hybrid Projects in the North Sea (Thema Report 2020-11) 
https://data.europa.eu/doi10.2833/36426 
18 Market Arrangements for Offshore Hybrid Projects in the North Sea (Thema Report 2020-11) 
https://data.europa.eu/doi10.2833/36426 

9 

 
 
                                                           
Offshore bidding zones could also be an appropriate solution for NRAs and TSOs at national 
level,  even  when  offshore  projects  are  connected  radially  to  the  home  market.  This  can 
happen, for example, if there is insufficient transmission capacity to take the electricity from 
the coast to cities further inland due to delays in permitting procedures or due to the practice 
of not building capacity for the few peak hours of wind. An offshore bidding zone would give 
the right price signal and can give incentives for demand such as power-to-gas technology to 
be located close to offshore generation. Without a separate bidding zone, a TSO may need to 
curtail offshore wind generation and re-dispatch power plants closer to the cities, which is not 
efficient. A separate bidding zone offshore could help ensure that the market only dispatches 
the required amount of electricity. 

Offshore  bidding  zones  are  adaptable  and  can  be  scaled  up  over  time.  An  important 
consideration is that the transmission network to connecting markets should be suitably sized 
to  ensure  that  the  electricity  can  flow  to  the  onshore  network.  For  example,  if  extra  wind 
farms  are  added  to  an  offshore  bidding  zone,  the  connected  markets  will  only  benefit  if 
additional  cables  are  laid  to  increase  transmission  capacity.  Demonstration  projects,  either 
demand  or  generation,  can  also  be  situated  in  offshore  bidding  zones19.  For  generation 
projects, the importance of ensuring the right level of transmission capacity remains crucial. 
Demonstration  projects  that  provide  increased  flexibility  (via  storage,  for  example)  in 
offshore  bidding  zones  can  take  full  advantage  of  direct  access  to  affordable  offshore 
generation and contribute to an optimal usage of the offshore network. 

Finally,  in  order  to  deliver  the  full  benefits  to  consumers  and  to  ensure  that  borders  remain 
open for the import and export of renewable electricity, it is crucial (as explained in section 
I(c)) that TSOs make the maximum capacity, in line with the secure operation of the system, 
available to offshore energy producers for trade over the interconnectors.  

b) Establishment and governance of offshore bidding zones  

Bidding zones, as explained above, are market areas within which there is a single wholesale 
electricity price. The bidding zone price varies from zone to zone due to different patterns of 
energy generation and demand. These price differences are the signals for trade, determining 
the direction of power flows, i.e. if electricity is scarce in a zone, the price rises and imports 
follow.  The  70%  minimum  target  for  trade,  as  described  above,  applies  to  bidding  zone 
borders. Largely for historical reasons and the gradual integration of the EU electricity system 
over  time,  bidding  zones  have  tended  to  follow  country  borders,  rather  than  the  underlying 
physical reality of the grid, although this is not always the case. 

Establishing  new  offshore  bidding  zones  for  renewable  energy  projects  connected  to  more 
than one market, potentially across national borders, raises questions about how these zones 
should  be  established  and  regulated  and  how  system  operation  should  be  carried  out. 
Although  new  in  an  offshore  context,  European  TSOs  and  NRAs  already  have  substantial 

19 A demonstration project in an offshore bidding zone may be granted priority dispatch and an exemption 
from balance responsibility in line with the Electricity Regulation.  

10 

 
 
                                                           
experience in dealing with these issues and research conducted on behalf of the Commission 
indicates that suitable governance arrangements can be made under current legislation20. None 
of the options set out below, require making legislative changes.  

At  national  level,  offshore  bidding  zones  that  do  not  cross  national  boundaries  can  be 
governed  under  the  current  domestic  arrangements.  The  Nordic  countries  and  Italy  have 
considerable  experience  where  TSOs  manage  several  bidding  zones  at  national  level.  For  a 
multinational  zone, regulatory  governance could  be provided for through  NRA cooperation, 
possibly institutionalised in a joint committee. Real-time system operation could be supported 
through  the  use  of  TSO  service  and  cost-sharing  agreements  with  action  coordinated  at 
regional  level  by  the  relevant  Regional  Coordination  Centre.  In  both  cases,  these 
arrangements  are  possible  under  existing  legislation  and  the  experience  of  the  Irish  Single 
Electricity Market and other cross-border bidding zones is very useful.  

A  regulatory  process  to  establish  bidding  zones  already  exists.  It  is  the  Commission’s  view 
that  appropriate  governance  arrangements  for  offshore  bidding  zones  can  be  made  by 
applying existing legislation and procedures.  

Establishment of a new bidding zone 

For  the  establishment  of  a  new  bidding  zone,  two  pieces  of  legislation  are  relevant:  the 
Electricity  Regulation  (EU)  943/2019  and  the  Guideline  on  Capacity  Allocation  and 
Congestion Management 1222/2015 (CACM). The detailed procedures and requirements are 
set  out  in  Articles 32  and  33  of  CACM  and,  in  all  cases,  the  level  of  coordination  and 
consultation  with  neighbouring  TSOs  depends  on  how  big  an  impact  reconfiguring  the 
bidding zones is likely to have on their bidding zones. Following the entry into force of the 
Electricity  Regulation,  a  pan-European  bidding  zone  review  was  launched.  Nonetheless,  as 
clarified in Recital 19 of the Electricity Regulation, it is still possible to launch a national or 
regional bidding zone review in accordance with existing procedures in CACM. 

At  national  level,  if  there  is  a  negligible  impact  on  a  neighbouring  TSO’s  control  area,  a 
single  NRA  or  TSO  with  the  approval  of  its  competent  NRA  can  launch  a  bidding  zone 
review  with  a  view  to  amending  the  existing  configuration  in  its  own  control  area.  In  this 
case, the relevant TSO and NRA must give prior notice of the planned review to neighbouring 
TSOs and be fully transparent on the reasons and conditions of the review. The results of the 
review  must  be  published  and  if  the  result  is  a  proposal  to  amend  the  bidding  zone 
configuration,  this  must  also  be  published.  Given  that  each  bidding  zone  is  located  in  a 
Capacity Calculation Region (CCR), the next step is to update the list of borders in that CCR 
to  account for the new offshore bidding zone. The TSOs  of the CCR should  update the list 
and then send it to the relevant NRAs for approval.   

20 Market Arrangements for Offshore Hybrid Projects in the North Sea (Thema Report 2020-11) 
https://data.europa.eu/doi10.2833/36426 

11 

 
 
 
                                                           
For  a  bidding  zone  review  with  a  regional  impact,  CACM  also  sets  out  how  to  launch  the 
review  and  the  detailed  procedures  to  follow  in  Articles  32  and  33.  Broadly  speaking,  the 
process is as follows:  

  The  participating  TSOs  must  develop  the  methodology,  assumptions  and  alternative 
bidding zone configurations and submit these to  participating NRAs. Once approved 
by  NRAs,  the  bidding  zone  review  must  be  conducted  in  line  with  the  criteria  and 
process set out.  

  The final proposal on whether to amend the bidding zone configuration is sent to the 
participating  Member  States  (or  designated  competent  authority)  for  an  agreement 
within six months. 

The Electricity Regulation (EU) 943/2019 adds the following points to the CACM process:  

 

 

the timeframe assessed in the bidding zone review should be three years; 

there  are  now  strengthened  governance  arrangements  and  the  EU  Agency  for  the 
Cooperation  of  Energy  Regulators  (ACER)  can  decide  if  the  NRAs  do  not  agree  on 
the  methodology,  assumptions  and  alternative  bidding  zone  configurations  as 
proposed by the TSOs;  

  There are also strengthened governance arrangements for the decision-making process 
following the review. The Electricity Regulation requires the report to be submitted to 
‘relevant Member States or their designated competent authorities’ for a decision. The 
relevant  Member  States  are  those  participating  in  the  review  and  those  in  the  same 
CCR as the affected bidding zones.   

Therefore, in order to establish an offshore bidding zone following a review, Member States 
in a CCR have six months to agree whether and how to proceed21.  In addition, the TSOs must 
update the list of borders contained in a CCR and send it to NRAs for approval in line with 
established  procedure.  The  Regional  Coordination  Centre  coordinating  TSO  actions  in  the 
new offshore bidding zone will be the one responsible for that specific CCR.  

Governance of a new bidding zone 

…at national level 

For  new  bidding  zones  established  at  national  level  in  the  exclusive  economic  zone  of  one 
Member State, the governance arrangements are relatively straightforward. Most EU Member 
States have one TSO responsible for system operation, and this TSO would be responsible for 
the  new  bidding  zone.  Many  TSOs  already  have  extensive  experience  of  managing  several 

21 In the event that Member States fail to reach agreement, the decision is automatically escalated to the 
Commission in line with the process set out in Article 14 of the Electricity Regulation.  

12 

 
 
 
                                                           
bidding zones, for example, TERNA in Italy, Energinet in Denmark and Svenska Kraftnät in 
Sweden.  The  regulatory  oversight  flows  directly  from  this  arrangement.  The  NRA  in  that 
Member State would supervise the establishment and operation of new bidding zones by the 
TSO and issues such as market monitoring would fall under the remit of the competent NRA. 
Again, experience from Italy, Denmark and Sweden is a useful blueprint. 

…at multinational level 

At  multinational  level,  various  levels  of  cooperation  and  governance  arrangements  can  be 
envisaged when exploring how to manage a cross-border bidding zone. Existing examples of 
multinational bidding zones in the EU today provide a good starting point. For example, the 
past German-Austrian-Luxembourgish bidding zone, the existing arrangements governing the 
German-Luxembourgish  bidding  zone  and  the  experience  of  the  all-island  integrated  Single 
Electricity Market in Ireland. 

For an offshore bidding zone located in the exclusive economic zone or territorial waters of 
more  than  one  Member  State,  Member  States  and  their  competent  NRAs  can  decide  on  the 
most efficient arrangements and how close and how formal they would like the cooperation to 
be.  For  example,  one  option  is  to  appoint  a  TSO  (permanently  or  on  a  rotating  basis)  to 
perform the system operation for the bidding zone and take on all related responsibilities. This 
would be formalised in TSO service and cost-sharing agreements, under the supervision of the 
competent  NRAs.  Specifically  for  the  offshore  bidding  zone,  NRAs  would  also  need  to 
cooperate in order to take joint decisions, to the extent needed, on issues such as applicable 
tariffs  and  the  grid  connection  regime.  Austrian,  German  and  Luxembourgish  NRAs  had  a 
positive  experience  of  informal  cooperation  in  achieving  coordination  and  cooperative 
decision  making  in  relation  to  the  regulation  of  the  Austria-Germany-Luxembourg  bidding 
zone. Their experience in the context of a larger and more complex bidding zone suggests that 
such informal cooperation can work successfully under existing EU law. 

It  is  too  soon  to  say  whether  more  formal  governance  arrangements  in  an  offshore  bidding 
zone are needed but this will become apparent over time. For example, as offshore renewable 
projects  expand,  begin  to  include  demand,  and  link  up  to  other  offshore  hubs  or  additional 
Member  States,  the  challenges  might  be  better  addressed  through  dedicated  processes  for 
decision  making  and  governance.  If  this  need  arises,  formalised  arrangements  for  joint 
decision making could be arranged on the basis of delegated authority from the NRAs. This 
approach would not necessarily require transferring legal authority to a multilateral body.  

One example of institutionalised NRA cooperation cited in the study by THEMA, is the Irish 
Single  Electricity  Market  (SEM)  Committee.  The  SEM  Committee  oversees  the  joint  Irish 
electricity  market  (spanning 
jurisdictions)  and  has  formal  regulatory 
responsibility for the following: 

two  separate 

  management of the applicable Trading and Settlement Code; 

 

the  Market  Monitoring  Unit  (which  monitors  compliance,  notably  in  relation  to 
market power abuses); 

13 

 
 
 

the Market Modelling Group; and 

  Single Market Operator Regulation. 

All regulatory matters that do not fall under the above scope remain the responsibility of each 
of the respective NRAs. The Committee consists of three members from the Republic’s NRA, 
two members from Northern Ireland’s NRA, and two independent members. 

The NRAs work together through the Committee to harmonise transmission policy and define 
the  systems  and  processes  that  constitute  the  high-level  design  of  the  integrated  electricity 
market. The NRAs continue to be ultimately responsible for regional cooperation but specific 
functions  have  been  transferred  to  the  joint  body,  with  the  agreement  of  the  national 
governments. Under EU legislation, ACER maintains responsibility22 in the event of a dispute 
regarding  relevant  methodologies  and  can  take  a  decision  in  the  event  of  continued 
disagreement.  However,  the  SEM  Committee  provides  a  more  practical  mechanism  to 
undertake ongoing regulatory tasks that cover both NRAs, as well as to support cooperative 
regulatory development as needed. 

The  approach  used  in  the  Irish  market  could  thus  serve  as  a  useful  model  for  NRA 
cooperation as part of a multinational offshore bidding zone. Although the Committee’s work 
is  based  on  bilateral  cooperation,  the  institutional  arrangements  that  it  embodies  could  be 
readily adapted to cover a multinational bidding zone. 

…and for future offshore highly-meshed grids  

As we look ahead to the scale of investment in renewable energy needed to achieve the 2050 
climate neutrality target, and the ambitious plans of Member States to roll out offshore wind 
and other  forms  of tidal  and ocean energy, there  will naturally  be some  maritime areas that 
will  become  physically  crowded,  with  large  volumes  of  offshore  energy  generation.  These 
areas will also experience very specific technical challenges in the types of system operation 
issues  faced,  from  interacting  with  other  renewable  energy  hubs  to  the  difficult  task  of 
managing  large  volumes  of  non-synchronous  generation.  It  is  important  to  note  that 
mechanisms to support TSO coordination already exist. Regional Coordination Centres could 
support  coordination  among  onshore  system  operators  and  their  tasks  are  sufficiently 
adaptable  to  be  tailored  over  time  to  the  needs  of  the  offshore  system.  Article  37(2)  of  the 
Electricity  Regulation  (EU)  2019/943  also  provides  scope  for  assigning  additional  advisory 
tasks to Regional Coordination Centres. 

However,  where  real-time  system  operation  becomes  increasingly  complex  and  intricate,  it 
could  be  warranted  to  take  a  more  holistic  approach  to  future  system  operation  in  offshore 
regions.  The  relevant  group  of  TSOs  could  appoint  one  TSO  to  manage  the  entire  offshore 
area  (possibly  consisting  of  several  offshore  bidding  zones)  or  the  TSOs  and  NRAs  may 

22 ACER’s powers in the Irish context are exclusively those afforded by the applicable European legislation, most 
notably in relation to regional methodologies in the CACM Guideline (2015/1222), the System Operation 
Guideline (2017/1485) and the Electricity Balancing Guideline (2017/2195). 

14 

 
 
                                                           
decide  to  establish  an  independent  system  operator  (ISO)  for  this  purpose,  potentially  as  a 
joint venture. An ISO established for this purpose would build up significant expertise in the 
technical  challenges  associated  with  offshore  DC  infrastructure  and  could  become  a  global 
leader in managing a variable renewables-based electricity system.  

Other benefits could flow from such an arrangement. One or more offshore ISOs would be a 
model case for regional cooperation. An ISO could function as a system architect to develop 
the long-term master plan for offshore meshed grid development, map locations for offshore 
wind,  as  well  as  undertake  the  required  grid  investments  needed  for  Europe-wide  grid 
optimisation.  It  would  provide  scope  for  the  relevant  NRAs  to  assess  in  a  neutral  and 
coordinated way the best type of incentive regime and tariff design for a variable renewables-
based electricity system. It would also have the advantage of solving coordination challenges 
and could help de-risk anticipatory investments. At the same time, close cooperation between 
the  ISO  and  onshore  TSOs  would  remain  necessary,  e.g.  to  ensure  sufficient  transmission 
capacity onshore at the designated landing points for offshore cables. 

It is highly likely that the governance arrangements for a multilateral  ISO would need to be 
formalised, along the lines of the arrangements outlined above for multilateral bidding zones, 
or  ACER,  as  the  existing  body  for  cooperation  between  European  NRAs,  could  potentially 
take  on  the  regulatory  function.  This  structure  could  be  complemented  by  a  regional 
regulators' forum  and, at governmental  level,  a high-level  ministerial  regional  energy policy 
forum.  

c) Conclusion on offshore bidding zones 

Offshore bidding zones provide the long-term legal certainty required by hybrid projects and 
are  currently  considered  the  most  efficient  and  affordable  way  for  consumers  to  integrate 
large-scale offshore renewables into the system.  

They also support system security and have additional benefits by ensuring reliable access to 
imports  and  potential  incentives  for  efficient  investments.  It  is  already  possible  under  the 
current  regulatory  framework  of  the  Clean  Energy  Package  to  establish  offshore  bidding 
zones and to make suitable governance arrangements. Even more far-reaching solutions, such 
as the establishment of  offshore  ISOs,  are in  principle possible under the current  legislative 
framework. Different approaches can, to a large extent, co-exist. However, in the long term, 
and with the significant build-up of offshore renewable generation expected and necessary to 
achieve the EU’s climate objectives, the offshore bidding zone approach appears well suited. 
This  being  said,  it  should  also  be  acknowledged  that  this  approach  does  have  an  impact  on 
renewable energy developers, most notably in relation to price dynamics.  

15 

 
 
 
 
 
 
3) Price dynamics and links with support schemes 

As  explained  in  the  section  on  offshore  bidding  zones,  if  the  offshore  zone  contains  only 
renewable energy generation and no demand, the price in that zone will depend on the level of 
demand from the markets to which it is connected.  In addition, offshore generation will need 
to  compete  with  connecting  markets  in  order  to  ensure  that  it  is  in  the  merit  order  and 
dispatched,  under  the  principle  of  marginal  pricing  and  the  market  coupling  process,  which 
has worked well for onshore electricity markets for years.  

However, this provides challenges for offshore electricity producers. Stakeholders have raised 
concerns,  which  have  been  recognised  in  supporting  studies  for  the  Commission,  that  since 
the  offshore  bidding  zone  price  will  be  dependent  on  demand  on  connected  markets,  prices 
will be volatile, revenue may be lower and the volumes to be sold more uncertain. It is also 
true  that  these  are  significant  long-term  investments  and  additional  risks,  such  as  price 
volatility  and  uncertainty  about  the  evolution  of  negative  price  periods  can  increase  overall 
project costs and reduce the attractiveness of such projects for investors. Any support schemes 
for offshore hybrid projects should take this into account. It is necessary to address separately 
the  rules  for  a  functioning  electricity  market,  which  apply  to  all,  and  specific  schemes  to 
provide support for certain forms of energy production in the form of State aid.  

4) Networks and connection regimes 

It is important to emphasise that the points made above cannot be considered in isolation. The 
European market framework is a blend of rules set at EU and national level, the combination 
of which will shape the overall environment for renewable energy in that Member State. For 
offshore  hybrid  projects,  network  planning  and  the  interaction  of  the  tariff  design  with 
national support schemes are particularly important. 

The social welfare benefits in developing hybrid projects and considerably scaling up offshore 
renewable energy with more meshed offshore grids may not be fully achieved unless onshore 
network  planning  and  deployment  can  keep  pace  with  offshore  developments.  It  will  be 
crucial to bring the electricity onshore to strong, well-connected parts of the grid and ensure 
that  reinforcements  to  the  onshore  network  allow  the  offshore  renewable  electricity  to  be 
transported from the coast to consumers. Well-designed onshore and offshore bidding zones 
that  are  aligned  with  structural  congestion  in  the  grid  should  be  ensured  and  they  can  also 
provide  investment  signals  for  power-to-gas  installations  or  incentives  for  major  energy 
consumers to locate near the coast to benefit from lower electricity prices.      

The tariff design and the charges applicable to producers, including for connection, are also 
essential for the overall business case. The tariff design should provide incentives for efficient 
network use but must also provide for the financing and cost recovery of the grid connection. 
Currently, there are significant differences between the applicable tariffs and charges, which 
could  hamper  cooperation  between  Member  States  in  joint  cross-border  projects.  There  are 
broadly  three  types  of  connection-charging  regimes:  ‘deep’  connection  charging  (producers 

16 

 
 
 
pay  for  the  cost  of  their  connection  to  the  nearest  grid  and  for  the  cost  of  reinforcements), 
‘shallow’ connection charging (producers only pay for connection to the grid, while the TSO 
pays for reinforcements) and ‘extra shallow’ charging (the TSO pays for both connection and 
reinforcements). What is apparent is the strong link between the socialisation of certain costs 
through  grid connection regimes and the clearing  price of renewable energy auctions across 
Member States. Those with deep connection charging have higher bidding prices than those 
with shallow connection charging. This is because consumers do not pay for the connection 
and this cost is factored in by the developers in their bid.  

The  advantages  of  a  deep  charging  regime  could  be  a  lower  risk  that  the  connection  is  not 
provided on time through better coordination and sequencing from the developer. In addition, 
for  joint  projects  by  Member  States,  a  greater  share  of  the  total  cost  is  factored  into  the 
project, which may make cost sharing easier. By contrast, a shallow charging regime has the 
benefit that the TSO can write off the network connection over a longer period and the cables 
can be reused for future projects.  

Assuming that cost-sharing arrangements can be solved between NRAs, on balance, shallow 
charging may be better suited to areas that use pre-developed or clearly designated sites for 
offshore  projects.  Deep  charging  may  be  better  suited  to  systems  where  developers  have  a 
choice  of  sites  and  it  may  be  beneficial  to  provide  incentives  to  factor  in  the  network  cost 
impact of different sites. What is clear is that close coordination of national policies on tariffs 
and charges by NRAs will be needed to enable these projects to come forward. Currently, the 
rules  at  EU  level  on  these  aspects  are  very  limited,  and  harmonisation  would  require  a 
voluntary alignment of national rules for the offshore bidding zone.   

III. Possible adaptation of EU market rules  

a) Congestion income 

Congestion  income  is  the  price  differential  between  markets  that  TSOs  receive  as  income. 
This income must be spent on the priority objectives of reducing congestion by maintaining or 
increasing interconnection capacity, in line with Article 19 of the Electricity Regulation. For 
renewable  electricity  projects  in  offshore  bidding  zones,  the  value  of  a  hybrid  asset  is  split 
between the electricity market revenues and congestion income.  

In  a  more  integrated  meshed  grid  that  supports  competition  and  price  convergence,  it  is 
currently unclear how the levels of congestion rents will evolve. For example, there is a high 
correlation  between  wind  generation  in  northern  Europe  and  lower  electricity  prices. 
However,  it  is  clear  that  in  an  offshore  bidding  zone  configuration,  there  will  be  a 
redistribution  of  part  of  the  revenue  from  offshore  electricity  producers  to  transmission 
system operators. The extent of this depends on the topology of the project. For over half of 

17 

 
 
 
 
the projects, the redistribution effect is expected to account for less than 1% of total revenue, 
though for a small share of projects, this can be up to 11% of revenues23. This effect needs to 
be  addressed  to  ensure  that  the  total  value  of  viable  hybrid  projects  can  be  captured  and  to 
align the incentives to encourage these projects where they are beneficial to society.  

A way to align these incentives could be an amendment to the rules on the use of congestion 
income. For example, by opening up the possibility for Member States and NRAs to allocate 
congestion  income  to  renewable  energy  producers  active  in  an  offshore  bidding  zone,  this 
could ensure that hybrid projects are no less attractive for a renewable energy investor. There 
are three main benefits to this approach: it could reduce the level of subsidies needed through 
support  schemes,  it  could  enable  a  transition  for  producers  to  market  participation  once  the 
support  scheme  ends,  and  it  could  limit  the  need  for  support  schemes  entirely  by  enabling 
projects to come forward in a market-based way.   

A further risk to note in the context of hybrid projects is that, if offshore energy generation is 
expanded  but  the  corresponding  interconnection  cables  are  not  built  to  schedule,  it  would 
result in limited interconnection capacity, and the offshore price could be close to zero until 
this  congestion  is  relieved.  In  these  cases,  congestion  income  would  be  very  high  for  a 
temporary period resulting in a form of redistribution from generation to TSOs. Where those 
congestion  rents  are  used  to  increase  the  missing  interconnector  capacity,  they  address  the 
core  of  the  issue,  thereby  helping  to  integrate  offshore  wind.  However,  interconnection 
projects can also incur significant delays for multiple reasons.   

For these reasons, the Commission will explore the scope to grant a degree of flexibility by 
carrying  out  a  legal  revision  of  the  rules  governing  the  allowed  use  of  congestion  rents,  to 
enable a partial transfer of congestion income for hybrid projects. Possible approaches to this 
include  making  changes  to  financial  transmission  rights,  auction  revenue  rights  or  support 
scheme design, as outlined in supporting studies for the Commission24. The Commission has 
not reached a conclusion on this issue. However, a partial transfer of congestion income could 
strike a good balance to  encourage market-based investments and still ensure that TSOs are 
remunerated  for  making  interconnection  capacity  available  for  trade.  Therefore,  the 
Commission will put forward a proposal for this purpose at the latest by 2022.  

b) Technical connection requirements for offshore HVDC grids 

The EU framework for connecting to the electricity grid is set out in three network codes: the 
Requirements  for  Generators  (Commission  Regulation  (EU)  2016/631),  the  Demand 
Connection Code (Commission Regulation (EU) 2016/1388) and the Network Code on High 

23 Market Arrangements for Offshore Hybrid Projects in the North Sea (Thema Report 2020-11) 
https://data.europa.eu/doi10.2833/36426 
24  THEMA Consulting has suggested ways that this could be addressed in research conducted on behalf of the 
Commission. Market Arrangements for Offshore Hybrid Projects in the North Sea (Thema Report 2020-11) 
https://data.europa.eu/doi10.2833/36426 

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Voltage  Direct  Current  Connections  (Commission  Regulation  (EU)  2016/1447).  One  of  the 
key findings from the PROMOTION study is that these codes were written with the onshore 
network mostly in mind. Even the HVDC Network Code focuses on supporting the onshore 
AC grid  rather than  an interface  with  an offshore DC  electricity  grid.  Therefore, one of the 
recommendations  of  the  study  is  to  streamline  the  technical  connection  requirements  for 
generators and HVDC cables in order to speed up the connection of offshore projects where 
multiple parties and Member States are concerned.  

The current EU framework provides for a significant degree of national flexibility for TSOs to 
set requirements. In a study conducted on behalf of the Commission, Tractabel analysed these 
requirements with a view to creating best practice for technical connection requirements for 
offshore HVDC grids in the North Seas region25. Where justified, it proposed setting common 
requirements for certain aspects. This study can be a useful tool for Member States and TSOs 
when considering the specifications for common projects.  

In addition, it would be beneficial to the deployment of offshore renewables projects  across 
the EU to amend the network codes and set common EU standards for some technical aspects. 
Expert groups are currently working on amendments to the grid connection network codes26 
as  part  of  the  ongoing  work  in  the  Grid  Connection  European  Stakeholder  Committee.  The 
Commission  will  share  the  results  of  this  study  with  the  relevant  experts  to  ensure  that  the 
findings and recommendations of this report are taken on board in the amendment process.  

IV. Conclusions  

Offshore renewable energies can be scaled up in a way that is compatible with EU legislation. 
It is paramount to do so in line with existing EU legislation to achieve the goal of delivering a 
decarbonised  electricity  market  that  is  flexible,  integrated  and  secure,  at  least  cost  to 
consumers.  

In  the  future,  offshore  renewable  energy  projects  are  expected  to  play  a  significant  role  in 
achieving our climate neutrality target. These projects are expected to be built using a blend 
of solutions – both single radial connections and hybrid projects that are connected to more 
than one market.  

In  the  case  of  hybrid  projects,  establishing  an  offshore  bidding  zone  is  a  suitable  way  to 
integrate these projects into the electricity system. In the short term, an offshore bidding zone 
ensures that electricity can flow to where it is most needed, ensuring that offshore renewable 
energy  contributes  to  regional  security  of  supply.  In  the  medium  to  longer  term,  they  also 
provide  price  signals  to  incentivise  the  development  of  storage  and  other  offshore  demand 
facilities. An offshore bidding zone is more efficient overall, as it reduces the need for costly 

25 Technical requirements for connection to HVDC grids in the North Sea (Tractabel Report 2020-11) 
https://data.europa.eu/doi10.2833/493628 
26 https://www.entsoe.eu/network_codes/cnc/expert-groups/  

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TSO corrective actions such as redispatching and countertrading and it keeps costs down for 
consumers.  

However, it should also be acknowledged that although this model is more efficient, it affects 
the  risk  borne  by  project  developers  and  trading  revenue  may  be  lower  due  to  increased 
competition.  This  risk  could  be  mitigated  in  well-designed  support  schemes  for  hybrid 
projects.  Furthermore,  hybrid  projects  can  have  a  redistributive  effect  on  incomes  and, 
depending  on  the  topology  of  the  projects,  can  lower  trading  revenues  while  increasing 
congestion  income.  To  ensure  that  incentives  are  aligned  for  viable  hybrid  projects  coming 
forward  in  a  market-based  way,  the  Commission  will  consider  amending  the  rules  on  the 
spending of congestion income. 

The governance arrangements required for offshore bidding zones are possible under current 
EU  law  and  would  flow  from  the  individual  projects,  ranging  from  a  simple  extension  of 
national  TSO  and  NRA  tasks  to  more  complex  multilateral  arrangements.  Looking  further 
ahead and beyond the deployment of the first hybrid projects, to complex meshed grids, the 
delegation  of  TSO  tasks  to  one  lead  TSO  (including  bidding  zone  management  and 
operational  security)  or  the  creation  of  an  ISO  could  be  an  efficient  and  strategic  regional 
initiative to ensure optimal planning and operation of the offshore grid. However, this is not a 
prerequisite. Multilateral governance arrangements setting out a clear allocation of tasks and 
supervision,  agreed  by  the  Member  States,  NRAs  and  TSOs  concerned  can  be  made  under 
existing legislation. Experience in today’s electricity market indicates that this can work well. 

It is also important to highlight the links with aspects of national law and policy and note that 
the  efficiency  of  network  planning  and  the  socialisation  of  project  costs such  as  connection 
and  site  surveys  all  contribute  significantly  to  the  investment  case  for  projects  and  to  the 
overall  cost  of  offshore  renewable  energy  deployment.  Furthermore,  the  Commission  will 
work  with  the  Grid  Connection  Electricity  Stakeholder  Committee  to  check  that  the  grid 
connection  network  codes  are  suited  to  the  rollout  of  more  meshed  and  complex  offshore 
projects. 

In conclusion, the creation of offshore bidding zones for hybrid projects  provides a suitable 
framework  for  a  massive  scaling  up  of  offshore  renewable  energy,  for  it  to  become  the 
backbone  of  our  energy  system  as  we  move  towards  the  EU’s  2050  objective  to  achieve 
climate  neutrality.  It  provides  the  certainty  required  for  these  long-term  projects  and  strong 
investment incentives to further develop offshore demand, such as storage and the production 
of hydrogen from green electricity. 

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