The regulatory framework for wind energy in EU Member States : part 1 of the study on the social and economic value of wind energy – WindValueEU.
Date: 2015-03-25
Institutions: Institute for Energy and Transport
Subjects: economic value, electrical energy, electricity supply, energy industry, energy supply, energy technology, environmental impact, renewable energy, research report, social impact, wind energy

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The regulatory framework for 
wind energy in EU Member States 

Part 1 of the Study on the social 
and economic value of wind energy 
– WindValueEU 

(ENER/C2/2012-462-1/SI2.671144) 

Javier SERRANO GONZÁLEZ 

Roberto LACAL ARÁNTEGUI 

2 0 1 5  

Report EUR 27130 EN 

 
 
 
 
Cover picture: wind farm at the harbour. © Jos Beurskens. 

European Commission 
Joint Research Centre 
Institute for Energy and Transport 

Contact information 
Javier Serrano González 
Address: Joint Research Centre, Institute for Energy and Transport. Westerduinweg 3, NL-1755 LE Petten, The 
Netherlands 
E-mail: javier.serrano-gonzalez@ec.europa.eu  
Tel.: +31 224 56 51 87 

JRC Science Hub  
https://ec.europa.eu/jrc  

Legal Notice 
This publication is a Science and Policy Report by the Joint Research Centre, the European Commission’s in-house 
science service. It aims to provide evidence-based scientific support to the European policy-making process. The 
scientific output expressed does not imply a policy position of the European Commission. Neither the European 
Commission nor any person acting on behalf of the Commission is responsible for the use which might be made 
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All images except where otherwise indicated © European Union 2015 

JRC93792 

EUR 27130 EN 

ISBN 978-92-79-46032-6  (PDF) 

ISSN 1831-9424 (online) 

doi: 10.2790/282003 

Luxembourg: Publications Office of the European Union, 2015 

© European Union, 2015 

Reproduction is authorised provided the source is acknowledged. 

Please cite this report as follows: 
The regulatory framework for wind energy in EU Member States. Part 1 of the Study on the social and economic 
value of wind energy – WindValueEU. Javier Serrano-González and Roberto Lacal-Arántegui, European 
Commission, Joint Research Centre, Institute for Energy and Transport, March 2015. Available at: 
https://ec.europa.eu/jrc/en/publications-list  

Abstract 

This document is the first deliverable of the study on the social and economic value of wind energy that the Joint 
Research Centre carries out on behalf of Directorate General for Energy. The aim of this  report is to provide an 
updated  overview  of  the  regulatory  framework  for  wind  energy  in  European  Union  Member  States. Three  main 
aspects are covered in this report: support schemes, grid issues and potential barriers for wind energy deployment. 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
JRC Scientific and Policy 
Reports 

Study on the social and economic value of wind 
energy - WindValueEU 

Part 1 

Regulatory framework in EU 
Member States 

Javier SERRANO GONZÁLEZ 

Roberto LACAL ARÁNTEGUI 

Energy Technology Policy Outlook Unit, Institute for Energy and Transport 

Joint Research Centre, European Commission 

 
 
 
 
 
 
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WindValueEU 

Part 1: Regulatory Framework 

Table of Contents 

Table of Contents ..................................................................................................................................... i 

Abbreviations and acronyms ............................................................................................................. iii 

Acknowledgments ................................................................................................................................. iv 

Executive Summary ................................................................................................................................ 1 

1. 

Introduction ...................................................................................................................................... 5 

1.1. 

1.2. 

Literature overview on regulatory framework for wind energy integration ..... 5 

Introduction to support schemes ..................................................................................... 7 

Feed-in tariffs ................................................................................................................... 8 
1.2.1. 
1.2.2. 
Feed-in premium ............................................................................................................ 8 
1.2.3.  Quota system and tradable green certificates (TGC) ........................................ 9 

2.  Overview and comparison of regulatory framework for onshore wind energy ..... 11 

2.1. 

2.2. 

Feed-in tariffs for onshore wind power ........................................................................ 13 

Feed-in premiums for onshore wind power ............................................................... 15 

2.3.  Tradable green certificates and quota obligation for onshore wind power ... 17 

2.4.  Suspension of support schemes and retrospective measures ............................. 20 

2.5.  Secondary support schemes ............................................................................................ 21 

2.5.1. 
2.5.2. 
2.5.3. 

Tax incentives or exemptions .................................................................................. 21 
Investment grants ........................................................................................................ 22 
Low-interest loans........................................................................................................ 23 

2.6.  Grid issues ............................................................................................................................... 24 

2.6.1.  Connection procedure ............................................................................................... 24 
2.6.2.  Connection costs sharing .......................................................................................... 25 
2.6.3.  Operation and use of the grid by wind energy generators .......................... 28 

2.7.  Barriers...................................................................................................................................... 29 

Political and economic framework ........................................................................ 30 
2.7.1. 
2.7.2.  Grid regulation and infrastructure ......................................................................... 31 
2.7.3.  Administrative procedure.......................................................................................... 32 
2.7.4.  Market design................................................................................................................ 33 
2.7.5.  Other potential barriers ............................................................................................. 33 

3.  Overview and analysis of the regulatory framework for offshore wind energy. .... 35 

In-depth analysis of Belgium, Denmark, Germany, the Netherlands and the 

4. 
United Kingdom offshore wind power regulation. ................................................................... 39 

4.1.  Belgium .................................................................................................................................... 39 

4.2.  Denmark .................................................................................................................................. 40 

4.3.  Germany .................................................................................................................................. 42 

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4.4.  The Netherlands .................................................................................................................... 43 

4.5.  The United Kingdom ........................................................................................................... 44 

References ............................................................................................................................................... 47 

ii 

 
 
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Part 1: Regulatory Framework 

ABBREVIATIONS AND ACRONYMS 

Throughout this report, the 2-letter country codes are used as defined by the 
International Organization for Standardization: 
http://www.iso.org/iso/country_names_and_code_elements 
Other abbreviations and acronyms are: 

Contract for difference 

Danish Krone 
European Commission 
European Union 
Feed-in tariff (scheme) 
Feed-in premium (scheme) 
Equivalent full-load hours 
British Pound Sterling 
Grid Operator 
Gigawatt 
Kilowatt 
Low-Carbon Contracts Company 
Member State (of the EU) 
Megawatt 
Megawatt-hour 

CfD 
DG ENER  Directorate General for Energy of the European Commission 
DKK 
EC 
EU 
FiT 
FiP 
FLH 
GBP 
GO 
GW 
kW 
LCCC 
MS 
MW 
MWh 
NREAP  National Renewable Energy Action Plan 
PLN 
PO 
RES 
RON 
RVO 
SEK 
TGC 
VAT 

Polish Zloty 
Plant Operator 
Renewable energy system/source 
Romanian Leu 
Rijksdienst voor Ondernemend Nederland (Netherlands Enterprise Agency) 
Swedish Krona 
Tradable green certificates 
Value-added tax 

iii 

 
 
 
WindValueEU 

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Acknowledgments 

(Netherlands 

The authors would like to extend their gratitude to the following individuals and their 
organisations for reviewing this document and for contributing with their ideas to its 
improvement. These are: Ivo Schmidt (DG ENER), Laura Rol Rua (Iberdrola), André de 
Boer 
Klein 
(Forschungszentrum Jülich, Germany) and Cheung Yuen (Office for Renewable Energy 
Deployment, United Kingdom). We would like to thank in particular Mathias Normand 
and his team from Vattenfall for the very intense effort and the contribution of their 
thorough revision of this report. 

Agency,  Netherlands), 

Enterprise 

Franciska 

iv 

 
 
 
 
WindValueEU 

Part 1: Regulatory Framework 

Executive Summary 

This  document  is  the  first  deliverable  corresponding  to  the  study  on  the  social  and 
economic  value  of  wind  energy.  This  study  is  divided  into  four  parts:  (i)  regulatory 
framework, (ii) wind power technology aspects, (iii) wind energy market status and (iv) 
economic and non-economic impacts of wind energy. The results obtained in the first 
part will be presented in two deliverables: Deliverable 1 (the present document) and 
Deliverable 7, an update to be submitted in August 2016. 

Methodology 

Following the general methodology proposed for this project, a literature review of 
scientific  publications  was  performed.  However,  due  to  the  continuously-evolving 
nature  of  the  regulatory  framework,  some  of  the  conclusions  drawn  from  literature 
review  should  be  contextualised  by  taking  into  account  the  specific  circumstances 
(market as much as regulation) at the time each piece of research was published. In 
order  to  provide  an  updated  picture,  other  sources  different  than  scientific 
publications  were  used,  including  periodically-updated  databases  and  recently-
released policy reports. 

Results 

Feed-in tariffs (FiTs), followed by feed-in premiums (FiP) are the most common support 
schemes  in  EU  Member  States.  FiTs  ensure  a  relatively  high  level  of  security  for 
investors, but FiTs  are  not affected by  market  signals (what has been called  market 
compatibility) which is an essential condition for achieving a high penetration of wind 
energy in the electricity system. This concern made the recent Guidelines on State aid 
for  environmental  protection  and  energy  2014-2020  [67]  to  call  for  higher  market 
compatibility by requiring generators to participate in the electricity market as well as 
by selecting the subsidised remuneration by competitive bidding. In this regard, recent 
changes have taken place in some Member States such as new tendering schemes in 
Italy and France or the new Contract for Difference scheme implemented in the United 
Kingdom. 

This  document  also  explores  other  regulatory  aspects  such  as  grid  connection 
procedures, grid operation requirements, distribution of the connection costs, priority 
access to the grid and balancing responsibilities. Most Member States operate with 
the so-called shallow approach to grid connection costs: the plant developer bears the 
grid extension costs and, if necessary, the grid operator bears the grid reinforcement 
costs1. In the case of offshore wind the ultra-shallow approach (the plant developer 

1 Grid extension refers to the construction of the new electrical infrastructure to connect the new plant 
to the existing grid. Grid reinforcement is referred to as the necessary actions/modifications to the 
existing electricity grid in order to integrate the new wind farm. 

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WindValueEU 

Part 1: Regulatory Framework 

just bears the costs of the wind farm inner electrical infrastructure and substation) is 
the most common way of allocating connection costs. 

Reported barriers to wind energy deployment are also presented in this study. A major 
issue is the number of retroactive and retrospective measures2 that took place in some 
Member States. Long and complex administrative procedures for wind farm projects 
and  grid  connection  as  well  as  increasing  occurrence  of  curtailment  are  also  issues 
commonly reported in some Member States. 

Support schemes, grid connection approaches for sharing the costs, granting of priory 
or guaranteed access to wind power plants, requirement of balancing responsibility by 
wind farms and reported barriers for further wind energy deployment are featured in 
Table 1, where the barriers considered as more severe this is shown in bold. 

Table 1. Summary of wind energy regulatory framework aspects in 2014 

Support 
Scheme 

Grid 
connection 
approach 

Priory/ 
guaranteed 
access 

Balancing 
costs 

AT 

FiT 

Deep 

Yes 

No 

BE 

TGC 

Shallow 

Yes 

Yes 

BG 

FiT 

Shallow 

No 

No 

CY 

FiT 

Deep 

Yes 

No 

CZ 

- 

Deep 

No 

No 

DE 

FiP 

DK 

FiP; 
Tender 
offshore 

Shallow; 
Ultra-
shallow 
offshore 
Shallow; 
Ultra-
shallow 
offshore 

Yes 

Yes 

Yes 

Yes 

EE 

FiP 

Deep 

No 

Yes 

Reported barriers 

Spatial and environmental planning 

 
  Cost of administrative procedure 

  Uncertainty of the support scheme 
 
Long lead time for grid connection 
  Complexity of administrative procedure 
  Retroactive measures 
 
 

Lack of fair and independent regulation 
Lack of transparency on the 
connection procedure 
 
Lack of electricity market competition 
  Complexity of administrative procedure 

  Support scheme cancelled 

Transparency of the connection 
procedure 
Transparency of the administrative 
procedure 

 

  Curtailment 
  Grid development 
 

Spatial and environmental planning 

Lack of reliable support scheme 

 
  Complex connection procedure 
  Complex administrative procedure 

2 Retrospective changes are defined as regulatory changes acting on existing plant that take effect from 
the date of publication of the new norm. On the other hand, retroactive changes on existing plant take 
effect from a previous date. 

2 

 
 
 
                                                        
 
WindValueEU 

Part 1: Regulatory Framework 

Support 
Scheme 

Grid 
connection 
approach 

Priory/ 
guaranteed 
access 

Balancing 
costs 

Reported barriers 

ES 

Tender 

Shallow 

Yes 

Yes 

FI 

FiP 

Deep 

No 

Yes 

FR 

Tender 

Shallow 

No 

No 

GR 

FiT 

Shallow 

Yes 

No 

HU 

FiT; 
Tender-
based 

Shallow 

Yes 

Yes 

HR 

FiT 

Deep 

No 

No 

IE 

FiT 

Shallow 

Yes 

IT 

FiT; 
Tender-
based 

LT 

FiT 

Shallow 

Yes 

Deep-
shallow 

Yes 

No 

No 

No 

LU 

FiT 

Deep 

No 

No 

LV 

MT 

NL 

FiP; 
Tender-
based 

- 
FiP; 
Tender-
based 

Deep 

No 

Yes 

Deep 

Yes 

Shallow 

No 

No 

Yes 

PL 

TGC 

Shallow 

Yes 

Yes 

PT 

Tender 

Shallow 

Yes 

No 

3 

Spatial planning 

Lack of stable support 

Lack of reliable support scheme 

 
  Retroactive measures 
  Grid development 
  Complex administrative procedure 
 
  Complex connection procedure 
  Grid development 
 
  Complex administrative procedure 
 
Long lead time for grid connection 
 
Lack of reliable support scheme 
  Grid development 
  Complexity administrative procedure 
 
Lack of reliable support scheme 
  No call for tenders since 2007 
 

Lack of transparency of the connection 
procedure 

  No new purchase agreements from 

January 2015 

Spatial Planning 

  Cost of connection procedure 
 
  Duration of grid connection procedure 
  Curtailment 

Long lead time for grid connection 

 
  Grid development 

  Reliability of the regulatory framework 
  Complex administrative procedure 
 
Long lead time for grid connection 
 
Existence and reliability of general 
renewable energy strategy and support 
scheme 
Spatial Planning 

 
  Reliability of the regulatory 

framework 
Lack of liberalised electricity market 

 
  Grid development 
  No support scheme for wind energy 
  Reliability of the general RES strategy 
  Grid development 
 
Spatial Planning 
  Reliability of the regulatory framework 
 

Long administrative procedure 
Grid development 

  Reliability of the regulatory 

 

framework 
Long and complex administrative 
procedure 

 
 
WindValueEU 

Part 1: Regulatory Framework 

Support 
Scheme 

Grid 
connection 
approach 

Priory/ 
guaranteed 
access 

Balancing 
costs 

Reported barriers 

 

Long and complex connection 
procedure 

Lack of market competition 

  Retroactive measures 
 
  Grid development 
 

Lack of transparency of the grid 
connection procedure 
Low remuneration level 

 
  Grid development 

  Reliability of the regulatory framework 
  Duration of the administrative process 
 
Spatial and environmental planning 

  Reliability of the general RES-E 
  Transparency of the connection 

 

 

procedure 
Long and costly administrative 
procedure 
Insufficient total budget for large scale 
RES support 

  Costly connection costs 

RO 

TGC 

Shallow 

Yes 

Yes 

SE 

TGC 

Deep 

No 

Yes 

SI 

FiP 

Shallow 

Yes 

Yes 

SK 

FiT 

UK  TGC/CfD 

Deep-
Shallow 

Deep-
Shallow 

Yes 

No 

No 

Yes 

4 

 
 
WindValueEU 

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1. 

Introduction 

The Renewable Energy Directive 2009/28/EC [1] established a European framework to 
promote renewable energy and set mandatory national targets in order to achieve at 
least  a  20  %  renewable  energy  share  in  final  energy  consumption  by  2020.  Each 
Member State (MS) was required to set out the sectoral targets by means of National 
Renewable Energy Action Plans (NREAP). Also, each individual plan had to define the 
technology mix scenario, the trajectory to be followed and the measures and reforms 
to overcome barriers and ensure the deployment of renewable energy. 

As each MS has different objectives and also independent choice of policy support, 
each government set a specific regulatory framework, especially in terms of support 
strategies, but also regarding administrative procedures and access to the grid. In this 
study,  these  three  topics  are  analysed  for  the  particular  case  of  wind  energy,  by 
comparing the individual implementations adopted in each country. 

1.1. 

Literature overview on regulatory framework for wind energy 
integration  

For this study, support schemes have been widely analysed in the existing scientific 
literature.  The  research  that  we  reviewed  can  be  classified  into  two  main  areas:  (i) 
scheme  design—taking  into  account  considerations  such  as  cost  and  risks  for  both 
investors and society— and (ii) analysis on their performance and effectiveness. 

Couture  and  Gagnon  (2010 3)  [2]  presented  the  advantages  and  disadvantages  of 
different design options for feed-in tariffs (FiT) and feed-in premiums (FiP).  Specific 
features, such as inflation adjustment, degression rate and floor or ceiling price are 
analysed by identifying the impact on risk for investors, and overall cost of renewable 
energy deployment. Hiroux and Saguan (2010) [3] discussed how electricity markets 
could be designed in order to host a significant amount of wind energy, concluding 
that wind power producers should be exposed to market signals. To this end, a FiP 
seems to be the most suitable option, since the risk for producers is controlled to some 
extent and renewable generators are exposed to market signals. Kitzing et al. (2012) 
[4] analysed the possible trend to a harmonised regulatory framework within each MS 
and studied the development of support schemes during 2000 – 2011, concluding that 
a slight tendency is observed for a natural, bottom-up convergence. 

Risk implications were studied by Lemming (2003) [5] by analysing how the higher risk 
associated to tradable green certificates (TGC) markets —compared with FiTs— results 
in  higher  income  required  by  investors.  A  similar  conclusion  on  the  relationship 
between risk and return requirements by investors was drawn by Held et al. [6] in 2006. 
Dinica (2006) [7] also focused on the perspective of investors and concluded that it is 

3 The publishing year is indicated for each study, since policy measures are continuously evolving and 
conclusion of some studies should be contextualised to the corresponding particular situation. 

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necessary to take into account factors other than financing and economic obstacles. 
Klessmann  et  al.  [8]  in  2008  analysed  the  consequences  of  market  risk  exposure  in 
Germany,  Spain  and 
the  United  Kingdom,  analysing  both  price  and 
forecasting/balancing risks. If wind generators are responsible for balancing, there is 
an incentive for producers to minimise imbalance costs with the consequent benefits 
for the grid. Conversely, this approach would lead to higher risk premiums (especially 
for the case of small producers, since the forecasting quality improves for aggregated 
generators).  This  fact  may  also  lead  to  a  market  concentration  of  larger  players. 
Furthermore,  as  the  predictability  of  wind  is  limited,  liquid  intraday  and  balancing 
markets are necessary for the efficient integration of wind generation in the electricity 
market. Klessmann et al. [9] showed in 2013 that risk-sensitive policies are crucial for 
attracting investors by: (i) reducing financing costs, (ii) decreasing project development 
costs  and  (iii)  increasing  market  revenues.  These  authors  remarked  that  policy  and 
administrative risks can be reduced at low cost, since exposing projects to this kind of 
risk does not produce any positive effect from a macro-economic point of view. Kitzing 
(2014) [10]  compared  the risk implications of FiTs and FiPs by a mean-variance risk 
analysis. The results obtained by Monte Carlo simulation show that, for the same level 
of attractiveness, FiT require lower direct support than FiPs. The author estimates that 
up  to  40  %  higher  remuneration  is  required  in  the  case  of  FiPs  to  attract  a  similar 
investment than a FiT. 

An assessment of the effectiveness of support schemes was presented by Mitchell et 
al.  (2006)  [11]  by  comparing  the  performance  of  the  United  Kingdom  Renewable 
Obligation scheme (a  TGC) and the FiT applied in Germany. The authors concluded 
that low-risk policies show higher effectiveness and, more specifically, that the German 
FiT  implicated  better  investment  conditions  than  the  certificates  system  offered  in 
United Kingdom. Also Toke (2007) [12] concluded that the certificates system in the 
United Kingdom does not imply a lower cost than a FiT. In 2011, Klessmann et al. [13] 
evaluated  the  status  of  renewable  energy  deployment  in  the  EU  by  means  of  the 
effectiveness indicator presented in [14]. The results showed that during the period 
2003-2009  the  highest  average  policy  effectiveness  was  reached  for  onshore  wind 
(4.2 %),  followed  by  biofuels  (3.6 %)  biomass  electricity  (2.7 %),  biogas  (1.6 %)  and 
photovoltaic (1.5 %). Germany was the country with higher effectiveness indicator for 
onshore  wind  (10.2 %),  followed  by  Spain  (7.4 %)  and  Portugal  (7.1 %).  Haas  et  al. 
(2011) [15] also argued that FiTs provide higher deployment and at lower costs than 
TGCs systems, and suggested that the better performance of FiTs is mainly because: 
(i) FiTs are easy to implement and can be revised to account for new capacities in a 
very short time; (ii) administration costs are lower than in case of trading schemes and 
(iii) FiTs can be easily tailored to each specific technology. 

Cardoso and Fuinhas (2012) [16] conducted an empirical analysis by a Panel Corrected 
Standard estimator. The study examines the  evolution of renewable energy  sources 
during 1990-2007 and it concludes that FiTs have been effective in fostering renewable 
energy use in European countries, but TGCs did not show evidence of producing the 
desired  effect.  Jenner  et  al.  (2013)  [17]  analysed  the  effectiveness  of  FiTs  from  an 

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econometric point of view. The authors established a relationship between the increase 
of return of investment (ROI) and the installed power. The research concluded that a 
10 % increase in ROI would imply an average increment of 2.8 % in yearly installed 
capacity. 

The influence of grid issues on the deployment of wind energy has also been an issue 
studied  in  detail  in  the  scientific  literature.  Barth  et  al.  (2008)  [18]  described  the 
different approaches for connection costs allocation. The research remarks that grid 
connection  costs  are  clearly  attributable  to  renewable  generators  but  grid 
reinforcement  costs  cannot  be  attributed  solely  to  one  source.  However,  it  is  also 
stated that performing a fair distribution of these costs is not easy. The authors remark 
that deep (or semi-deep) connection charges can be used to address the specific needs 
in a certain location of the grid by taking into account the generation/consumption 
profile.  This  kind  of  grid  connection  charges  incentivises  investors  to  place  new 
generators in regions with scarce electricity supply, rather than to put them in regions 
with  already  abundant  generation.  Swider  et  al.  (2008)  [19]  compared  the  grid 
connection  conditions  and  costs  in  selected  European  countries  (Germany,  the 
Netherlands,  the  United  Kingdom,  Sweden,  Austria,  Lithuania  and  Slovenia);  the 
research concludes that the allocation of connection costs can be an important barrier 
for  renewable  energy  installations  if  the  developer  has  to  bear  all  of  them.  The 
implications of connection cost sharing for offshore wind energy were discussed by 
Weißensteiner et al. (2008) [20] who found that offshore installations passing the grid 
connection  costs  to  grid  operators  results  in  lower  surplus  for  the  producers  and, 
hence, lower transfer costs for final consumers. 

The factors influencing energy curtailment were analysed by Porter et al. (2007) [21]. 
Flexibility of generating mix; existence of well-functioning and deep hour-ahead and 
day-ahead  markets;  geographical  distribution  of  the  wind  resource;  capacity  of 
transmission and size of the control areas are the main aspects that will determine how 
easy would be the integration of renewable energy in a certain region. Vandezande et 
al. (2010) [22] discussed the necessity of balancing requirements for wind farms in case 
of high penetration scenarios. Well-functioning balancing markets would be essential 
to incorporate wind generators in the balancing process. Finally, Batlle et al. (2012) [23] 
state that exposing renewable energy generators to the cost of imbalances enhances 
their ability to estimate their production and hence minimizing the cost of reserves for 
the whole system. 

Introduction to support schemes  

1.2. 
Policy support to renewable energy is usually performed by the combination of several 
measures. FiTs, FiPs or quota obligations (combined with TGCs) are usually applied as 
major support instruments [24]; they are discussed in sections 2.1 to 2.3. Section 2.4 
presents an overview of cases where the previous support schemes were suspended 
or  changed  with  retroactive  effects.  Finally,  investments  grants,  fiscal  measures  and 
financial support are secondary measures that provide an extra level of support are 
discussed in section 2.5. 

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Support  schemes  may  or  may  not  differentiate  among  renewable  technologies. 
Technology-neutral policies may lead to a market dominated by a few technologies, 
since their state of maturity is not the same, uniform incentives cannot provide enough 
support  for  technologies  in  their  early  stage  of  development.  In  addition,  uniform 
incentives  can  contribute  to  overcompensation  for  mature  technologies  when  the 
expensive technologies set the marginal price. 

1.2.1. 

Feed-in tariffs 

A  FiT  offers  a  long-term  purchase  guarantee  for  the  sale  of  renewable  electricity. 
Ideally, FiTs must include three key elements: (i) guarantee of dispatch, (ii) long-term 
commitment  and  (iii)  payment  levels  based  on  the  costs  of  the  technology.  This 
instrument seeks to provide higher security for investors. However, the main drawback 
is the lack of market compatibility, since energy has to be purchased regardless of the 
demand  level  [25].  An  extreme  effect  of  this  lack  of  market  compatibility  is  the 
appearance —in those markets where it is allowed— of negative prices of electricity 
during some off-peak hours [26]. A brief description of FiTs variants is provided below. 

Fixed price model. 

This model considers a fixed remuneration independent of other economic variables 
such  as  inflation,  electricity  market  price,  price  of  commodities,  etc.  Usually,  when 
calculating the remuneration level, the effect of the inflation is taken into account. This 
way, the revenues are sufficiently high during the early years of the project. However, 
the  real  value  of  the  revenues  decreases  with  time  due  to  inflation  [27].  As  the 
remuneration is known in advance, this support scheme allows developers to assess 
the income of the project with a high degree of certainty being, therefore, a support 
mechanism with low risk for investors. 

Fixed price model with partial or full price adjustment 

This remuneration scheme is based on a fixed amount updated periodically to track 
changes  in  the  broader  economy.  The  aim  of  this  readjustment  is  to  guarantee  a 
proper  level  of  revenues  at  the  end  stage  of  the  project,  when  the  effect  of  the 
cumulative  yearly  inflation  is  important  and  the  real  value  of  the  revenues  can  be 
significantly affected if the selling price of the delivered energy is not updated. 

Front-end loaded model 

This model offers higher tariffs during the early years than in the later years, which is 
intended to (i) avoid overcompensation during the last stage of the project, when the 
capital  expenditure  is  paid  off  and  (ii)  concentrate  higher  income  when  project 
developers are under higher financial pressure. Another feature of this model is the 
expected reduction of long-running costs of the support policy by reflecting to the 
ratepayer the declining costs that developers have to assume over time. 

1.2.2. 

Feed-in premium 

A feed-in premium is an additional amount paid for each unit of energy produced on 
top  of  the  electricity  market  price.  Thus,  a  FiP  is  considered  a  market-dependent 

8 

 
 
 
 
WindValueEU 

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mechanism because the final remuneration depends on the market price. With a FiP, 
there is some uncertainty about the final payment levels that can be too low or too 
high, and this higher risk has an effect on the total payment that is necessary to attract 
investors. Another factor that increases the risk for investors is that, usually, premiums 
do not offer guarantee of dispatch. According to some published studies, premium 
schemes are about 10 - 30 €/MWh costlier than FiTs [28] [29]. On the other hand, FiP 
policies are more compatible with competitive electricity markets, since they require 
renewable energy plants to participate in the bidding process. As remuneration to the 
wind farm operator increases when the market price is high, an incentive is created to 
produce more energy when it is needed the most [2] and, perhaps more significantly, 
participation in the bidding process would deter wind generators from producing in 
those hours with negative electricity prices. 

A variant of FiP is the spot market gap model. This approach consists of the payment 
of a variable amount that complements the spot market price to reach a previously 
set-up fix remuneration level (similar to a FiT level). Developers eventually receive a 
fixed amount (the set-up FiT) regardless of the spot market price (therefore, this option 
is  market  independent  from  the  producer's  point  of  view)4.  Usually  by  this  support 
scheme, the costs of the policy support shifts from the ratepayer to the taxpayer, since 
the subsidised amount is directly paid by the public budged [30]. 

1.2.3. 

Quota system and tradable green certificates (TGC) 

This  support  mechanism  is  market-based,  since  the  price  of  the  tradable  green 
certificates  is  defined  by  market  equilibrium  between  the  supply  and  demand  for 
certificates.  Demand  is  driven  by  a  determined  target  for  renewable  energy 
consumption,  i.e.  the  quotas  defined  as  a  percentage  of  energy  generated  by 
renewable energy sources. Certificates are tradable financial assets sold on a specific 
market.  Thus,  the  additional  cost  of  producing  renewable  energy  (compared  with 
conventional  sources)  is  compensated  with  the  extra  income  from  the  sale  of 
certificates. The total income obtained by renewable energy producers is the sum of 
the  electricity  market  price  plus  the  selling  price  for  TGC.  According  to  the  existing 
literature [31], [32], [33], [34], [35], the main advantages of TGCs are: (i) they are cost-
efficient,  since  actors  would  be  expected  to  fund  the  least  expensive  projects  to 
achieve any particular quota, and (ii) enable a higher exposure of renewable generators 
to market signals. On the other hand, TGC have some disadvantages, mainly related 
to the risk that project developers have to address under this support mechanism [35]: 
(i)  renewable  projects  face  uncertainty  derived  from  both  future  evolutions  of 
electricity prices and of TGC prices, and (ii) future evolution of certificate prices can 
lead to under/over compensation. 

4 For this reason from a theoretical point of view, this model is considered by some authors as a feed-
in tariff. However, from the point of view of policy support this method is market dependant, since the 
subsidised amount changes with the spot market prices. 

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2.  Overview and comparison  of  regulatory framework for 

onshore wind energy 

Figure 1 shows an overview of support schemes currently applied for new installations 
in  Member  States.  Cells  in  dark  blue  represent  support  schemes  for  onshore  wind 
energy, orange cells correspond to support schemes tailored to offshore wind energy, 
light blue cells indicate those cases where support schemes are only offered for micro-
wind energy5 and grey cells represent support schemes that are applicable to other 
technologies than wind energy. 

Figure 1: Overview of support instruments in EU MS in 2014. Collected and adapted from [36], 
[37] 

Figure 1 is also indicative of the evolution of support schemes for wind energy in each 
MS.  By  early  2000,  most  MSs  had  implemented  support  mechanisms  to  promote 
renewable energy. Nevertheless, continuous changes have been performed, because 
as the renewable energy sector matures policymakers have to face new challenges: 

  Technological/cost evolution. Rigid schemes that are  not able to respond to 
quick  falls  of  production  costs  have  to  be  adapted  in  order  to  avoid 
overcompensation  and  excessive  demand  for  new  installations  [38].  As  an 
example taken from photovoltaic energy market, in the Czech Republic, 1.5 GW 
of new capacity was installed in 2010 achieving a cumulative capacity of 1.95 
GW and exceeding the 2020 target of 1.65 GW set in the National Renewable 
Energy  Plan  [39].  After  this  unexpected  increase  of  demand,  a  number  of 
legislative  changes  took  place  in  the  following  years  and,  eventually,  the 
suspension of the FiT took place in 2013. 

  Macro-economic  changes.  The  global  economic  slowdown  influenced  some 

national budgets, which affected the level of support. 

  Objectives  of  renewable  energy  sharing.  As  shares  of  renewable  electricity 
progress, policymakers need to address new challenges and priorities; moving 
from  promoting  an  initial  expansion  of  the  sector  to  ensuring  continuous 
development with lower or no economic support. 

Despite amendments in support policy being necessary, they are also a factor that may 
hinder  the  confidence  of  investors.  For  this  reason,  stability  and  transparency  are 

5 In the context of this work, support schemes aimed to micro wind energy are not studied in further 
detail. 

11 

ATBEBGCYCZDEDKEEESFIFRGRHUHRIEITLTLULVMTNLPLPTROSESISKUKFeed-in tariffFeed-in premiumQuota obligation Contract for differenceInvestment grantsTax exemptionsFinancingTendering schemes 
                                                        
 
 
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critical  issues  that  can  influence  drastically  the  development  of  renewable  energy 
markets. Loss of confidence is especially severe when the changes and new measures 
are applied with retrospective or retroactive character [38]. 

Risk  perception  by  investors  is  an  important  factor  to  take  into  account.  Pure  cost-
benefit analysis is usually not sufficient to assure enough attractiveness, since it only 
considers  net  benefit  as  key  indicator.  Justice  [41]  suggests  that  the  risk  can  be 
classified according to the following categories: 

  Policy  and  regulatory  risk  (risk  of  sudden  and/or  retroactive  or  retrospective 
changes in the policy framework, budget or capacity caps, permitting and grid 
access risks, etc.) 

  Country  and  financial  risks  (government  stability,  maturity  of  legal  system, 

transparency of business dealings, currency risks, etc.) 

  Technical and project specific risks (construction, technological, environmental, 

operation and management risks) 

  Market risks (market price risks that influence project costs and revenues, e.g. 
feedstock prices, energy market prices, carbon prices, new competitors, etc.) 

Policymakers  can  play  an  important  role  in  reducing  policy  and  regulatory  risks.  A 
proper design of the scheme and of the administrative procedures in the permitting 
process  is  essential  in  order  to  reduce  uncertainty.  This  would  not  only  avoid 
discouraging investors, but would also reduce the overall cost of the support scheme. 
Higher risk needs to be compensated with higher remuneration levels in order to keep 
the  support  scheme  attractive  for  investors.  According  to  Rathmann  et  al.  [42],  the 
levelised cost of renewable energy could be reduced by up to 10 % if market players 
do not expect sudden policy changes. Similar conclusions (about 5-10 % reduction) 
were drawn by De Jager et al. [43]. 

Most MSs apply the same main support scheme with specific remuneration depending 
on technology; only Estonia offers the same premium regardless of the technology. 
Poland and Sweden implement a technology-neutral TGCs system by issuing the same 
amount of certificates regardless of the technology. 

Additionally,  as  modifications  are  performed  to  adapt  the  support  mechanisms  to 
market needs, it is expected that best practices spread. This would be the basis for 
more  optimised  support  schemes  and  a  forthcoming,  perhaps  more  harmonised 
approach  to  their  design,  as  energy  markets  integrate  and  fully  use  existing 
cooperation  mechanisms.  Also,  this  natural  harmonisation  would  be  improved  by 
competition between national support schemes. As stated in the Communication from 
the Commission, European Commission guidance for the design of renewables support 
schemes  [38]:  "Regulatory  competition  between  EU  member  states  for  renewable 
energy policy will most likely lead to a certain natural convergence as Member States 
design their support mechanisms to attract capital and ensure they meet their national 
renewable energy targets". 

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In the following sections, the specific measures taken in each MS for the promotion of 
onshore wind power plants6 are further detailed. 

Feed-in tariffs for onshore wind power 

2.1. 
Table 2 summarises the specific features of FiTs offered for new onshore wind power 
plants among MSs. Austria, Bulgaria, Croatia, Greece, Lithuania and Slovakia apply a 
fixed  FiT  model  without  indexing  to  inflation.  Ireland  indexes  the  remuneration  to 
inflation. 

Germany  offers  the  option  of  a  front-end  tariff  that  considers  a  final  period  with  a 
reduced tariff. The transition time is designated according to the quality of the wind 
location  of  the  wind  farm.  By  this  remuneration  model, 
resource 
overcompensation for better places is avoided. Also, concentration of onshore wind 
farms in the same geographical area is somehow mitigated. 

in  the 

In Hungary7, Lithuania and Italy, tenders are employed to set the remuneration to be 
paid to plant operators. Under this procedure plant developers present their bid for a 
certain remuneration taking into account the technical specifications set in the call for 
tenders.  The  winning  bid  is  selected  by  considering  both  technical  and  economic 
merits. 

Recent developments include schemes that attempt to fine-tune remuneration details 
to avoid overcompensation. For example, in Spain a new support scheme was set in 
2013 that is based on two items on top of market price: remuneration for investment 
(covering  the  investment  costs  that  cannot  be  recovered  by  selling  the  generated 
energy in the market) and remuneration for operation (that covers, when applicable, 
the  difference  between  the  operating  costs  and  the  income  for  participating  in  the 
market). For existing installations, the remuneration is set by law taking into account a 
reasonable profitability that would obtain a standard facility. As a reference, in the case 
of wind power plants the remuneration for operation applicable for the year 2014 is 
zero and the remuneration for investment ranges from 8 294 €/MW (for a wind farm 
commissioned in 2004) to 101 312 €/MW (in the case of a wind farm commissioned in 
2013). In addition, a tender procedure will cover new installations where bidders will 
specify a series of retributive parameters (including, among others, the life span of the 
project, number of equivalent hours and lower/upper limits of electricity prices). These 
would be employed to determine the bidding variable: the reduction percentage over 
the  standard  value  of  the  initial  investment  for  the  reference  installation.  Once  the 
winner  of  the  tender  is  selected,  the  remuneration  for  investment  will  be  calculated 
according to the procedure set in the Royal Decree 413/2014 [44]. 

6 The study is focused on the promotion of large scale wind power. For this reason policies aimed at 
wind installations smaller than 5 MW are not featured in detail. 
7 Although theoretically in use, in practice tenders are not used in Hungary, were deployment is null. 

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Table 2: Summary of FiTs for 2014 for onshore wind energy support implemented in 
MSs. 

Country 

Amount (€/MWh) 

Austria 
Bulgaria 
Croatia 
Cyprus 
Germany 
Greece 
Hungary 
Ireland 
Italy 
Lithuania 
Luxemburg 
Slovakia 
United Kingdom 

93.6 
95.55 BGN/MWh (49 €/MWh)9 
Depending on reference price 
14511 
Years 0-5: 89; years 6-20: 49.512 
82-90; 10514 
Tender - defined 
69.515 
127, 110, 8917 
6019 
92 
70.321 
95 GBP/MWh 117,67 (€/MWh)22 

Period 
(years) 
13 
12 
14 
20 
20 
20 
- 
15 
20 
12 
15 
15 
15 

Degression / 
caps 
1%8 
10 
- 

13 
- 
- 
16 
2% / 18 
- / 20 

- 
- 

A new model was recently introduced in the United Kingdom: a FiT with contracts for 
difference (CfD) with regards the market price. Under this scheme wind generators will 
receive  the  previously  defined-by-auction  strike  price  (in  practice,  a  FiT  fixed  by 
auction). Generators are required to participate in the market and, if the market price 
is lower than the strike price, the difference is covered by the CfD counterparty, i.e. the 

8 Degression confirmed for new wind farms installed in 2015, this amount can be annually adjusted to 
reflect the evolution in the cost of technology 
9 Exchange rate used: 1 EUR = 1.96 BGN 
10 To be set every year by the regulatory authority 
11 The last 30 MW under this FiT are pending construction. Afterwards the FiT will be stopped. 
12 An extension of the initial period is granted depending on the wind resource at the wind farm 
location related to a reference value (mean wind speed: 5.5 m/s at 30 m with roughness length 0.1 m). 
13 Depending on added capacity 
14 Wind farms above 5 MW. 82 €/MWh for wind farms in the interconnected grid (105 €/MWh if no 
capital grant was received); in not interconnected islands: 90 €/MWh (110 €/MWh if no capital grant 
was received) 
15 For wind farms with more than 5MW 
16 Related to inflation 
17 Wind farms above 5 MW have to bid in a tender with a maximum of 127 €/MWh. Developer PTL 
Energia reported (7/10/2014) being building wind farm Torre di Ruggiero for a tendered FiT of 109.83 
€/MWh. On 17/09/2014 it reported it was awarded, at the last GSE competitive auction, a FiT of 88.9 
€/MWh for a 33MW wind farm to be built in Simeri Crichi. 
18 Annual maximum installed capacity (by registration and by tender) of 710 MW for 2014 and 2015 
19 Maximum amount for wind farms bigger that 350 kW: FiT selected by tender 
20 Maximum installed capacity till 2020 of 500 MW 
21 The feed in tariff is guaranteed for the first three years. After this period, a reduction can be applied 
for new wind farms. Wind power plants with less than 15 MW receive a surcharge 
22 This is the so-called Strike Price. Exchange rate used 1 EUR = 0.807 GBP 

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Low Carbon Contracts Company (LCCC). Conversely, if the market price is higher than 
the strike price, the generator pays back the difference to the LCCC. 

Feed-in premiums for onshore wind power 

2.2. 
An overview of currently available FiP for two Members States is presented in Table 3. 
Both  Estonia  and  Denmark  offer  a  premium  on  the  top  of  the  market  price,  but 
Denmark set a ceiling to the sum of market price plus premium. A third variant of this 
model was introduced in Spain in 2007 [45] that included a ceiling and a floor in the 
premium remuneration scheme. Thereby, the risk for investors was also mitigated by 
assuring  a  minimum  remuneration  in  case  of  low  market  prices.  However,  Spain 
suspended this remuneration scheme for new installations in 2012 [37], [46]. 

Table 3: Summary of FiPs for 2014 for wind energy support implemented in Denmark 
and Estonia 

Add-on 
(€/MWh) 

Denmark 

250 DKK/MWh 
(33.5 €/MWh)23, 

Estonia 

53.7 

Supplements 

23 DKK/MWh (3.1 
€/MWh) for 
covering balance 
- 

Caps 

Eligibility 
period 

6600 FLH plus 
5.6MWh/m2 24 

12 

600 GWh/yr 

A  variant  of  the  spot  market  gap  method  is  used  in  some  MSs  to  determine  the 
premium that is based in average prices of the electricity in the wholesale market. For 
example, Finland implements a FiP calculated as the difference between the objective 
remuneration (previously defined) and the average price of electricity in the preceding 
three  months.  This  premium  is  annually  adjusted  according  to  the  average  price  of 
electricity. 

The Netherlands offers a FiP-like remuneration scheme that is technology-neutral and 
structured in six stages depending on the application date of the plant. Table 4 shows 
the  corresponding  amount  depending  on  the  tender  stage  when  the  project  is 
selected. 

In Finland the costs derived from the support scheme are covered by public funds, but 
in the Netherlands these costs are covered by a rate surcharge taking into account a 
cap  for  the  overall  programme  (including  also  subsidies  to  renewable  heat  and 
cogeneration) that was set at 3.5 billion EUR in 2014. The available funds are allocated 
to corresponding projects according to a first come, first served basis. 

23  Considering  an  exchange  rate  of  1  EUR  =  7.46  DKK.  Wind  power  plants  commissioned  after 
01/01/2014 receive a maximum remuneration (premium plus market price) of 80 €/MWh 
24 The wind farm will receive the FiP for a number of hours resulting from the sum of two concepts: 
6600 equivalent full load hours plus 5.6 MWh per each square metre of rotor area. 

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Table 4. Feed-in premium tariff received in the Netherlands related to the application 
date. In parenthesis the maximum of full-hours equivalent is indicated. 

Stage 
Application 
date 
Amount 
(€/MWh) 

1 
01/04 - 
11/05/2014 
87.5 
(2960) 

2 
12/05 - 
15/06/2014 
100 
(2960) 

3 
16/06 - 
31/08/2014 
112.5 
(2320) 

4 
01/09 - 
28/09/2014 
121.3 
(2320) 

5 
29/09 - 
02/11/2014 
121.3 
(2320) 

6 
03/11 - 
18/12/2014 
121.3 
(2320) 

Germany's 25  FiP  takes  into  account  the  FiT  as  reference  remuneration.  Thus,  the 
premium  is  calculated  as  this  reference  remuneration  minus  the  average  electricity 
price during the previous month. Also Slovenia applies a variant of this scheme where 
the premium is calculated as the reference value minus the average price multiplied 
by a certain factor. 

Table 5: Summary of FiPs – Spot Gap Market model- for 2014 for wind energy 
support implemented in MSs. 

Country 

Target price (€/MWh) 

Eligibility 
period 

Finland 

Germany 

Latvia 

The 
Netherlands 

83.5 26, 

Variable27, 
46.85-58.8 (LVL/MWh) 
67.0-83.5 (€/MWh)28, 
S1: 87.5; S2: 100 
S3: 112.5; S4-S6: 121.329, 

12 

20 

20 

15 

Caps 

Maximum installed 
capacity: 2.5 GW 
- 

3500 eq. hours 

S1 & S2: 2960 h 
S3: 2520 h; S4-S6: 2320 h 

25 Germany offers the possibility of choosing between FiT and FiP 
26 Target price. The subsidised amount is the difference between the target price and the average market 
price during the previous three months with a minimum of 30 €/MWh if the average market price drops 
below that figure. The subsidy is covered by the state budget. An early-bird premium is considered for 
wind farms installed before 31/12/2015 with a target price of 105.3 €/MWh for the three first years. 
27 Calculated  as  the  FiT  minus  technology-weighted  average  monthly  market  price.  Already-installed 
generators under the old remuneration scheme can switch from FiP to FiT and vice versa on a monthly 
basis. New generators have only access to FiP 
28 Exchange rate used 1 EUR = 0.70 LVL. Selected by tender. The tariff is reduced by 40 % in years 11-
20. The FiT system is currently under review. The subsidy amount was chosen by a competitive bidding 
process. However, the mechanism to choose winners was claimed to be non-transparent.  
29 Each  stage ("S") of remuneration is opened  successively  and  each lasts around 6 weeks. If a plant 
applies for the lowest level (S1), it is most likely that there are funds and thus it can get this level of 
remuneration. The later the plant applies, the more remuneration is entitled, but there might not be any 
funding left from the previous stage. In addition, there is an annual overall cap on maximum expenditure 
in support for all renewable energy sources of 3.5 € billion 

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Country 

Target price (€/MWh) 

Eligibility 
period 

Slovenia 

<10 MW; 95.38. <125 MW; 
86.7530 

20 

Caps 

- 

2.3.  Tradable green certificates and quota obligation for onshore 

wind power 

Belgium, Sweden, Poland, Romania and United Kingdom apply TGCs and quotas to 
promote wind energy. Table 6 summarises the main features and particularities in each 
case. 

In Belgium, support to onshore wind is the responsibility of the regions, and thus the 
basis  to  issue  one  certificate  change  depending  on  the  jurisdiction.  For  example, 
1 MWh is the basis used in the Flemish region, as in Sweden and Poland. In the United 
Kingdom,  one  certificate  is  issued  for  each  1.11  MWh  of  energy  produced  by  an 
onshore wind farm. A different approach is applied in the Belgian regions of Wallonia 
and Brussels by issuing the green certificates indexed to the amount of CO2 saved. 

Table 6: Main features of TGCs support schemes in EU MS. 

Penalty (€) 

Minimum 
(€) 

Maximum 
(€) 

Validity 
(years) 

Eligibility 
(years) 

1 TGC 
base 
217 kg of 
CO2 
456 kg of 
CO2

31 

100 

100 

Belgium 
(Brussels) 
Belgium 
(Wallonia) 
Belgium 
(Flanders) 
Sweden 

1 MWh 

100 

1MWh 

Poland 

1MWh 

Romania 

0.5 - 0.67 
MWh 

33 
303 PNL 
(72.94 €)35 
526.07 RON 
119.29 €36 

65 

65 

93 

- 

- 

- 

- 

- 

- 

5 

5 

10+532 

15 

1534 

129.12 RON 
29.28 

263.06 RON 
59.65 

End 
2016 

15 

30 Reference prices to calculate the premium as the reference price minus the average electricity market 
price multiplied by a factor, B (0.8 up to 10 MW and 0.86 up to 50 MW). 
31 For wind energy, the amount of green certificate is calculated on a case-by-case basis 
32 A reduced coefficient is applied after 10 years 
33 150 % of average price of unsatisfied obligation period 
34 15 years (in any case, eligibility will cease at the end of 2035 at the latest) 
35 Exchange rate used 1 EUR = 4.17 PNL 
36 Considering an exchange rate of 1 EUR = 4.41 RON 

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1 TGC 
base 
37 

UK 

Penalty (€) 

Minimum 
(€) 

Maximum 
(€) 

Validity 
(years) 

38 

Eligibility 
(years) 
20 

In Romania, two certificates per MWh are issued for wind farms accredited before 31 
December  2013,  but  from  these,  one  certificate  is  suspended  until  31  March  2017. 
From 2018, one certificate is issued per MWh. In case of onshore wind farms registered 
after  31  December  2013,  1.5  certificates  per  MWh  are  issued  till  2017  and  0.75 
certificates per MWh from 2018. The penalty for missing a certificate ranges from 72.9 
€ in Poland [47] to 119.3 € in Romania. In the United Kingdom, the penalty is calculated 
as  a  function  of  the  buy-out  price  during  the  period  of  the  missing  certificate  plus 
interest. 

Another distinguishing factor is the different level of demand stimulation by setting 
the quota of renewable energy that has to be consumed by the required customers. 
Most MSs that apply  TGCs have published their quotas for the  following years, see 
Figure 2. As it can be appreciated, the required quota varies significantly among MSs. 
As a consequence of this, pressure put over the demand is expected to be at a different 
level. 

Figure 2: Evolution of required quota for renewable energy consumption 

37 Variable depending on year and technology 
38 Buy-out price plus five per cent interest 

18 

0510152025303540PolandRomaniaSwedenGreat britainNorth IrelandWalloniaYearQuota (%)Great Britain 
 
 
 
 
 
                                                        
 
 
 
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Figure 3: Evolution of yearly average price of TGCs. 

Poland, Romania and the Belgian region of Wallonia have defined an increasing trend 
of the quota. On the other hand, Northern Ireland and Great Britain39 set a decreasing 
trend in the following  few  years that finally  will remain at a  constant value after 31 
March 2015 until the mechanism closes in 2017. Sweden defined an increasing quota 
phase till 2020 and a decreasing phase from 2020 to 2035. 

The average annual price in each country is shown in Figure 3. As it can be appreciated, 
the prices of certificates are relatively stable for each MS. Romania [48]; Great Britain 
[49]  and  Poland  [50]  have  reached  similar  prices.  Whilst  much  higher  prices  were 
obtained in Flanders and Wallonia [51] and lower prices observed in Sweden [52] 40. 

Quotas  combined  with  TGCs  system  is  a  support  scheme  that  is  increasingly  losing 
ground. Two MS —the United Kingdom and Poland— are planning to phase out this 
support mechanism  [53]. More specifically, the UK has announced the expiration of 
the quota system on 31 March 2017 [37], to be replaced with a contract for difference 
(CfD) that entered in force in October 2014 in Great Britain. During a transition period, 
owners can choose between both support schemes. 

Also,  some  other  MSs  that  used  to  apply  TGCs,  eventually  switched  to  a  different 
support scheme as was the case of the Netherlands that phased out this system in 
2000 [54] or Italy who in 2013, switched TGCs for a FiT [55]. 

39 Great Britain and Northern Ireland set a different amount of quota obligation 
40 Yearly average currency exchange rates where used to convert SEK, RON, GBP and PLN to EUR. 

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2.4.  Suspension of support schemes and retrospective measures 
There are some Members States that, for different reasons, currently do not provide 
any of the main support schemes (FiTs, premiums or TGCs). In one case (Malta), the 
MS never provided support for large-scale wind energy; in other cases, support was 
provided in the past and later stopped. 

Cyprus stopped wind energy support for new projects with the exception of a 30MW 
ongoing development. In France, following a ruling issued by the European Court of 
Justice, the conditions for the purchase of electricity produced by wind power plants 
were  abolished  on  28  May  2014.  The  old  regulation  applied  exemptions  to  certain 
industries from the surcharge, Contribution au Service Public de l'Electricité, which was 
found to be against EU state aid regulations. 

In  January  2012,  Spain  suspended  the  existing  support  schemes  after  having 
introduced  previously  several  retroactive  changes.  The  price  regulation  system  was 
eventually phased out through Real Decreto-ley 9/2013. A new remuneration scheme 
entered into force in June 2014 [44]. Additionally, a series of retrospective measures 
have  been  put  into  force  in  recent  years  affecting  the  income  of  renewable  energy 
producers: modification of the reward system for reactive power control, annual cap 
of equivalent production hours and a 7% flat rate tax applied on the gross revenues 
for electricity sale [56]. 

In October 2014, a new policy for renewable energy support was published in Portugal. 
This new policy does not consider any support for large scale projects, just for micro- 
and mini-generation. Portugal had stopped supporting new installations in 2012 and 
negotiated  a  levy  on  existing  wind  producers  to  do  away  with  their  situation  of 
overcompensation  (in  contrast  with  Spain  that  did  not  negotiate  at  all  with 
stakeholders).  

In  August  2013,  the  Czech  Republic  abolished  the  FiT  scheme  for  all  renewable 
technologies  except  for  small  hydro.  However,  wind  power  plants  that  obtained 
approval  of  their  building  permits  before  31  December  2013  will  be  entitled  for 
support if they are put into operation before 31 December 2015 [37]. 

Additionally, several MSs introduced retrospective measures [57]: 

 

 

In Wallonia (Belgium), some municipalities are adopting special taxes over new 
and  existing  wind  turbines  [58].  Also  in  Wallonia,  a  specific  fee  for  green 
electricity producers has been introduced in mid-2012. 

In Bulgaria, since May 2012, the connection to the grid of renewable plants with 
a  preliminary  grid  connection  contract  was  postponed  to  2016. Furthermore, 
since mid-March 2014, the distribution system companies have been limiting 
the maximum power generation of all wind and photovoltaic power plants by 
60% [56]. 

20 

 
 
WindValueEU 

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  Greece  imposed  in  2012  a  levy  on  the  gross  income  of  all  operating  RES 

projects. 

  The Polish indexing of green certificate prices to inflation was removed [56]. 

  Romania introduced in 2013 retroactive regulatory changes that fundamentally 
changed the economics for existing installations. Mandatory acquisition quotas 
for  green  certificates  -which  were  defined  by  law  till  2020-  were  slashed 
drastically (in 2014, the quota reductions were over 25%, as the obligation was 
reduced  from  15%  to  11.1%);  energy-intensive  companies  where  exempted 
largely without redistribution of the obligations; the validity of green certificates 
was reduced from 16 months to 12 months; the envisaged implementation of 
the  guaranty  fund,  that  should  have  bought  excess  green  certificates,  was 
repealed. All these measures resulted in green certificate prices being cut by 
half and caused extreme oversupply which may result in many green certificates 
to expire and therefore be worthless. Furthermore, half of the green certificates 
produced between 2013 and 2017 were delayed to the period of 2018 and 2020, 
which  causes  financial  losses  even  if  a  recovery  would  be  possible.  Green 
certificates are not granted anymore for electricity produced above the physical 
notifications of the day-ahead forecast. New priority dispatch of certain national 
coal generation and changes to balancing market rules led to additional, non-
remunerated, production curtailment. Finally, a construction tax of 1.5% yearly 
on tangible assets was introduced. 

2.5.  Secondary support schemes 
Other types of incentive programmes such as tax exemptions, investment grants or 
financing support can complement the main wind energy support schemes. 

2.5.1. 

Tax incentives or exemptions  

Tax incentives or exemptions are considered to be highly flexible policy tools that are 
targeted to encourage specific renewable energy technologies, especially when used 
in combination with other policy instruments [59].  

Table 7: Summary of tax incentives for wind energy available in MSs 

Country 

Greece 

Ireland 

Income tax 
relief 
100 % of CapEx 
be deducted 
from income 
50 % of CapEx 
(excl. land cost) 
up to 9.5 M€ 

VAT relief on 
WF CapEx 

Other tax reliefs 

VAT relief on 
energy sales 

- 

- 

- 

- 

- 

- 

21 

 
 
WindValueEU 

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Country 

Italy 

Lithuania 

The 
Netherlands 

Poland 

Sweden 

Slovakia 

Income tax 
relief 

- 

- 

- 

- 

- 

- 

VAT relief on 
WF CapEx 
10 % (instead 
of 20 %) 

- 

- 

- 

- 

- 

Other tax reliefs 

- 

- 

VAT relief on 
energy sales 

- 

Total 
exemption 
(approx. 0.52-1 
€/MWh) 

Write off investment 
on renewable 
projects against 
taxes. 
Max. 600€ per 
installed kW41 

- 

Reduced real estate 
tax (0.2 €/MWh for 
wind energy) 
Exemption of energy 
tax42 
Exemption on excise 
tax 

- 

Total 
exemption 
(approx. 5 
€/MWh) 

- 

Table 7 shows that these incentives or exemptions are offered on different types of 
taxes. Namely, value-added tax on CapEx; income tax relief (as in Greece and Ireland); 
special tax exemptions (applied in Sweden and United Kingdom); reduced taxes for 
renewable  energy  consumers  (Lithuania  and  Poland)  or  —  as  in  case  of  the 
Netherlands — stimulation of participating in renewable energy projects by deducting 
taxes paid by investors. 

2.5.2. 

Investment grants 

Investments grants are implemented by several MSs. For example, in Belgium Flanders 
offers a subsidy programme for selected wind projects (but this programme cannot be 
combined  with  participation  in  the  TGCs  market)  and  Wallonia  applies  investment 
grants for wind projects larger than 1 MW. Finland, Greece, Romania and Slovenia offer 

41 For entrepreneurs based in the Netherlands 
42 Just for self-consumption 

22 

 
 
 
 
                                                        
 
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support that may reach 30-50 % of the project. A higher percentage can be granted in 
Lithuania up to 80 % of the capital expenditure with a maximum of 0.2 M€ per project. 

Table 8: Summary of investment grants for wind energy available in MSs 

Country 

Target 

Conditions 

Belgium 
(Wallonia) 

Projects larger than 1 
MW 

Belgium 
(Flanders) 

Estonia 

Finland 

Greece 

Lithuania 

Romania 

Slovenia 

Selected projects 

Wind projects in 
general 
Wind projects in 
general 

Wind projects in 
general 

Wind projects in 
general 
Wind projects in 
general 
Selected by tendering 

Minimum assistance 25 000 € 
For small companies up to 50 % with 
1.5 M€ maximum. Big companies up to 
20 % but 25-30 % for strategic projects 

Depending on the environmental 
performance of the project with a 
maximum of 1 M€ over a period of 3 
years. No compatible with TGCs 

Variable. Depending on the scope of 
the project 

Up to 30 % of overall cost 

Between 15 - 45 % of total cost 
15-40% in case of wind farms larger 
than 1 MW 
Up to 200 000 € or 80 % of the overall 
cost 
Up to 6.7 M€ or 50 % of total cost  
(40 % in the zone of Bucharest) 
Maximum 30-50 % 

2.5.3. 

Low-interest loans 

This category of support scheme seeks to assist on financing renewable projects by 
promoting or offering loans with a rate below the market rate of interest. This kind of 
support can also provide longer payment periods or phases without interest payment. 
As it can be observed in Table 9 both Germany and Lithuania offer loans for onshore 
wind power. 

Table 9: Summary of loans for wind energy available in MSs 

Country 

Target 

Loan conditions 

Lithuania 

Wind energy in 
general 

Non-established upper limit. The credit institution 
will provide at least 20 % of the loan 

23 

 
 
WindValueEU 

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Country 

Target 

Loan conditions 

Germany 

Onshore wind 
farms and 
repowering 

Depending on the programme: projects up to 25 
M€, 100 % of financing; between 25 and 100 M€, 50 
% of financing. Repayment-free start-up period of 
maximum 3 years. Low interest loan up to 20 years. 
Monthly commitment fee of 0.25 % 

2.6.  Grid issues 

This  section  presents  grid  issues  regarding  grid  connection  (procedure  and  cost 
allocation) and operation (priority use of the grid and balancing). 

2.6.1. 

Connection procedure 

farm, 

sends 

The  general  procedure 
for  grid  connection 
in 
most European countries 
is  basically  as  shown  in 
[60].  After 
Figure  4 
performing 
the  basic 
technical  project  of  the 
the  plant 
wind 
developer 
the 
application to the system 
operator.  In  a  feasibility 
system 
study, 
the 
examines 
operator 
whether 
the  network 
conditions existing at the 
of 
planned 
connection 
are 
technically  adequate.  If 
technical 
the 
requirements 
the 
of 
electrical  system  at  the 
connection 
intended 
point  are  not  adequate, 
operator 
the 
furnishes  evidence  of  this  inadequacy  and  proposes  the  necessary  modifications  or 
network reinforcements. Following this feasibility study, a formal connection offer is 
proposed. 

Figure 4: General connection procedure for wind power plants 
[60] 

point 

grid 

24 

Wind farm basic technical projectRequest for connection point (bank guarantee)Assignment of connection pointTechnical requirements to connectionFinal Technical projectApprovalConnection & access contractConnection of the wind farmEvaluationDSOTSOIf not enough capacityWind farm developer 
 
 
WindValueEU 

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In some counties renewable energy sources  are entitled to priority connection over 
conventional sources as long as they meet the technical requirements and the terms 
and conditions for connection. As shown in Figure 5, priority connection is offered in 
10 MS whereas in the rest connection is non-discriminatory between technologies. 

Figure 5: Connection regime for renewable energy sources in MSs [37], [61], [62]. 

2.6.2. 

Connection costs sharing 

The allocation of grid connection costs impacts renewable energy schemes more than 
conventional generators because renewable energy projects are more sensitive to any 
increase in capital costs [19].  

As  shown  in  Figure  6,  there  are  different  approaches  for  sharing  costs  of  grid 
connection between producers and grid operators [63]: 

  Shallow 

the 

Wind farm 
substation 

cost 
approach.  The  plant 
developer  bears  the 
cost  of  equipment 
necessary  to  connect 
the  generator  to  the 
nearest suitable point 
already 
on 
existing grid network, 
generally 
a 
the 
substation.  On 
other  hand,  the  grid 
owner  will  bear  the 
cost  of  any  grid 
reinforcement 
that 
would  be  necessary 
to  integrate  the  new 
generator.  Usually, 
these  costs  are  eventually  transferred  to  the  end  users  by  specific  tariffs  or 
surcharges. The major advantage of this approach is a relatively cheap connection 
cost for the plant developer. However, the main drawback is that the grid operator 
may  overestimate  the  reinforcement  costs,  knowing  that  these  costs  will  be 
transferred to the ratepayers. 

Figure 6: Approaches for cost allocation of grid connection [64]. 

  Super–shallow  approach:  plant  developers  only  have  to  bear  the  costs  of  the 
internal electrical infrastructure including the plant substation. Expansion of the 
grid to the connection point and reinforcement is borne by the grid operator. 

25 

ATBEBGCYCZDEDKEEESFIFRGRHRHUIEITLTLULVMTNLPLPTROSESISKUKPriority connection Non-discriminatory 
 
 
WindValueEU 

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  Deep cost approach: plant developers have to bear all connection costs, as well as 
any further reinforcement expenses that can arise as a consequence of integrating 
the generator in the electrical system. This model has two main drawbacks from 
the developer's point of view: (i) the costs borne by the generator are potentially 
much higher than by the shallow approach and (ii) project risks increase because 
developers face additional uncertainty regarding network reinforcement costs. 

  Mixed shallow-deep approach: this model is a hybrid of the two above-mentioned 
methodologies. Mainly, the plant developer bears the cost of the grid extension 
to the assigned connection point, plus a proportion of the reinforcement costs. 
The  main  drawback  of  this  approach  is  the  difficulty  of  defining  the  exact 
proportion  corresponding  to  each  party.  Incidentally,  by  offering  tailored 
connection  charges  this  method  can  be  used  to  stimulate/discourage  the 
installation of new generators in the locations more/less suitable  from a system 
point of view. 

Table 10 shows that the shallow approach is the most implemented among MSs. A 
variant of the shallow cost approach is offered in Denmark: the costs of connection to 
be borne by the plant developer are limited to the equivalent costs of connecting the 
generator to the medium voltage grid [37]. In Germany, if the system operator defines 
a  connection  point  different  than  to  the  closest  one,  the  grid  operator  bears  the 
additional costs. Lithuania applies a deep-shallow approach, being the plant developer 
responsible for 10 % of the cost of grid reinforcement. 

26 

 
 
WindValueEU 

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Table 10. Distribution of the connection costs and reinforcement between plant and 
system operators (PD: Plant Developer; GO: Grid Operator) [37], [65] 

  Connection  Reinforcement  Approach 

Comments 

PD 
x 
x 

GO 

x 

AT 
BE 
BG 
CY 
CZ 

DE 

DK 

x 

EE 

ES 

FI 

FR 
GR 
HR 
HU 
IE 
IT 

LT 

LU 
LV 
MT 
NL 

PL 

PT 
RO 

SE 

SI 

SK 

UK 

x 
x 

x 

x 

x 

x 

x 

x 
x 
x 
x 
x 
x 

x 

x 
x 
X 
x 

x 

x 
x 

x 

x 

x 

x 

GO 

x 
x 

x 

x 

x 

x 

x 
x 
x 

x 

x 

x 

x 
x 

x 

x 

PD 
x 

x 
x 

x 

x 

x 
x 

x 

x 
x 
x 

x 

x 

x 

Deep 

Shallow  Offshore connection costs partially subsidised 
Shallow 
Deep 
Deep 

Shallow 

Shallow 

Deep 

Shallow 

Deep 

Shallow 
Shallow 
Deep 
Shallow 
Shallow 
Shallow 
Deep-
shallow 
Deep 
Deep 
Deep 
Shallow 

Shallow 

Shallow 
Shallow 

Deep 

Shallow 
Deep-
Shallow 
Deep-
Shallow 

Plant developer bears cost to closest 
connection point. If grid operator requires a 
different point of connection, grid operator 
bears the additional costs 
Plant developer bears a cost equivalent to the 
costs that would be incurred if his plant was 
connected to the medium voltage grid. The 
remainder is borne by the grid operator 
Reported lack of regulation regarding 
responsibilities of grid reinforcement 

No clear rules: grid reinforcement borne by 
plant developer if it is for the only benefit of 
the plant 

Plant operators contribute with no more than 
10 % of the costs of reinforcement 

Hyper-shallow for new offshore WF. 
Despite grid operator being responsible for 
upgrading the network, rules are not clear 

Grid reinforcement borne by plant developer if 
it is for the benefit of the plant only 

Costs of reinforcement are shared between 
plant and system operators 
Plant operators pay the Connection Charges to 
grid operators distributed over time1 

27 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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2.6.3. 

Operation and use of the grid by wind energy generators 

The  wind  generator's  revenue  is  linked  to  the  volume  of  energy  sold.  In  this  sense, 
there are two main aspects of the use and operation of the grid that can mitigate the 
volume risk: priority of access to the grid and beneficial curtailment rules. It should be 
noted that the operational issues presented in these sections are applicable for both 
onshore and offshore wind energy. 

Figure 7: Priority/guaranteed access to the grid for energy produced by renewable 
sources. 

Some MSs establish conditions for priority access to the grid by renewable installations 
by  either  the  priority  access  (in  presence  of  purchase  contracts  with  transmission 
operators) or guaranteed access (when the wind generators participate in the market). 
Figure  7  shows  those  countries  that  offer  either  kind  of  preferential  access  for  the 
transmission of energy produced by renewable energy sources. 

Despite priority use of the grid being granted in most MSs, energy curtailment can 
occasionally happen under certain operational conditions of the grid. A problem is that 
in some countries there is a lack of curtailment and compensation rules. Furthermore 
as wind  energy penetration levels rise and the  electricity grid is not developed and 
reinforced at the same time, an increase in energy curtailment can be expected in the 
future.  Energy  curtailment,  as  a  potential  barrier  for  wind  energy  deployment,  is 
presented in more detail in section 2.7 below. 

Balancing Responsibility 

Figure  8  shows  that  in  some  MSs,  wind  operators  are  required  to  cover  balancing 
responsibilities.  Nevertheless,  the  ability  of  wind  generators  to  participate  in  this 
process is linked to the design of the market. Mature intraday markets, with a proper 
level of liquidity, allow wind generators to better react to market  signals  [66], since 
wind production forecast errors decrease with short lead-times. 

Figure 8: Balancing responsibility for wind electricity producers in MS. 

The new Guidelines on State aid for environmental protection and energy 2014-2020 
[67] introduce the obligation for large renewable energy systems (RES) to be subject 
to  balancing  obligations  on  the  conditions  that  liquid  balancing  markets  exist. 
Currently, there are different levels of required balancing responsibility between the 
MSs that require participation on balancing. In Germany, no responsibility is allocated 
under  the  FiT  scheme;  however,  generators  under  the  premium  option  are  fully 
responsible  for  balancing.  Hungary  and  Latvia  make  RES  generators  pay  balancing 

28 

ATBEBGCYCZDEDKEEESFIFRGRHRHUIEITLTLVLUMTNLPLPTROSESISKUKYesNoBalancing responsibility 
 
 
 
WindValueEU 

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penalties that, in the latter case, can reach 20% of the Fit. In Italy, a positive incentive 
for meeting the forecasts is granted. 

2.7.  Barriers 
This  section  aims  to  give  an  overview  of  potential  barriers  to  onshore  wind  energy 
deployment among MSs. 

The  effectiveness  of  support  mechanisms  is  not  just  related  to  the  remuneration 
provided: other drivers and factors such as the political and economic framework, the 
structure and regulation of the market, the infrastructure and regulation of the grid, as 
well as the administrative and permitting process, have a considerable influence on 
the diffusion of renewable energy technologies. Figure 9 shows the impact of each one 
of  these  categories  according  to  the  preliminary  results  obtained  by  the  DiaCore 
project  [68].  The  box-plots  show  the  results  of  the  interviews  and  questionnaires 
performed on renewable energy stakeholders in Europe. As can be seen, the political 
and  economic  framework  is  the  most  relevant  factor  with  a  median  of  9  points  of 
relevance scoring (over a maximum of 10 points). According to the results, market and 
grid  structure  have  a  lower  relevance,  with  a  median  of  8  points  and,  finally,  the 
administrative process with 7 points is considered as the less relevant factor. These 
results are in concordance with the study performed by Lüthi and Prässler [69], which 
concluded  that  project  developers  rank  regulatory  security  as  the  most  important 
barrier, remuneration as second and administrative process duration as third. 

Figure 9: Relevance of the main categories of possible barriers to RE diffusion [68]. 

Each  one  of  the  above-mentioned  main  barrier  types  can  be  divided  into  several 
subcategories: 

  Political  and  economic  framework:  revenue  risk  under  the  support  schemes, 
remuneration  level,  reliability  of  the  regulatory  framework  and  access  to 
finance. 

29 

109876543210RelevancePolitical and economic frameworkMarket structure and regulationGrid regulationand infrastructureAdministrative processes 
WindValueEU 

Part 1: Regulatory Framework 

  Grid regulation and infrastructure: cost of access to the grid, duration of the 
connection  period,  transparency  of  the  procedure,  curtailment  and  grid 
development. 

  Market  structure:  fair and  independent regulation  of  the  wind  energy  sector, 
existence of functioning, non-discriminatory, short-term markets, availability of 
long-term contracts and enough market competition and volume. 

  Administrative process: complexity, spatial and environmental planning, cost of 

administrative procedure and duration of the procedure. 

  Other: operational issues, public perception, communication between relevant 

stakeholders and taxes. 

It  should  be  noted  that,  despite  some  specific  barriers  affecting  in  different  ways 
onshore and offshore wind energy, the results presented in this section are common 
for both onshore and offshore wind. 

2.7.1. 

Political and economic framework 

According  to  the  results  of  the  survey  performed  by  the  DiaCore  project,  the  most 
important factor, in regard to political and economic framework, is the reliability of the 
regulatory  framework,  followed  by  the  remuneration  level,  risk  under  the  given 
support scheme (with similar rating) and access to finance (rated as the less important 
barrier). 

Figure 10 shows the barriers identified in the interactive database, RE-frame [70]. This 
online tool allows users to insert new barriers, as well as to see and comment on the 
already  existing  barriers.  The  barriers  reported  by  the  stakeholders  in  this  database 
have been employed by the Keep on Track! project in the report Analysis of Deviations 
and Barriers 2013/2014 [71]. 

The dominant category is the reliability of the regulatory-framework barrier that has 
been  reported  in  17  MSs.  Introduction  of  new  levies  and  taxes  (as  in  the  case  of 
Bulgaria, Greece, Latvia, Portugal and Spain), as well as continuous changes, are the 
main issues featured under this category. A subsequent issue of the lack of reliability 
is the difficult access to financing in those markets that do not offer enough regulatory 
security (this barrier has been reported in 11 MSs, with different levels of severity). 

Figure 10: Reported barriers regarding political and economic framework in MS (based in 
[70]). 

30 

ATBEBGCYCZDEDKEEESFIFRGRHRHUIEITLTLULVMTNLPLPTROSESISKUKRevenue riskRemmuneration levelReliability of regulatory frameworkAccess to finance 
WindValueEU 

Part 1: Regulatory Framework 

2.7.2. 

Grid regulation and infrastructure 

Figure  11  summarizes  the  potential  barriers  identified  that  relate  to  grid  regulation 
and infrastructure. Cost of grid access has been reported as a barrier in the 8 MSs that 
adopted a non-shallow cost model for grid connection. 

Long duration of the connection process is mainly caused by complex or inefficient 
procedures involving a large number of administrations or too many steps, as well as 
the  presence  of  (connection)  demand  saturation  and  non-homogenous  procedures 
for grid connection [65]. The following procedural issues have been highlighted: 

 

 

 

In Finland, a large number of grid operators  exists with significantly different 
procedures. 

In Bulgaria, a moratorium for renewable energy grid connection entered into 
force in 2010. 

In  Poland,  developers  have  to  provide  advance  payments  for  the  grid 
connection concession. They claim that such payment leaves them in a weak 
position when negotiating the connection conditions. Also, advanced payments 
can be a barrier for small players with lower financial resources. However, these 
payments  might  be  necessary  to  avoid  "free  riders"  from  taking  over  grid 
connection points thus blocking the access of real developers. 

 

In Slovakia, developers complain about a moratorium for the connection of new 
renewable installations applied by the distribution system operators. 

Energy  curtailment  normally  involves  a  reduction  of  prospective  income  with  or 
without  compensation.  Curtailment  is  the  requirement  to  reduce  or  stop  wind 
electricity  production  because  of  certain  operational  conditions,  and  it  has  been 
reported in 13 MSs. Furthermore, in 7 MSs (Belgium, Estonia, Finland, Hungary, Poland, 
Portugal and Slovenia) curtailment conditions are not defined by regulation, and in 3 
MSs  (Italy,  Poland  and  Portugal),  compensation  is  not  provided  in  case  of  energy 
curtailment. In Belgium, the conditions for curtailment are decided during the permit 
process  so that compensation can be offered or not depending on the distribution 
system operator. In Germany, curtailment may not be compensated depending on the 
operating  circumstances.  Plant  operators  state  that  in  case  of  non-compensated 
curtailment,  the  system  operators  are  in  a  strong  position,  since  it  is  difficult  to 
question the grid operating decisions. 

Grid development is a common barrier  hindering further wind deployment. Usually, 
the growth rate of installed renewable sources is higher than the rate of development 
or reinforcement of the electricity grid. This problem is compounded when wind farms 
are located far from consumption centres (as is the case in countries such as Finland, 
Greece, the UK and Italy). 

31 

 
WindValueEU 

Part 1: Regulatory Framework 

Figure 11: Reported barriers regarding grid regulation and infrastructure in MS (compiled 
from [60], [65] and [70]). 

2.7.3. 

Administrative procedure 

Complexity  of  procedures  and  long  duration  of  the  licensing  process  are  the  main 
administrative issues, as depicted for each MS in Figure 12. According to the results 
obtained  by  the  Wind  Barriers  project  [60],  the  total  time  required  to  obtain  the 
building  permit  can  vary  significantly  from  one  country  to  another  from  2  to  154 
months. Duration of the permitting process is mainly related with the approval and 
scope of the Environmental Impact Assessment, compliance with spatial planning and 
the number of authorities to contact. In some cases,  radar issues (both military and 
civilian) can further complicate the situation. 

Figure 12: Reported barriers regarding administrative process in MSs (compiled from [65], 
[70]). 

The following administrative issues are highlighted in the RE-frame database: 

 

 

 

 

In  Flanders,  developers  state  that  a  construction  permit  can  be  refused  for 
environmental  reasons,  even  in  the  case  where  an  environmental  permit  has 
been  previously  granted.  In  Wallonia,  some  projects  with  permits  already 
granted are sued due noise rules, facing judicial uncertainty and possible delays. 
In France, stakeholders reported that the high number of appeal proceedings 
(between  3  and  6  legal  permits  are  required)  can  be  a  major  barrier,  and  a 
similar problem is reported in Greece with a high number of appeals against 
wind projects. 
In  Romania,  developers  complain  about  non-harmonised  administrative 
procedures, since environmental authorisations and construction licenses can 
vary significantly between different regions. 
Interference with radars is a generalised issue among MSs. This barrier has been 
reported  in:  Belgium,  Estonia,  Finland,  France,  Germany,  the  Netherlands, 
Sweden and the United Kingdom. 

32 

ATBEBGCYCZDEDKEEESFIFRGRHRHUIEITLTLULVMTNLPLPTROSESISKUKCost of grid accessDurationTransparencyCurtailmentGrid developmentATBEBGCYCZDEDKEEESFIFRGRHRHUIEITLTLULVMTNLPLPTROSESISKUKComplexity of administrative procedureSpatial and environmental planningCost of administrative procedureDuration of administrative procedure 
 
WindValueEU 

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2.7.4.  Market design 

As  renewable  energy  generators  become  significant  players  in  the  energy  markets, 
higher participation in the electricity and balancing markets is required to encourage 
overall system cost effectiveness and to steer efficient investment decisions. However, 
when operators are exposed to non-competitive balancing prices, only a proper design 
of the electricity  market may avoid  unduly penalisation. Thus,  trading close to real-
time is particularly important since generation forecasts significantly improve closer to 
production time. In this sense, the existence of intra-day markets is necessary in order 
to minimize the cost of balancing for wind generators and reduce support needs. 

Figure 13: Reported market design and structure barriers in MS (compiled from [70], [65]). 

Market concentration in the hands of incumbents is another important factor, for both 
wholesale  and  balancing  markets,  which  can  create  conditions  of  unfair 
competitiveness for wind generators. 

Table 11 shows the indicators of concentration level in electricity markets reported by 
Eurostat  for  the  year  2012  [72].  Other  than  Malta  and  Cyprus,  where  one  company 
produces  all  electricity,  the  highest  concentration  corresponds  to  Latvia  (89.0  %), 
Estonia (88.0 %), France (86.0 %), Croatia (82.0 %) and Luxembourg (81.8 %). 

Table 11. Indicators of electricity market concentration in EU MSs 

AT 

57 

145 

4 

IE 

55 

5 

BE 

66 

46 

2 

IT 

26 

291 

BG 

28 

5 

LT 

30 

17 

I1 

I2 

I3 

I1 

I2 

1 

1 

LU 

82 

4 

CY 

100 

CZ 

68 

DE  DK 

37 

73  >450  ~1300 

1 

4 

2 

LV  MT  NL 

EE 

88 

5 

1 

PL 

16 

ES 

24 

4 

PT 

37 

100 

89 

17 

1 

800 

111 

112 

3 

5 

1 
6 
I3 
I1: Market share of the largest generation company 
I2: Number of companies generating 95% of national production or more 
I3: Number of big companies (representing each more than 5 % of total) 

4 

4 

2 

1 

4 

FI 

25 

30 

4 

RO 

27 

11 

5 

FR 

86 

>5 

1 

SE 

44 

74 

3 

GR  HR  HU 

77 

82 

2 

2 

SK 

79 

11 

1 

3 

SI 

55 

3 

2 

47 

32 

4 

UK 

52 

17 

7 

2.7.5. 

Other potential barriers 

Besides  the  above-mentioned  issues,  there  are  also  a  number  of  other  potential 
barriers for wind development. Particularly, public perception is a generalised issue in 
Europe  for  large  infrastructure  projects  (as  shown  in  Figure  14,  specifically  for  wind 
energy,  this  barrier  is  present  in  13  MSs).  The  lack  of  public  awareness  about  the 
benefits of  wind  energy and the perception as an expensive technology may cause 
resistance to a wider wind deployment. Public opposition and a strong position of anti-

33 

 
 
 
 
 
 
 
 
 
 
WindValueEU 

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wind  lobbies  can  hinder  public  willingness  for  further  wind  deployment,  as  well  as 
increase the number of legal processes against wind projects. 

Lack  of  information  between  relevant  stakeholders  (namely  project  developers, 
administration,  regulators  and  grid  operators)  has  also  an  influence  over  wind 
development. This lack of information exchange has been reported in 8 MSs. 

in  some  countries,  plant  operators  complained  about  tax  regimes 
Finally, 
discriminatory for wind generation. As an example, in France the so-called IFER tax is 
paid  by  all  electricity  producers,  but  the  amount  is  higher  for  wind  plants  than  for 
conventional energy sources. In Romania, a new tax was created for renewable energy 
producers  consisting  of  1.5  %  on  the  value  of  the  equipment.  In  Spain,  taxes  at 
municipal level for wind generators have increased and there are other imposed taxes 
that are not homogenous at a national level (a new levy in several regions applies only 
to  wind  generators).  Finally,  also  in  Spain,  a  7%  tax  was  introduced  in  2013  for  all 
generation technologies. However, whereas renewables cannot pass on the cost of the 
tax  because  it  is  imposed  on  revenue  from  the  FiT,  conventional  generators  can 
increase their bids in the wholesale market by the new extra expense, and thus pass 
on the tax cost onto consumers. 

Figure 14: Other potential barriers to wind power deployment (compiled from [70], [65]). 

34 

ATBEBGCYCZDEDKEEESFIFRGRHUIEITLTLVMTNLPLPTROSESISKUKPublic perceptionInformation exchangeTaxing regime 
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3.  Overview and analysis of the regulatory framework for 

offshore wind energy. 

Most aspects of the regulatory framework, including grid operation issues and barriers, 
cover both onshore and offshore wind, and they have been presented in the previous 
section. Therefore, this chapter presents a brief overview and analysis of the differences 
for offshore wind energy, e.g. in the permitting and connection procedures. 

Figure 15: Evolution of support schemes for offshore wind energy in BE, DK, DE, NL and UK. 

Figure 15 shows an overview of the evolution of support schemes for offshore wind 
energy in Belgium (BE), Denmark (DK), Germany (DE), the Netherlands (NL) and the 
United Kingdom (UK). As offshore wind is a less mature technology, it is projected that 
it will achieve a high cost reduction by applying technological improvements under 
economies  of  scale.  Due  to  this  reason,  some  MSs  implemented  specific  support 
schemes or adapted the remuneration level, such as Belgium, Denmark, Germany, Italy, 
the Netherlands and the United Kingdom. France offers a FiT for offshore wind farms 
with an agreement of purchase before 28 May 2014, but actual support to offshore 
wind farms is currently available under a tendering scheme. 

Table 12. Main features of the TGC system for offshore wind energy in Belgium 

Belgium 

TGC 
Base 

Penalty 

Minimum 

Maximum 

Validity 
(years) 

Eligibility 
(years) 

1MWh 

- 

107 €/MWh (0-216 MW) 
90 €/MWh (>216 MW) 

- 

5 

20 

Offshore  wind  development  in  Belgium  depends  on  the  federal  government,  which 
offers the TGC support scheme. The minimum price of green certificates for an offshore 
wind power plant is 107 € for the first 216 MW and 90 € for capacity exceeding this 
amount  [73].  However,  as  long  as  there  is  no  certificate  market  for  offshore  [62], 
producers receive the minimum guaranteed price for certificates that are financed by 
a surcharge in electricity bills. Also, additional aid is provided in Belgium by financing 
the connection costs with a maximum of 25 M€ per project. 

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As  shown  later  in  Section  4,  in  Denmark,  the  FiP  is  selected  based  on  one  of  two 
approaches: 

  Calls for tender.  Denmark set up the FiP for  each project through auctions. As a 
result,  a  FiP  of  69.5  €/MWh  was  granted  for  the  Horns  Rev  2  wind  farm 
(commissioned in 2009), 84.4 €/MWh for Rødsand 2 (2010) and 140.7 €/MWh in 
the case of the Anholt wind farm (2013). Furthermore, the tender for Horns Rev 3 
(400 MW) was recently granted at 103.1 €/MWh and another auction, for Kriegers 
Flak (600 MW), will follow next year. In all cases the FiT is paid for the first 50 000 
FLH of operation, between 11 and 12 years of normal operations. 

  Open-door  procedure.  Offshore  wind  farms  under  the  FiP  scheme  commissioned 
after  February  2008  receive  a  premium  of  30  €/MWh  for  22 000  equivalent  full 
hours plus 3 €/MWh for covering the balancing costs. Also, in coastal projects, a 20 
%  share  of  the  ownership  of  the  project  has  to  be  offered  to  local  residents  or 
companies [73]. If this share achieves 30 %, an extra bonus of 1.3 €/MWh can be 
awarded over the FiP [37]. In the same sense, guarantees for loans taken out by 
local  owners  are  provided  by  the  Danish  transmission  system  operator, 
Energinet.dk. 

In Italy, the fare to be received during 25 years is determined by a tendering scheme 
with a base price for offshore projects of 165 €/MWh. In order to be admitted to the 
tender process, bidders have to offer a reduction over the base price between 2-30 %. 
No commercial offshore wind farm exists yet in Italy. 

In  the  Netherlands,  offshore  wind  farms  can  apply  for  the  subsidy  under  the  SDE+ 
programme. The specific rates and phases for offshore wind  farms  are the  same as 
shown in Table 4 (except for Stages 4 to 6, for which the rates are, respectively, 137.5 
€/MWh, 162.5 €/MWh and 187.5 €/MWh). The subsidy is granted for a period of 15 
years and a maximum of 3000 equivalent hours each year. 

Table 13. Summary of specific regulatory frameworks for offshore wind energy. 

Belgium  Denmark  Germany 

Italy 

Nether-
lands 

United 
Kingdom 

Support 
scheme 
Determination 
of 
remuneration 
Priory dispatch 
Balancing 
obligation 

TGC 

FiP 

FiP 

FiT 

FiP 

TGC/CdF 

Market -
based 

Tender 

Administrati
ve 

Tender 

Tender 

Market 
based/tender 

Yes 

Yes 

No 

Yes 

Yes 

Yes 

Yes 

No 

No 

Yes 

No 

Yes 

Under  this  process,  offshore  wind  energy  competes  with  all  other  technologies 
covered by the SDE+ scheme by taking into account a ceiling of 3.5 b€ for the entire 
programme  for  2014.  Nevertheless,  a  new  specific  scheme  for  offshore  wind  was 
announced by the Dutch Government on 26 September 2014. Under this scheme, the 

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successful applicant is selected by a competitive bidding process exclusive to offshore. 
The new bill is expected to enter into force on 1 July 2015 [74]. Dutch offshore projects 
have also gained already preferential loan  conditions from the Economisch Instituut 
voor de Bouw. Finally, offshore wind farms are entitled to write off investments against 
tax with a maximum investment of 1000 €/kW of installed power. 

In  the  United  Kingdom,  offshore  wind  farms  are  eligible  to  support  via  its  TGC 
("Renewables Obligation") and in the new CfD. Two certificates are issued per MWh 
(i.e. 0.5 MWh/certificate) generated by an offshore wind farm, which will be modified 
in 2015/2016 to 0.53 MWh and finally to 0.55 MWh after 2016. This way, the level of 
support received by offshore wind farms is similar to solar photovoltaic plants (that 
also receive two certificates per each MWh generated) and slightly more than twice as 
much  as  onshore  wind  (1.11  certificates  per  MWh).  Regarding  additional  support, 
offshore  wind  energy  is  also  exempted  of  paying  the  Carbon  Price  Floor  and  the 
Climate Change Levy. 

The UK Renewables Obligation will be phased out and replaced by an auction-based 
feed-in tariff structure called “Contract for Differences” (CfD), as mentioned in section 
2.3. 

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4. 

In-depth  analysis  of  Belgium,  Denmark,  Germany,  the 
Netherlands  and  the  United  Kingdom  offshore  wind 
power regulation. 

This section presents in more detail the permitting aspects in the five MSs with the 
highest degree of offshore wind power deployment. The analysis focusses on: 

  Permitting process: maritime spatial planning, authorities involved, applicable 

laws and barriers. 

  Submarine transmission system and grid connection: procedure, cost sharing 

of expansion and grid reinforcement. 

4.1.  Belgium 
The  zone  reserved  in  the  Belgian  part  of  the  North  Sea  for  offshore  wind  energy 
exploitation is set by the Royal Decree of 17 May 2004. The designated area covers 
270 km² for a total capacity of 2 000 MW [75]. To develop an offshore wind farm, a 
candidate developer requires [76]:  

  A domain concession (right to occupy a parcel) in the zone reserved for wind 
development: the Law on the organisation of the electricity market stipulates 
the conditions and a specific procedure that must be fulfilled for granting an 
offshore concession. 

  An environmental permit: this procedure has several steps, including a public 
hearing  where  the  public  concerned  can  express  their  objections.  The 
Management Unit of the North Sea Mathematical Models of the Royal Belgian 
Institute  of  Natural  Sciences  renders  advice  on  the  possible  environmental 
impact  of  the  future  project  to  the  Minister  responsible  for  the  marine 
environment  by  also  taking  into  account  the  environmental  impact  study 
carried out by the project developer. 

  Authorisation for the construction and operation: this is issued by the Ministry 
of the Environment to carry out a specific activity under  specified  conditions 
and during a given period. 

Furthermore,  a  monitoring  programme  to  assess  the  effects  of  the  project  on  the 
marine environment is imposed once the environmental permit is granted [77]. 

Grid connection 

The offshore grid connection procedure is the competence of the federal authorities. 
The general process is shown in Figure 16, the process is very similar to the onshore 
case [78]. The first step is optional; the plant developer requests an orientation study 
about  the  estimated  costs  of  connection.  Next,  the  plant  developer  applies  for 
connection to the transmission system operator which will perform a detailed study 

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by proposing the technical solution for the grid connection, and a cost proposal. If the 
applicant accepts, the parties sign a connection agreement. 

The plant developer bears the costs of the grid connection to the onshore substation 
(shallow approach). Nevertheless, these costs are partially subsidised by 33 % of the 
investment  up  to  a  maximum  of  25  M€.  The  subsidy  is  spread  over  five  years  (by 
providing 20% each year) and is covered by the transmission system operator. 

Figure 16: Grid connection procedure for offshore wind farms in Belgium. 

4.2.  Denmark 

In Denmark, the zones designated to offshore wind power exploitation are defined in 
the report Future Offshore Wind Turbine Locations – 2025 [79] published in April 2007 
and  last  updated  in  April  2011.  Permits  are  granted  by  the  Danish  Energy  Agency, 
which acts as a one-stop shop for the project developer. In total 3 licences, granted 
consecutively, are required to establish an offshore wind project: 

1.  License to carry out preliminary investigations. 

2.  Licence  to  establish  the  offshore  wind  turbines  (only  given  if  preliminary 
investigations show that the project is compatible with the relevant interests at 
sea). 

3.  Licence to exploit wind power for a given number of years, and an approval for 
electricity production (given that conditions to establish the project are met). 

Two procedures are available to apply for the establishment of an offshore wind farm: 

  Calls for tender. The areas for tender for an offshore wind farm (both near-shore 
and located in the exclusive economic zone) are set in the Renewable Energy Act. 
For a given suitable project with a defined geographical area and rated capacity, 
the Danish Energy Agency invites applicants to submit a quotation for the fixed 
price that the applicant is willing to receive for producing electricity for a defined 
number  of  full-load  hours,  normally  50 000.  According  to  [73],  the  tender 
procedure  in  Denmark  provides  several  measures  to  assure  a  proper  degree  of 
security  of  investment  and  a  simplified  process  for  bidders,  a  one-stop-shop 
procedure,  and  providing  the  draft  permits.  Additionally,  the  required 
environmental  impact  assessment  has  to  be  performed  by  Danish  authorities 
before tender submission starts. 

40 

ConnectionApplicationDetailed StudyDomain ConcessionConnection AgreementConnectionOrientationStudy (optional) 
 
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  Open-door  procedure 43 .  Under  this  method,  the  project  developer  takes  the 
initiative to establish an offshore wind farm in a specific area. Before processing 
the  application,  the  Danish  Energy  Agency  initiates  a  hearing  with  other 
government bodies to analyse whether other major public interests can interfere 
on the project implementation. If the area can be developed, the Danish Energy 
Agency issues an approval to carry out the preliminary investigations including an 
Environmental  Impact  Assessment.  Areas  previously  established  for  tendering 
under the Renewable Energy Act cannot be applied under this procedure [80]. 

The procedure includes a measure addressed to increase local acceptance for near-
shore wind farms: the developer of an offshore wind farm is obliged to offer at least 
20 % of its property to residents in the municipalities that have a coastline within 16 
km of the project [80]. Nevertheless, there is only an obligation to offer this share, not 
to achieve it [81]. 

Grid connection 

According to [82], the procedure for grid connection is widely considered as simple 
and  transparent,  despite  the  procedural  steps  not  being  specified  by  law.  The  grid 
operator is obliged to connect any wind power plant that fulfils the grid connection 
requirements set by the Ministry for Energy [37]. 

For the further-offshore, such as the ongoing tenders for Kriegers Flak and Horns Rev 
3, the transmission system operator(Energinet.dk) bears the costs of grid connection 
to the offshore substation (ultra-shallow approach) [82], and is required to ensure the 
connection to be operative at the agreed date. 

In order to ensure coordination with the transmission system operator, the developer 
must provide the following information [83]: 

  Submit technical information on equipment for installation at the platform (e.g. 

September 2015 for Horns Rev 3). 

  Equipment for installation at the platform is to be delivered to the yard no later 

than a previously defined date (e.g. November 2015 for Horns Rev 3). 

  The  developer  should  provide  information  no  later  than  1  December  2015 
(again in the case of Horns Rev 3) about the desired date for energisation of 
the transformer platform and installation of cables. 

However, plant developers of near-shore projects, either established by tenders or by 
the open-door procedure, have to bear the costs of their own offshore substation and 
connection  to  land  (shallow  approach)  [73].  The  grid  connection  procedure  is 
summarised in Figure 17. The process starts with submission of the necessary permits 
and licences together with the application to the grid operator. Next, grid operator 
and  plant  developer  conclude  a  connection  agreement.  When  the  plant  is 

43 All recent operating wind farms have tariffs established by call for tenders. 

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commissioned, the grid operator gives temporary permission to operate before final 
permission is granted [37]. 

Figure 17: Grid connection procedure for offshore wind farms (open-door procedure and near-
shore projects by tenders) in Denmark. 

4.3.  Germany 
In Germany, the maritime spatial plan for the Exclusive Economic Zones is performed 
by the Bundesministerium für Verkehr und digitale Infrastruktur, BMVI, (Federal Ministry 
of Transport and Digital Infrastructure) and, in the case of territorial waters (12 nautical 
mile  zone),  by  the  corresponding  state  authority.  The  Federal  Maritime  and 
Hydrographic Agency is in charge of the application procedure for wind farms located 
in the German exclusive economic zone [84]. 

In  order  to  obtain  the  approval,  the  wind  farm  project  has  to  meet  the  following 
conditions: 

1.  It is not a risk to the safety and efficiency of navigation. 

2.  It is not damaging to the marine environment. 

The approval and permit process consist of the following steps: 

1.  Project  application  and  participation  of  public  interest  parties  (such  as  water 
and  shipping  authorities,  Federal  Agency  for  Nature  Conservation,  etc.)  and 
interest groups (fishing, nature conservation associations, etc.). 

2.  Application conference. The applicant gives  a presentation about the project 
discussing  the  potential  conflict  with  the  protected  assets  (fauna,  soil,  water, 
etc.) in the Offshore Installations Ordinance [85] and with other private or public 
stakeholders involved in the project. 

3.  Preparation  of  the  report  and  further  documents.  On  the  basis  of  the 
environmental  studies,  the  applicant  prepares  an  Environmental  Impact 
Assessment. A risk analysis dealing with the probability of vessels colliding with 
wind farm installations is also mandatory. 

4.  Consideration  and  approval.  After  receiving  the  documents,  the  Federal 
Maritime and Hydrographic Agency passes the documents to the competent 

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authorities and associations asking for their comments. The Federal Maritime 
and  Hydrographic  Agency  then  reviews  if  the  requirements  for  granting 
approval have been met. At the same time, the competent regional authority 
deliberates  if  consent  can  be  granted  in  relation  to  safety  and  efficiency  of 
navigation. 

If  both  authorities  agree  with  the  project,  the  approval  is  issued  for  a  period  of  25 
years. Also, to prevent the areas to be reserved for future use, construction of the wind 
farm has to start within 2.5 years after notification of the approval [85]. 

Grid connection 

Based on the amended Renewables Energy Act, in August 2014, the Federal Network 
Agency (BNetzA) approved a new procedure for grid connection capacity allocation. It 
reflects the government’s target to achieve 6.5GW of offshore wind in 2020. Capacity 
allocations up to 7.7 GW are possible to the end of 2017 and 6.5GW afterwards up to 
2020  (the  procedure  also  provides  for  capacity  withdrawals  in  case  development 
deadlines are not achieved in wind farms  which already have an  unconditional grid 
connection commitment). From 2020 onwards, 800MW are added each year. 

If  demand  surpasses  the  connection  capacity  offered,  e.g.  at  an  individual  grid 
connection line, capacity allocation is carried out through a tender process. Admission 
to the capacity allocation process requires: BSH permit, a soil  study report, and the 
availability of free capacity within the cluster on a grid connection line. Within the wind 
farms  allowed  to  participate  in  such  a  tender,  the  offer  price  is  the  only  criteria  for 
capacity allocation. The winners of the tender have to pay the pay-as-cleared price. At 
the beginning of each capacity allocation procedure, BNetzA publishes the available 
capacity  to  reach  the  government’s  target  and  the  free  capacity  on  each  grid 
connection line. Initially this process shall be conducted every 9 months, provided the 
prior tender has already finished and free capacity is available. 

4.4.  The Netherlands 
A draft for a new offshore wind act was published on 20 March 2014 by the Ministry 
of  Economic  Affairs  and  the  Ministry  of  Infrastructure  and  Environment.  On  26 
September  2014,  the  Dutch  government  announced  the  chosen  areas  for  offshore 
wind deployment: Borssele (1 400 MW), Hollandse Kust Zuid-Holland (1 400 MW) and 
Hollandse Kust Noord-Holland (700 MW). The first area, Borssele, is located outside the 
12-mile zone and it  was already designated  in 2009 under the National Water Plan 
2009-2015.  The  other  two  designated  areas  (Hollandse  Kust  Zuid-Holland  and 
Hollandse  Kust  Noord-Holland)  are  also  located  outside  the  territorial  waters  but 
expanded with narrow strips to a maximum of 2 nautical miles within the 12-mile zone 
[86]. 

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Under  the  new  act,  a  tender  procedure  is  proposed.  The  new  projects  can  only  be 
constructed in previously-defined plots within the designated areas under the National 
Water Plan. The main steps of the proposed procedure are: 

  Designation  under  the  National  Water  Plan  of  the  areas  for  offshore  wind 

energy deployment. 

  Selection  of  the  new  wind  farm  location  and  conditions  of  construction  and 
operation. The Ministry of Economic Affairs and the Ministry of Infrastructure 
and  the  Environment  are  the  competent  authorities  in  this  regard.  An 
environmental impact assessment and an appropriate assessment on the basis 
of the Dutch Nature Conservation Act are also required at this stage. 

  During  the  decision  process  on  the  location  of  wind  farms,  the  Government 
performs  specific  studies  about  wind,  soil  and  water  conditions  in  order  to 
provide a good insight into the construction and operation conditions. 

  The developer of the wind farm is finally selected by a tender procedure where 
the lowest bidder (if the bid is below the previously defined maximum amount) 
is awarded to construct and operate the project. 

Grid connection 

Under the general case the cost of the connection is borne by the plant developer in 
a shallow approach. The general process regarding grid connection is shown in Figure 
18. The first step is requesting grid connection to the grid operator. Secondly, the grid 
operator  will  provide  a  preliminary  design  about  how  the  connection  will  be 
implemented. If the plant developer agrees with the proposed design, the connection 
agreement is signed [87]. 

Figure 18: Grid connection procedure for offshore wind farms in the Netherlands. 

Under the new tenders, however, the Netherlands is presenting a new approach, which 
could be called hyper-shallow, for which the installation of the offshore substation is 
responsibility of the TSO, TenneT, and the tender winners are offered the substation 
as connecting point. 

4.5.  The United Kingdom 
The  Marine  and  Coastal  Access  Act  2009  divides  the  UK  marine  areas  into  marine 
planning regions with an associated planning authority who prepares a marine plan 
for the area. 

44 

ConnectionApplicationConnection offer by the TSOConnectionAgreementGrid extension or reinforcement (if necessary) 
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Decisions on where offshore wind farms can be located are made in two stages [88]. 
First, the Department for Energy and Climate Change performs the Offshore Energy 
Strategic Environmental Assessment. Second, the Crown Estate (which grants leases 
for  the  use  of  the  UK  seabed)  designs  the  suitable  zones.  In  2009,  under  the 
programme  Round  3,  a  competitive  process  awarded  these  zones  to  different 
developers. 

In England and Wales, depending on project size, the regulatory planning authority 
varies [89]: 

  Marine  licencing  for  activities  in  the  sea  is  the  responsibility  of  the  Marine 
Management  Organisation  who  can  also  grant  development  consent  for 
offshore renewable projects under 100MW. 

  For projects above 100MW, the development consent application is assessed 
by the Planning Inspectorate and the recommendation is made to the Secretary 
of State for Energy and Climate Change who makes the final decision. 

  Development  consent  for  any  associated  development  (for  example  onshore 
substation) located in Wales is the responsibility of the relevant Welsh planning 
authority. 

In Scotland, licensing is organised by a one-stop-shop model managed by the Marine 
Scotland Licensing Operations Team [90]. 

Grid connection 

The main difference between the connection procedures in the UK and other countries 
is that transmission infrastructure to shore is (in general) built by the developer, and 
then outsourced (through a tender) to other entities that receive a transmission fee. 
This tender process can occur at various stages of the construction process [92]: 

  Early-build  approach.  The  operator  of  the  offshore  transmission  system  is 
responsible for planning, consenting, construction, operation and ownership of 
the link. 

  Late-build approach. The operator of the transmission system is responsible for 

construction, operation and ownership of the link. 

  Generator-build approach. The plant developer builds the connection system 
and  the  transmission  system  operator  is  responsible  for  its  operation  and 
ownership. To date this is the most common procedure. 

Depending  on  the  chosen  option  (connection  built  by  the  plant  owner  or  by  the 
offshore system operator), the revenues stream takes into account the compensation 
for  the  assumed  costs  in  each  case  (planning,  consenting,  construction  and/or 
operating costs). 

As shown in Figure 19, the connection procedure is composed of the following steps 
[91]: 

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WindValueEU 

Part 1: Regulatory Framework 

1.  The  plant  developer  submits  the  connection  application  to  the  transmission 

system operator (National Grid). 

2.  The transmission system operator prepares a transmission owner reinforcement 

instruction. 

3.  Within  three  months  after  the  reception  of  the  application,  the  transmission 
system operator makes a connection offer, including the onshore connection 
point. 

4.  The generator accepts/rejects the connection offer within the following three 

months. 

5.  A tender process is undertaken by the Office of Gas and Electricity Markets, in 

case of a late-build approach. 

6.  The offshore transmission system operator is selected. 

7.  Signing of agreements 

Figure 19: Connection procedure for offshore wind farms in United Kingdom. 

This  procedure  is  an  extension  of  the  onshore  connection  regime.  For  onshore 
installations,  the  connection  of  new  generators  is  supervised  by  the  national 
transmission  operator  and  finally  transferred  to  the  onshore  transmission  operator 
responsible  for  the  corresponding  area  (National  Grid  Electricity  Transmission  for 
England and Wales, Scottish Power Transmission Limited for southern Scotland, and 
Scottish Hydro-Electric Transmission Limited for northern Scotland). However, in the 
case  of  a  new  offshore  generator,  there  is  no  responsible  transmission  operator. 
Therefore, the owner and operator of the new transmission link is selected by a tender 
process. 

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References 

[1]  European Commission. (2009). Directive 2009/28/EC of the European Parliament 
and of the Council of 23 April 2009 on the promotion of the use of energy from 
renewable  sources  and  amending  and  subsequently  repealing  Directives 
2001/77/EC and 2003/30. Official Journal of the European Union Belgium. 
[2]  Couture,  T.  and  Gagnon,  Y.  (2010).  An  analysis  of  feed-in  tariff  remuneration 
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