COMMISSION STAFF WORKING DOCUMENT Accompanying the document REPORT FROM THE COMMISSION Final Report of the Sector Inquiry on Capacity Mechanisms
Date: 2016-11-30
Institutions: Directorate-General for Competition, European Commission
Subjects: State aid, climate change policy, electrical energy, electricity supply, energy supply, investment promotion, price of energy, security of supply, self-sufficiency in energy, single market

EN 

   EN 

   EUROPEAN COMMISSION  Brussels, 30.11.2016  SWD(2016) 385 final   COMMISSION STAFF WORKING DOCUMENT Accompanying the document REPORT FROM THE COMMISSION Final Report of the Sector Inquiry on Capacity Mechanisms {COM(2016) 752 final}  
 
 
Table of Contents 

1. 

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

1.1  Concerns about the security of electricity supply ........................................................ 5 

1.2 

1.3 

1.4 

1.5 

The Energy Union and the Market Design Initiative .................................................. 5 

The Energy and Environmental Aid Guidelines .......................................................... 6 

The sector inquiry: what has the Commission done so far? ........................................ 7 

Set-up of the Staff Working Document ....................................................................... 8 

2. 

Increased generation adequacy concerns .......................................................................... 10 

2.1 

The electricity sector in transition ............................................................................. 10 

2.1.1

2.1.2

2.1.3

The liberalisation of electricity markets ............................................................. 10 

Decarbonisation policies .................................................................................... 12 

Concerns about security of supply ..................................................................... 13 

2.2 

Incentives for future investment in generation .......................................................... 24 

2.2.1

Expectations about future development of generation and demand .................. 25 

2.2.2

  Market and regulatory failures undermining incentives to invest ...................... 27 

2.2.3

Conclusions on the lack of optimal incentives to invest .................................... 39 

2.3  What is being done to alleviate imperfections of EU electricity markets? ............... 39 

2.3.1

2.3.2

Improving the functioning of the electricity market .......................................... 40 

Addressing residual market failures with a capacity mechanism ...................... 47 

3.  Member State interventions: overview and classification ................................................ 50 

3.1 

Types of capacity mechanisms .................................................................................. 50 

3.1.1

Targeted mechanisms ......................................................................................... 50 

3.1.2

  Market-wide mechanisms .................................................................................. 51 

3.2  Capacity mechanisms in place in the 11 Member States ........................................... 52 

3.2.1

3.2.2

3.2.3

3.2.4

3.2.5

3.2.6

Tender for new capacity ..................................................................................... 55 

Strategic reserve ................................................................................................. 57 

Interruptibility schemes ...................................................................................... 60 

Targeted capacity payments ............................................................................... 61 

Central buyer ...................................................................................................... 63 

De-central obligation .......................................................................................... 65 

3.2.7

  Market wide capacity payments ......................................................................... 66 

3.3  Conclusions ............................................................................................................... 67 

4.  Adequacy Assessments and Reliability Standards ........................................................... 68 

2 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4.1 

4.2 

Introduction ............................................................................................................... 68 

Findings of the sector inquiry .................................................................................... 68 

4.2.1

Reliability incidents are rare .............................................................................. 68 

4.2.2

  More adequacy problems are expected in the future .......................................... 69 

4.2.3

  Member States carry out increasingly advanced adequacy assessments ........... 71 

4.2.4

  Member State practice in setting reliability standards ....................................... 73 

4.3  Assessment ................................................................................................................ 77 

4.3.1

4.3.2

The absence of a common approach in assessing adequacy .............................. 77 

Reliability standards are not used to ensure appropriate intervention ............... 80 

4.4  Conclusions ............................................................................................................... 80 

5.  Design features of capacity mechanisms .......................................................................... 82 

5.1 

5.2 

Introduction ............................................................................................................... 82 

Eligibility ................................................................................................................... 82 

5.2.1

5.2.2

5.2.3

5.2.4

Eligibility criteria in capacity mechanisms ........................................................ 82 

Findings of the sector inquiry on eligibility ....................................................... 83 

Issues encountered in relation to eligibility ...................................................... 104 

Conclusions on eligibility ................................................................................. 111 

5.3  Allocation Process ................................................................................................... 112 

5.3.1

5.3.2

5.3.3

5.3.4

5.3.5

The role of the allocation process in capacity mechanisms ............................. 112 

Findings of the sector inquiry on administrative allocation processes ............. 112 

Findings of the sector inquiry on competitive allocation processes ................. 116 

Issues encountered in relation to allocation processes ..................................... 119 

Conclusions on allocation processes ................................................................ 123 

5.4 

The capacity product: obligations and penalties ...................................................... 124 

5.4.1

5.4.2

5.4.3

5.4.4

Capacity products ............................................................................................. 124 

Findings of the sector inquiry ........................................................................... 125 

Issues identified ................................................................................................ 132 

Conclusions ...................................................................................................... 138 

6.  Assessment of the various types of capacity mechanisms .............................................. 140 

6.1  Necessity for intervention through a capacity mechanism ...................................... 141 

6.2  Appropriateness and market impacts for each type of mechanism ......................... 142 

6.2.1

6.2.2

6.2.3

Tenders for new capacity ................................................................................. 142 

Strategic reserves .............................................................................................. 145 

Interruptibility schemes .................................................................................... 149 

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6.2.4

6.2.5

6.2.6

Targeted capacity payments ............................................................................. 152 

Central buyer mechanisms ............................................................................... 154 

De-central obligation ........................................................................................ 157 

6.2.7

  Market-wide capacity payments ....................................................................... 160 

6.3  Choosing the right type of capacity mechanism ...................................................... 161 

6.3.1

6.3.2

6.3.3

6.3.4

6.3.5

6.3.6

The main adequacy problems ........................................................................... 162 

Long term concerns .......................................................................................... 163 

Temporary concerns ......................................................................................... 163 

Locational concerns .......................................................................................... 164 

Concerns related to the responsive of the demand side ................................... 165 

Capacity payments are unlikely to be the most appropriate option ................. 166 

6.4  Minimising the cost of capacity mechanisms .......................................................... 166 

6.5  Capacity mechanisms and the decarbonisation objective ........................................ 167 

6.6  Conclusions ............................................................................................................. 168 

Annex 1: Overview of respondents ........................................................................................ 171 

Annex 2: The participation of interconnectors and foreign capacity providers in capacity 
mechanisms ............................................................................................................................ 177 

Annex 3: Summary of Replies of the Public Consultation and Questionnaires to public bodies 
following the publication of the interim report ...................................................................... 208 

Annex 4: References .............................................................................................................. 212 

4 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
1. 

INTRODUCTION 

1.1 

Concerns about the security of electricity supply  

(1) 

(2) 

(3) 

Europe's  electricity  sector  is  experiencing  a  period  of  unprecedented  transition. 
Liberalisation  and  decarbonisation  have  profoundly  changed  the  way  electricity  is 
generated, traded and consumed in the Union, pursuing a more sustainable and at the 
same  time  affordable  electricity  market.  Renewable  energy  sources  have  grown 
rapidly  and  10%  of  total  electricity  is  now  sourced  from  variable  renewable 
electricity, such as wind or solar. 

The  large-scale  roll-out  of  renewables  combined  with  the  overall  decline  in  demand 
have  curbed  the  profitability  of  conventional  generators  and  reduced  incentives  to 
maintain existing power plants or invest in new ones. In many Member States, these 
developments have been accompanied by increased concerns about security of supply. 
Member  States  are  concerned  that  the  electricity  market  will  not  produce  the 
investment signals needed to ensure an electricity generation mix that is able to meet 
demand at all times. 

Some Member States have reacted by taking measures designed to support investment 
in  the  additional  capacity  that  they  deem  necessary  to  ensure  an  acceptable  level  of 
security of supply. These capacity mechanisms pay providers of existing and/or new 
capacity for making it available. 

(4)  When  introduced  prematurely,  without  proper  problem  identification  or  in  an 
uncoordinated  manner,  and  without  taking  into  account  the  contribution  of  cross-
border  resources,  there  is  a  risk  that  capacity  mechanisms  distort  cross-border 
electricity trade and competition. For example, they may reward new investments only 
in certain types of generation or exclude demand response. They may also encourage 
investment  within  national  borders  when  it  would  be  more  efficient  to  reinforce 
interconnection and import electricity when needed. 

1.2 

The Energy Union and the Market Design Initiative 

(5) 

Concerns about the security of electricity supply have been raised by the Commission 
in  the framework of the Energy  Union.1 Under the  internal market dimension of the 
Energy  Union,  the  Commission  envisages  to  take  action  in  the  broader  area  of 
electricity market design and security of electricity supply both of which are related to 
generation  adequacy.  More  specifically,  the  Energy  Union  strategy  states  that  the 
Commission  will  establish  an  objective,  EU-wide,  fact-based  security  of  supply 

1  

Communication from the Commission, 'A Framework Strategy for a Resilient Energy Union with a Forward-Looking 
Climate Change Policy', COM(2015)80 final. 

5 

 
 
                                                 
assessment  addressing  the  situation  in  Member  States.  This  will  take  into  account 
cross-border  flows,  variable  renewable  production,  demand  response  and  storage 
possibilities. 

To  obtain  stakeholders'  views  on  these  ideas,  the  Commission  launched  public 
consultations, firstly, on a new energy market design2 and, secondly, on a review of 
the  Directive  concerning  measures  to  safeguard  security  of  electricity  supply.3 
Together  with  this  report,  the  Commission  also  proposes  legislative  changes  to  the 
energy  market  design  in  order  to  improve  the  functioning  of  the  internal  energy 
market.  

This sector inquiry aims to contribute to the Commission's Energy Union agenda and 
the development of a new market design that is fit for the future by assessing to what 
extent capacity mechanisms are appropriate instruments to ensure sufficient electricity 
supply whilst at the same time minimising the distortion of competition or trade in the 
internal electricity market.  

1.3 

The Energy and Environmental Aid Guidelines 

The  Guidelines  on  State  aid  for  environmental  protection  and  energy  2014  –  2020 
('EEAG')4 include specific rules for assessing capacity mechanisms. The Commission 
has  already  applied  these  rules  to  i.a.  capacity  mechanisms  notified  by  the  United 
Kingdom5 and France6. 

The sector inquiry is not intended to provide a State aid assessment of the existing or 
planned capacity mechanisms in the Member States included in it. The compliance of 
those mechanisms with State aid rules is carried out exclusively in the context of State 
aid decisions.  

(6) 

(7) 

(8) 

(9) 

(10)  The present report rather aims to gather and present information on the functioning of 
capacity  mechanisms  and  draw  tentative  conclusions  which  will  help  with  the 
application of EEAG. The interim report and a previous version of this Staff Working 

2  
3  
4  
5  

6  

COM(2015)340 final. 
https://ec.europa.eu/energy/sites/ener/files/documents/DG%20ENER_ConsultationPaperSoSelectricity14July.pdf.  
Guidelines on State aid for environmental protection and energy 2014-2020 (EEAG) (OJ C 200 of 28.06.2014, p. 1). 
Commission decision C (2014) 5083 final of 23.7.2014 in Case SA.35980 (2014/N-2) – United Kingdom - Electricity 
market reform – Capacity market. The public version of the decision is available at:  
http://ec.europa.eu/competition/state_aid/cases/253240/253240_1579271_165_2.pdf. 
The Commission opened formal investigations into the French country-wide capacity mechanism (SA.39621) and the 
tender  for  a  gas-fired  power  plant  in  Brittany  (SA.40454)  on  13  November  2015.  See:  http://europa.eu/rapid/press-
release_IP-15-6077_en.htm. The Commission's decision on the country-wide capacity mechanism is publicly available 
(in  French)  at:  http://ec.europa.eu/competition/state_aid/cases/261326/261326_1711140_20_2.pdf  and  for  the  tender 
for a gas-fired power plant in Brittany at: 
http://ec.europa.eu/competition/state_aid/cases/261325/261325_1711139_35_3.pdf. 

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Document  were  put  forward  for  public  consultation  on  13 April  2016  to  test  certain 
findings and tentative conclusions as established in the first phase of the investigation.  

(11)  The  information  gathered  in  the  sector  inquiry  has  enabled  the  Commission  to 

understand better: 

 

 

 

 

 

whether, and to what extent, it is necessary that Member States grant State aid 
to ensure security of electricity supply; 

what  types  of  capacity  mechanisms  are  most  suitable  to  ensure  security  of 
electricity  supply,  and  under  which  conditions  capacity  mechanisms  risk 
distorting competition between capacity providers7 and cross-border trade; 

how capacity mechanisms can complement the Single Market for energy rather 
than undermining its functioning;  

how  capacity  mechanisms  for  security  of  supply 
decarbonisation objectives8; and 

interact  with 

the 

how  compliance  with  State  aid  rules  can  be  ensured  when  Member  States 
design and implement capacity mechanisms. 

(12)  To  that  end,  the  Commission  has,  as  a  first  step,  examined  the  reasons  behind  the 
introduction  of  capacity  mechanisms  and  their  design  features.  It  has  examined  a 
number  of  existing  mechanisms  as  well  as  a  number  of  mechanisms  that  Member 
States  plan  to  put  in  place.  The  Commission  has  looked  at  those  mechanisms  in  the 
wider market context including in particular the growing share of renewable energy.  

1.4 

The sector inquiry: what has the Commission done so far? 

(13) 

In order to prepare the interim report, the Commission sent out in spring 2015 detailed 
questionnaires  to  over  200  public  bodies,  energy  regulators,  transmission  system 
operators ('TSOs')  and market participants commercially active on any of the eleven 
markets  under  assessment:  Belgium,  Croatia,  Denmark,  France,  Germany,  Ireland, 
Italy,  Poland,  Portugal,  Spain  and  Sweden.  The  Commission  selected  these  eleven 
Member States because they have either introduced or are considering introducing one 
or more capacity mechanisms. The combination of Member States was also chosen to 
constitute a representative sample of the different types of capacity mechanism being 

7  
8  

For instance between power generators and demand response operators. 
For instance by excluding certain technologies, such as lignite (see SWD, chapter 5.2.2.1, page 64) and in accordance 
with point 220 of the EEAG. 

7 

 
 
                                                 
developed in Europe. The Commission received in total 124 replies. An overview of 
the number of replies per Member State and a breakdown by respondent is provided in 
Annex 1.  

(14) 

Following  the  public  consultation,  the  Commission  received  replies  from  114 
stakeholders  from  19  Member  States  plus  Norway  and  Switzerland.  This  number 
includes replies from 62 associations and 20 public bodies. A breakdown of the replies 
is provided in Annex 1. 

(15)  On 15 June 2016, the Commission also organised a workshop with Member States to 
present the findings of the interim report. A particular focus of the workshop was on 
the  issue  of  cross-border  participation  in  capacity  mechanisms.  In  addition,  bilateral 
meetings  have  been  held  with  several  stakeholders  to  deepen  the  understanding  of 
specific  issues.  Finally,  the  Commission  has  made  use  of  a  wide  array  of  public 
sources of information as well as specialist literature and publications on the topic. 

1.5 

Set-up of the Staff Working Document 

(16) 

It  is  the  aim  of  this  Staff  Working  Document  to  present  the  findings  of  the  sector 
inquiry  and  to  draw  conclusions  regarding  the  current  practice  applied  by  Member 
States  when  contemplating,  adopting  and  operating  a  capacity  mechanism.  These 
findings and conclusions may be interpreted as guidance provided by the Commission 
as to its future assessment of capacity mechanisms under the State aid rules. 

(17)  The present final report follows the same structure as the interim report. It updates the 
information  of  the  interim  report  and  elaborates  on  certain  issues  that  have  received 
particular  attention  in  the  public  consultation  or  recent  case  practice.  Chapter  2 
presents an overview of the state of the electricity market in the EU as a whole and in 
particular in the eleven Member States under scrutiny. It explains why many Member 
States are concerned about the continued capability of their electricity system to meet 
demand  at  all  times  and  are  therefore  using  or  considering  to  introduce  capacity 
mechanisms. It subsequently assesses what drives investments in generation capacity 
and  describes  the  market  and  regulatory  failures  that  impact  investment  decisions  in 
the electricity market. A number of market improvements are discussed as means to 
address  the  identified  failures,  whereby  it  is  recognised  that  residual  failures  may 
persist. 

(18) 

In  subsequent  chapters  the  ability  of  capacity  mechanisms  to  address  these  residual 
market and regulatory failures is analysed. Chapter 3 provides taxonomy of capacity 
mechanisms and categorises the capacity mechanisms that have been encountered in 
the  eleven  Member  States  subject  to  the  sector  inquiry.  Chapter  4  provides  an 
overview of the ways in which Member States assess their generation adequacy and 
the role of reliability standards in that assessment. Chapter 5 presents in a high level of 
detail the preliminary findings of the sector inquiry vis-à-vis the design features of the 

8 

 
 
different capacity mechanisms, organised in three categories: eligibility, the allocation 
process  and  the  capacity  product.  This  chapter  has  been  complemented  by  a 
discussion  on  the  mitigation  of  market  power  within  capacity  mechanisms.  On  the 
basis  of  the  findings  presented  in  the  previous  chapters,  Chapter  6  draws  tentative 
conclusions  regarding  the  suitability  of  each  type  of  capacity  mechanism  to  address 
generation adequacy concerns. 

9 

 
 
 
 
2. 

INCREASED GENERATION ADEQUACY CONCERNS 

(19)  Generation  adequacy  concerns  arise  in  the  context  of  the  transition  of  Europe's 
electricity sector from national centrally-managed systems based on conventional fuel 
to a liberalised and competitive system with substantial shares of variable renewables. 
This  chapter  assesses  the  changes  in  the  sector  so  far  and  presents  expected  future 
developments. The chapter also describes the reasons why the eleven Member States 
of the sector inquiry have implemented or are planning a capacity mechanism. Finally, 
it underlines the importance of ensuring that the introduction of a capacity mechanism 
does  not  replace  market  reforms  that  are  better  suited  to  address  to  core  of  the 
problem.  

2.1 

The electricity sector in transition 

2.1.1

  The liberalisation of electricity markets 

(20)  Liberalisation and the creation of Single Market for energy have been at the heart of 
EU energy policy since the early 1990s. The Third Energy Package9, adopted in 2009, 
has  resulted  in  the  complete  unbundling  of  the  supply  and  generation  arms  of 
vertically integrated undertakings from their transmission activities, thus creating fully 
independent  transmission  system  operators  (TSOs)  and  paving  the  way  for 
competition to occur in the generation and supply segments of the sector.  

(21) 

trade  has 

In the last decade competitive wholesale markets have appeared in a large majority of 
Member  States  and  cross-border 
intensified  significantly.  The 
implementation  of  market  coupling10  has  enabled  an  optimal  use  of  interconnection 
capacities,  ensuring  that  electricity  automatically  flows  from  areas  of  low  prices  to 
areas of high prices, and the most efficient plants run not just nationally but in entire 
regions. Harmonised trading rules  for trading in regions comprising several Member 
States11 have fundamentally changed the business models of generators and suppliers 
alike. They increasingly take into account cross-border flows and hedge their positions 
long  term,  for  instance  by  closing  long  term  contracts  and/or  buying  transmission 
rights, and optimize their positions in the day-ahead and increasingly in even shorter 
term intraday markets.  

9  

10  

11  

Directive  2009/72/EC  concerning  common  rules  for  the  Single  Market  for  electricity,  Directive  2009/73/EC 
concerning  common  rules  for  the  Single  Market  for  natural  gas,  Regulation  (EC)  No  714/2009  on  conditions  for 
access to the network for cross-border exchanges in electricity, Regulation (EC) No 715/2009 on conditions for access 
to  the  natural  gas  transmission  networks  and  Regulation  (EC)  No  713/2009  of  the  European  Parliament  and  of  the 
Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators. 
The  term  market  coupling  refers  to  the  implicit  allocation  of  both  the  electricity  and  the  available  interconnection 
capacity at the same time, instead of separately via explicit auctions.  
See  e.g.  the  organisation  of  trading  with  “capacity  calculation  regions”  of  several  Member  States  (Commission 
Regulation  (EU)  2015/1222  of  24  July  2015  establishing  a  guideline  on  capacity  allocation  and  congestion 
management, OJ L 197, 25.7.2015, p. 24–72). 

10 

 
 
                                                 
(22)  Liberalisation  has  implied  a  transition  from  central  planning  of  investments  in 
generation  and  capacity  towards  decentralised  decision-making.  On  the  one  hand, 
investment  decisions  on  generation  capacity  and  on  transmission  capacity  are  no 
longer  taken  jointly.  On  the  other  hand,  investment  decisions  in  generation  capacity 
are  taken  autonomously  by  private  undertakings  operating  in  electricity  generation. 
This shift, together with the new organisation of the relation between generators and 
TSOs  through  unbundling,  requires  an  adaptation  of  previous  adequacy  planning 
mechanisms,  and  a  robust  framework  for  regulatory  supervision  of  generation 
adequacy, including a clear definition of the roles of the different actors in adequacy 
planning. Otherwise, the uncertainty about when and where investments in generation 
capacity  will  take  place  could  be  uncomfortable  for  TSOs  from  a  technical 
perspective, but also policy makers who bear the ultimate political responsibility for 
secure  electricity  supplies.  These  considerations  are  particularly  relevant  given  that 
Europe's  generation  fleet  is  ageing,  potentially  creating  a  need  for  investments  in 
generation capacity.  

(23) 

Installed generation capacity has substantially increased over the last two decades, as 
a  result  of  investments  by  both  incumbent  generators  and  new  entrants.  These 
investments focused notably on wind and solar technologies, but also on combustible 
fuel technologies, especially gas. 

Figure 1: Evolution of installed generation capacity by technology in the EU28 as a 
whole12 

Source: European Commission based on Eurostat data 

12   Category  "Other  combustible"  is  the  result  of  subtracting  "Gas  turbines"  and  "Combined  cycle"  from  the  category 

"Combustible fuels" in Eurostat database on "Infrastructure Electricity Annual data" [nrg_113a]. 

11 

 
 
 
                                                 
2.1.2

  Decarbonisation policies 

limit  on 

(24)  The  energy  sector  is  a  large  contributor  to  the  EU's  carbon  footprint  but  also 
contributes in a variety of ways to realise emission reductions. Power companies and 
industrial installations in the EU are covered under the EU Emissions Trading System 
(ETS), which puts a price on carbon, ensuring that the costs of fossil fuels reflect their 
carbon intensity. The ETS is a market based system, in which power companies can 
choose  whether  to  buy  allowances  on  the  market  or  to  reduce  emissions.  As  the 
overall 
technologies  for 
the  number  of  allowances  declines  and 
decarbonisation  are  further  developed,  this  provides  a  stronger  incentive  to  reduce 
emissions  at  a  low  cost.  Additionally,  the  political  determination  to  encourage 
renewable  generation  through  support  schemes,  resulting  in  national  renewables 
targets  and  the  Renewable  Energy  Directive13,  has  contributed  to  an  impressive 
growth in the share of renewables in the EU's energy mix. The increasing maturity and 
decreasing  investment  costs  of  these  generation  technologies  (the  'learning  curve'  of 
renewables), as well as the expectations of sustained increasing demand for electricity 
prior  to  the  economic  crisis,  have  further  stimulated  the  development  of  RES.  By 
2013, 26% of the EU's electricity is generated from renewables and about 10% of total 
electricity  is  sourced  from  intermittent  renewable  electricity,  whose  availability 
essentially depends on variable factors outside the control of the plant  operator,  like 
the weather conditions in the case of wind and solar.14  

Figure 2: Evolution of wind and solar generation capacity by Member State 

Source: European Commission based on Eurostat data 

(25) 

In most of the eleven Member States covered by this inquiry the generation mix now 
consists of substantial shares of variable renewable energy sources (RES). Wind and 
solar generation technologies have achieved the largest shares of installed capacity in 

13   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/EC. 

14   European Commission, Renewable energy progress report {SWD(2015) 117 final}. 

12 

 
 
 
                                                 
Denmark  (40%),  Germany  (38%),  Spain  (28%)  and  Portugal  (25%).  The  shares  of 
variable RES are expected to increase further, in particular as some Member States are 
still making progress and increase the share of renewables in their country in order to 
reach their 2020 targets. 

Figure 3: Installed generation capacity by technology (in %) in each of the 11 MS in 
2014 

Source: European Commission based on Eurostat data 

(26)  The  significant  increase  in  renewables  has  important  side-effects  for  security  of 
electricity  supply.  The  relatively  unpredictable  nature  of  certain  variable  renewable 
sources such as wind and solar makes the electricity system more difficult to manage 
for TSOs. Moreover, due to their low marginal costs, RES reduce the running hours of 
conventional  generation.  This  effect  has  been  reinforced  by  further  decarbonisation 
and  environmental  policies,  including  at  European  level,  such  as  the  European-wide 
Emissions Trading System, the Energy Efficiency Directive15, the Large Combustion 
Plant Directive16, and the Industrial Emissions Directive17. 

2.1.3

  Concerns about security of supply 

(27) 

Security  of  supply  is  one  of  the  three  core  objectives  of  EU  energy  policy.  In  the 
electricity sector, security of supply has a short term and a long term dimension. In the 
short term, it is important that the TSO, who is responsible for system security in real 
time, has sufficient instruments at its disposal to ensure balance between demand and 
supply.  In  the  long  run,  the  electricity  system  needs  to  be  fit  to  provide  sufficient 
electricity to meet demand at all times and in all parts of the system.  

15   Directive  2012/27/EU  of  the  European  Parliament  and  of  the  Council  of  25  October  2012  on  energy  efficiency, 

amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC. 

16   Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants. 
17   Directive 2010/75/EU of the European Parliament and the Council on industrial emissions. 

13 

 
 
 
                                                 
(28)  This  section  discusses  the  impact  that  recent  developments  in  European  electricity 
markets,  mainly  driven  by  the  liberalisation  and  decarbonisation  objectives,  but  also 
the economic crisis, are having on the long term adequacy of generation capacity and 
security  of  supply.  It  assesses  the  question  from  three  angles:  how  has  the  relation 
between  demand  and  generation  capacity  developed,  how  have  utilisation  rates  of 
power  plants  evolved,  and  how  has  the  profitability  of  conventional  plants  been 
affected. 

2.1.3.1

 Margins between generation capacity and demand have widened 

(29)  Total  installed  generation  capacity  in  the  EU-28  has  increased  by  more  than  30% 
since  2000,  reaching  a  total  of  more  than  1  TW  in  2013.  This  has  been  a  gradual 
increase,  with  the  steepest  growth  starting  in  the  years  immediately  before  the 
economic crisis and continuing until 2011. The fact that the growth in total installed 
capacity  continued  to  increase  during  the  first  years  of  the  economic  downturn  is 
related  both  to  the  lag  between  investment  decisions  and  new  generation  plants 
entering  operation  and  to  the  continued  support  schemes,  especially  for  renewables. 
While  installed  generation  capacity  has  increased  in  all  the  11  Member  States 
investigated in  this inquiry, the  growth has  not  been  evenly distributed, as  shown in 
Figure 4. 

Figure 4: Evolution of installed generation capacity in each of the 11 MS 

Source: European Commission based on Eurostat data 

(30)  Contrary to the inertia observed in the evolution of installed generation capacity, the 
production  and  demand  of  electricity  was  rapidly  impacted  by  the  start  of  the 
economic  crisis.  Production  grew  steeply  by  about  15%  between  2000  and  2007, 
before  starting  to  decrease  during  the  economic  downturn.  Between  2008  and  2013, 
annual electricity generation in the EU decreased by 5%. 

14 

 
 
 
Figure 5: Evolution of generated electricity in the EU28 as a whole 

Source: Eurostat 

(31)  The  downward  trend  of  demand  for  electricity  has  been  observed  in  most  Member 
States, but with differences across them as well as with some exceptions. In Poland for 
example,  average  demand  for  electricity  continued  to  grow  during  the  entire  period 
2000-2013,  which  is  consistent  with  the  mild  impact  of  the  crisis  on  the  Polish 
economy. In both France and Germany average electricity demand remained broadly 
stable  during  the  years  of  the  economic  crisis.  Average  electricity  demand  dropped 
significantly  in  most  other  Member  States,  including  Belgium,  Croatia,  Denmark, 
Ireland, Italy, Portugal and Spain. 

Figure 6: Evolution of final demand for electricity in each of the 11 Member States  

Source: European Commission based on Eurostat data 

(32) 

Similar trends have been observed for the peak demand, defined as the highest yearly 
demand level, of electricity in the Member States covered in the inquiry.  

15 

 
 
 
 
Figure 7: Evolution of peak demand for electricity in each of the 11 Member States18 

Source: European Commission based on replies to sector inquiry 

(33)  The  constant  increase  in  total  generation  capacity  since  2000  coupled  with  the 
decrease  in  average  demand  since  2008  has  widened  the  margin  between  average 
demand and installed capacity since the beginning of the economic crisis. 

Figure 8: Evolution of average demand and generation capacity for the EU28 as a whole 

Source: Eurostat 

(34)  The margin between average or peak demand and total installed capacity varies across 
the 11 Member States. In 2013, the margin was largest in Denmark, Spain, Italy and 
Portugal.  At  the  opposite  end,  it  was  smallest  in  Belgium,  Croatia,  Poland  and 
Sweden. 

18   This graph is based on figures provided by the Member States in the context of the sector inquiry. The figures provided 

by Germany were not specific enough to allow for inclusion in this graph.  

16 

 
 
 
 
                                                 
Figure 9: Indexed peak demand and generation capacity in each of the 11 Member 
States in 2014 

Source: Eurostat and European Commission based on replies to the sector inquiry 

(35) 

Increasing  gaps  between  peak  demand  and  potential  supplies  may  appear  to 
demonstrate that there is overcapacity in the market. However, that conclusion would 
be too simplistic. Resilient electricity systems typically require a supply buffer above 
predicted  peak  demand  to  protect  themselves  against  unpredicted  potential  increases 
in  peak  demand,  disruptions  to  supply  (e.g.  planned  and  unplanned  maintenance  of 
generation  units),  or  interruptions  in  the  availability  of  transmission  infrastructure. 
More  importantly,  the  aggregation  of  the  maximum  installed  capacity  does  not  take 
into  account  that  each  technology  has  a  different  level  of  availability  and 
intermittency,  which  means  that  different  generation  mixes  may  require  different 
margins between installed generation capacity and peak or average demand. Finally, a 
simple  capacity  margin  often  does  not  include  the  potential  contribution  of  imports 
through interconnectors or the flexibility of the demand-side. 

2.1.3.2

 Capacity utilisation of conventional generation has decreased 

(36)  The contribution of each technology to the effective generation of electricity does not 
match  the  share  of  each  technology  in  the  installed  capacity  mix.  While  in  2013 
nuclear represented 13% of total installed capacity in the EU28, it produced 27% of 
all  the  electricity  generated.  This  illustrates  the  fact  that  nuclear  generation  units 
typically run continuously most of the time during the year.  

(37)  The  opposite  applies  to  hydro,  wind  and  solar:  in  2013  they  represented  20%,  12% 
and 7% of total installed capacity respectively, but contributed just 13%, 7% and 3% 
to  effective  electricity  generation.  This  illustrates  the  variable  nature  of  these 
renewable technologies, which despite their low running costs cannot always generate 
due to their dependency on weather conditions.  

17 

 
 
 
Figure 10: Capacity and generation mix in the EU28 in 2014 

Source: European Commission based on Eurostat data  

(38)  The deviations between the share of installed capacity of each generation technology 
and the share of electricity generated by each technology indicate different  levels of 
capacity utilisation across  technologies.  One possible measure of capacity utilisation 
is the ratio between the average generation per hour and the installed capacity for each 
technology.  Figure  11  shows  this  measure  of  capacity  utilisation  for  the  EU28  by 
generation technology. 

(39)  As  expected,  nuclear  exhibits  the  highest  level  of  capacity  utilisation,  stable  above 
80%  since  2000.  Capacity  utilisation  of  hydro  has  also  remained  broadly  stable 
throughout  the  period,  albeit  at  a  much  lower  30%.  Wind  and  solar  have  gradually 
increased their levels of capacity utilisation over the last years, attaining 23% and 12% 
levels  respectively  in  2013.  Of  particular  interest  is  the  evolution  of  the  capacity 
utilisation  of  combustible  fuels,  which  has  significantly  decreased  since  2005,  from 
50%  to  40%.  Hence,  the  increasing  weight  of  intermittent  wind  and  solar  in  the 
generation  mix  over  the  last  decade  has  been  accompanied  by  a  lower  level  of 
capacity utilisation for combustible fuel technologies, in particular gas. 

Figure 11: Evolution of capacity utilisation ratio by technology in the EU28 as a whole  

Source:European Commission based on Eurostat data 

(40)  The  correlation  between  wind  and  solar  penetration  and  the  drop  in  the  capacity 
utilisation of combustible fuels can be further illustrated by the evidence from cross-

18 

 
 
 
 
country  data.  Those  Member  States  where  wind  and  solar  have  exhibited  a  larger 
increase  in  their  contribution  to  electricity  generation  tend  to  be  also  the  countries 
with the largest drop in the level of capacity utilisation of combustible fuels. Hence, 
over the period 2000-2013 in the EU28, there has been a negative correlation between 
the increase in the share of electricity generated from wind and solar and the drop in 
the  capacity  utilisation  of  combustible  fuels.  A  correlation  however  does  not 
necessarily imply a causal relationship. The decrease in the utilisation of combustible 
fuels  is  likely  to  have  multiple  causes,  including  for  instance  the  decrease  in  the 
demand for electricity, which tends to affect relatively more flexible technologies with 
higher operational costs. 

Figure 12: Relation between renewable generation penetration and capacity utilisation 
of combustible fuels 

Source: European Commission based on Eurostat data 

2.1.3.3

 Profitability levels for conventional generation have been eroded 

(41)  Wholesale electricity prices have shown both significant volatility and common trends 
across  Member  States.  Figure  13  depicts  the  evolution  of  monthly  average  spot 
electricity prices in France and Germany. In both Member States, spot prices describe 
an  upward  trend  in  the  pre-crisis  years  and  until  2010,  while  a  downwards  trend  is 
observed since 2011.  

19 

 
 
 
Figure 13: Evolution of spot electricity prices in France and Germany 

Source: European Commission on the basis of Power Exchanges data 

(42) 

Figure 14 shows similar trends for a price index constructed on the basis of a larger set 
of European spot electricity markets. 

Figure 14: Evolution of Platts' Pan European Price Index 

Source: Platts 

(43)  The  drop  in  electricity  prices  over  the  last  5  years  is  the  result  of  a  variety  of 
developments,  which  includes  the  lower  demand  for  electricity,  the  increasing 
proportion  of  renewable  technologies  with  low  marginal  costs  and  the  increasing 
margin between generation capacity and demand. 

(44)  Lower electricity prices imply lower levels of profitability for generation technologies 
whose costs and capacity utilisation have remained largely stable, for instance nuclear 
generation.  In  the  case  of  coal-  and  gas-fired  plants,  profitability  depends  on 
electricity prices and capacity utilisation, but also on the development of fuel prices. 

20 

 
 
 
 
The clean  spark spread and the clean dark spread19  provide an indication of average 
profit  margins  for  gas-  and  coal-based  generation,  net  of  EU  ETS  carbon  prices. 
Figure  15  shows  the  evolution  of  these  two  indicators  in  Germany  and  the  United 
Kingdom. In both Member States, the clean spark and dark spreads show an erosion of 
profitability  levels  of  gas-based  generation  relative  to  coal-based  generation, 
especially  between  2012  and  2014.  Recent  data  for  2015  seems  to  indicate  that  this 
trend might be reverting to some extent.  

Figure 15: Evolution of clean gas spark and coal dark in Germany and United Kingdom 

Source: Platts global commodity prices, to add: assumption on efficiency of gas fired 

(45)  The  decrease  of  EU  ETS  prices  since  2008,  and  especially  since  2011,  as  shown  in 
Figure  16,  has  reduced  overall  emission-related  costs  for  combustion  technologies. 
The relative impact has been more favourable for coal-based generation than for gas, 
due to the higher carbon emissions of the former.  

19   The  clean  spark  spread  and  the  clean  dark  spread  are  indicators  of  the  relative  profitability  of  gas  and  coal.  The 
Commission  has  used  data  from  Platts  in  Figure  15.  Platts  defines  its  spark  spreads  as  indicative  prices  giving  the 
average difference between the cost of gas and the equivalent price of electricity on any given day. Its dark spreads are 
indicative prices giving the average difference between the cost of coal and the equivalent price of electricity on any 
given day. More information on which UK and German gas, power and coal prices were used is provided here: 
https://www.platts.com/IM.Platts.Content/methodologyreferences/methodologyspecs/european_power_methodology.p
df. 

21 

 
 
 
                                                 
Figure 16: Evolution of EU ETS carbon price 

Source: European Commission, based on ICE data  

(46)  Additional  factors  that  might  have  contributed  to  the  increase  in  the  relative 
profitability of coal-fired power plants vis-à-vis gas-fired power plants in Europe are 
the massive shift to shale gas in the US and the switch from nuclear to gas in Japan,.  

(47)  All  these  factors  have  contributed  to  make  coal-based  generation  less  costly  on 
average  than  gas-based  generation.  Gas-based  generation  of  electricity  increased 
steadily until 2010, but has significantly decreased since 2011. Conversely, coal-based 
generation has increased since 2010, reflecting the change in the relative positions of 
gas and coal in the merit order curve.  

Figure 17: Evolution of gross generation of coal and gas in the EU28 

Source: European Commission based on Eurostat data 

22 

 
 
 
 
(48)  Coal-  and  gas-based  generation  are  the  main  source  of  flexible  generation.  In  case 
renewable sources are not available, gas generation is considered, among fossil fuels, 
to be a particularly suitable back-up for RES, due to its ability to ramp up and down 
relatively quickly, its relative advantage in terms of emissions as compared to coal and 
the  relatively  abundant  supply  of  gas  worldwide.  The  erosion  of  both  the  utilisation 
rates  and  profitability  levels  of  gas-fired  power  plants  impacts  the  business  case  of 
existing units. Although investment decisions are not just based on current prices but 
also  on  long  term  expectations,  this  erosion  of  profitability  also  dis-incentivises 
investments  in  new  plants,  which  in  turn  increases  long  term  generation  adequacy 
concerns. 

2.1.3.4

 Ageing of coal and nuclear plants 

(49)  A  significant  proportion  of  current  installed  generation  capacity  is  approaching  the 
limit of its operational life. Most nuclear plants have been in operation already for 20 
to 30 years, and will be older than 30 years by 2020. In Europe, little investment in 
new nuclear plants is planned and a number of countries are phasing out their nuclear 
fleet.  While  investments  are  being  made  to  extend  the  life  of  a  number  of  nuclear 
plants, notably in France, a significant share of nuclear generation capacity may close 
in the coming decades. 

(50)  Combustible  fuel  plants  are  more  evenly  distributed  across  age  intervals,  the  oldest 
being  mainly  coal  plants  and  the  younger  being  mainly  gas  plants,  especially 
combined cycle gas plants. Coal plants are candidates to be gradually phased out, not 
only due to their age, but also as a consequence of environmental policies. 

(51)  Regarding renewables, most hydro plants are older than 30 years, but their operational 
life  is  not  as  limited  as  for  nuclear  and  coal  plants.  They  are  expected  to  keep 
operating  for  many  decades,  provided  the  necessary  maintenance  investments  are 
made.  Wind  and  solar  generation  units  are  the  youngest  in  the  capacity  generation 
mix, most of them having been operational for less than 20 years. 

23 

 
 
Figure 18: Distribution of age of power plants per type of generation 

Note: "2020 f" refers to forecasts for 2020. 
Source: Platts Power Vision 

2.2 

Incentives for future investment in generation 

(52)  Declining  demand  and  increasing  shares  of  renewables  resulted  in  decreasing 
profitability  of  electricity  generators,  especially  conventional  flexible  technologies. 
The trend to more generation from intermittent technologies constitutes an economic 
challenge for the business model of many established energy companies with a fossil 
fuel-based  generation  fleet20.  While  the  shift  towards  more  renewable  energy 
production  is,  on  the  one  hand,  a  welcome  development  resulting  from  the 
decarbonisation of the generation fleet, its impact on security of supply must be taken 
into consideration and managed. In this context, combined with the general ageing of 
existing power plants, the question of whether investments in generation capacity will 
be  sufficient  to  guarantee  an  adequate  generation  fleet  to  meet  future  demand  has 
gained prominence.  

20   Though some stakeholders have noted that the expansion of renewables could have been planned in a way that allowed 
investors to better anticipate the eventual outcome on the running hours and profitability of conventional power plants. 

24 

 
 
  
 
                                                 
(53)  To the extent that low profitability reflects an excess of installed generation capacity, 
the resulting lower incentives to invest may be a sound economic signal to correct for 
overcapacity.  However,  if  low  profitability  is  the  consequence  of  market  and 
regulatory  failures,  then  incentives  to  invest  may  prove  insufficient  to  maintain 
adequate generation capacity in the medium and long term. It is therefore important to 
assess what drives investments in the European electricity markets of today and how 
that will influence the generation mix of the future.  

(54)  This  section  presents  the  evidence  obtained  from  the  sector  inquiry  on  the 
expectations of public bodies and market participants about future installed generation 
capacity  and  capacity  margins,  and  discusses,  on  the  basis  of  empirical  evidence  as 
well  as  economic  literature  on  the  subject,  the  market  and  regulatory  failures  that 
impact the incentives to invest in generation capacity. 

2.2.1

  Expectations about future development of generation and demand 

(55)  The sector inquiry responses show that total projected installed capacity will increase 
at  a  slower  pace  than  demand  in  six  out  of  the  nine  Member  States  where  data  was 
available.  

Figure 19: Evolution of projected installed capacity and demand by Member State 

Source: European Commission based on replies to sector inquiry 

(56) 

In the Member States where this trend is reversed (Belgium, Ireland and Poland) the 
main  contributor  to  the  increase  in  projected  installed  capacity  is  the  investment  in 
renewable generation capacity.  

25 

 
 
 
Figure 20: Current and projected installed wind and solar generation capacity in GW 

Source: European Commission based on replies to sector inquiry 

(57)  The  responses  also  show  that,  despite  significant  investment  in  gas  generation  in 
recent  years,  expectations  of  future  investments  in  gas  generation  are rather low;  no 
Member  State  except  Poland  expects  material  increases  in  gas-fired  generation 
capacity.21  

Figure 21: Current and projected installed gas-fired generation capacity in GW 

Source: European Commission based on replies to sector inquiry 

(58) 

Several  signals  may  have  contributed  to  this  moderation  in  planned  investments  in 
gas-fired generation capacity. First, the growth in demand is expected to be modest, at 
least below pre-crisis levels. Second, lower coal prices and the fall in the ETS prices 
have  had  a  positive  impact  on  the  profitability  of  coal-fired  power  plants  at  the 
expense of gas-fired competitors. 

21   The Polish Electricity Association explained that this concerned only CHP plants mainly due to a CHP support scheme 

and a business case based on industrial heat sales. 

26 

 
 
 
 
                                                 
(59)  Lower  profitability  for  flexible  conventional  technologies  resulting  from  these 
developments has a negative impact on incentives to continue investing in these types 
of  technologies.  The  increasing  risk  perceived  by  investors  as  a  consequence  of  the 
reduction of operating hours during which these technologies expect to have to recoup 
costs  and  get  appropriate  remuneration  further  contributes  to  erode  incentives  to 
invest. 

(60) 

(61) 

Incentives  to  invest  shape  the  energy  mix  of  the  future  and  therefore  determine  the 
level of reliability that mix will provide. The relation between incentives to invest in 
generation capacity and the desired level of reliability is therefore the core challenge 
from  a  regulatory  perspective.22  In  the  context  of  the  sector  inquiry,  88%  of  public 
bodies that responded to the questionnaire expressed that no reliability problems had 
been observed in their Member States over the last 5 years, but 69% of them expected 
reliability  problems  to  arise in  their Member  States  in  the  future.  This  indicates  that 
there are concerns among public bodies regarding future reliability. 

It  is  therefore  important  to  understand  whether  electricity  markets  provide  sufficient 
incentives to invest whenever new investments into generation become necessary. The 
time dimension is a relevant factor, given the lead times between investment decisions 
and  operability  of  the  new  generation  capacity.  Expectations  about  future  market 
prices  are  therefore  typically  more  determinative  than  current  market  prices  and,  in 
terms of ensuring generation adequacy at all times, an important question is whether 
investments are done timely. The remainder of this chapter explains  what incentives 
electricity  markets  can  be  expected  to  provide  and  why  they  may  be  insufficient  to 
guarantee  adequate  generation  capacity  and  reliability  in  the  future,  in  particular  if 
certain  market  and  regulatory  failures  are  not  addressed  through  further  market 
reform. 

2.2.2

  Market and regulatory failures undermining incentives to invest 

(62)  As  in  any  other  sector,  investment  decisions  crucially  depend  on  the  returns  that 
private investors expect to obtain. In the case of electricity generation, either through 
revenues  from  electricity  trading/sales  or  other  channels  (e.g.  selling  ancillary 
services23, or participating in capacity mechanisms or renewables support schemes). 

22   As Cramton P., Ockenfels A. and Stoft S. (2013) explain it: "the heart of the adequacy problem is resolving the trade-

off between more capacity and more blackouts." 

23   Directive  2009/72/EC  defines  ancillary  service  as:  ‘a  service  necessary  for  the  operation  of  a  transmission  or 
distribution  system.'  Examples  of  such  services  that  TSOs  can  acquire  from  generators  are  electricity  for  the 
compensation of grid losses, regulating power and emergency power. 

27 

 
 
                                                 
(63)  Electricity  markets  where  generators  obtain  revenues  only  from  selling  electricity, 
balancing  power24  and  providing  ancillary  services  have  been  termed  'energy-only 
markets' in the economic literature. In such markets, generators take their decisions to 
invest in maintaining current capacity and installing new capacity on the basis of their 
expectations  of  future  earnings  obtained  exclusively  from  these  revenue  streams. 
Hence,  in  an  energy-only  market,  supply  and  demand  for  electricity  determine  the 
profitability  of  generation  activities  and  the  incentives  to  invest  in  future  generation 
capacity.  

(64)  Current  liberalised  electricity  markets  in  the  EU  are  imperfect  examples  of  energy-
only  markets,  given  that  in  most  Member  States  some  or  all  generators  obtain 
revenues  through  channels  other  than  market  prices,  for  instance  in  the  form  of 
subsidies and payments that affect their incentives to invest in generation capacity. 

(65)  The  economic  literature  has  extensively  discussed  whether  different  models  of 
electricity  wholesale  markets  can  be  expected  to  generate  sufficient  incentives  to 
invest to guarantee adequate generation capacity. When this is not the case, a so-called 
'missing-money' problem arises: the market proves unable to incentivise investment in 
adequate  generation  capacity  because  investors  fear  future  revenues  will  not  cover 
their fixed costs and will not appropriately remunerate their investment.25  

(66)  The missing-money problem is  mainly  related to the potential inability of electricity 
markets to deliver sufficiently high prices during periods of scarcity – as explained in 
the  next  Section  –  although  other  factors  have  been  discussed  in  the  economic 
literature that can also contribute to the lack of incentives to invest, such as the public 
good  features  of  system  reliability  and  the  uncertainty  about  expected  returns  on 
investments in generation capacity.  

2.2.2.1

 Factors undermining price signals in electricity markets 

(67) 

Prices in competitive electricity markets reflect to a large extent the operating costs of 
the generation plants that are activated to serve the demand for electricity. However, 
this is not always the case even in very competitive markets. In principle, wholesale 
prices in perfectly competitive electricity markets equal the marginal cost of the most 

24   To  the  extent  that  balancing  power  markets  foresee  remuneration  based  on  availability  in  addition  to  delivery,  they 
already embed some payment for capacity and thus cannot be considered purely energy-only markets in strict sense. 
However, such payments for availability are designed mainly to provide short-term balancing possibilities, rather than 
long-term generation adequacy. Moreover, these markets represent relatively low traded volumes relative to the overall 
level of capacity. 

25   As  Joskow  P.  L.  (2013)  puts  it,  "the  revenue  adequacy  or  missing  money  problem  arises  when  the  expected  net 
revenues  from  sales  of  energy  and  ancillary  services  at  market  prices  provide  inadequate  incentives  for  merchant 
investors in new generating capacity or equivalent demand-side resources to invest in sufficient new capacity to match 
administrative reliability criteria at the system and individual load serving entity levels." 

28 

 
 
                                                 
expensive generation unit being utilised at every moment in time, provided that there 
is sufficient available supply to meet demand at such price. But this is not always the 
case because sometimes demand for electricity comes close to or may even exceed the 
total  available  generation  capacity,  leading  to  a  situation  of  scarcity.  In  such 
circumstances,  market  prices  typically  rise  above  marginal  cost  to  contract  demand 
and allow the market to clear. These transitory prices above operating costs produce 
margins that remunerate the fixed costs of marginal generating units. An energy-only 
market  relies  to  a  large  extent  on  the  rents  generated  during  periods  of  scarcity  to 
provide sufficient incentives for generators to invest in capacity.26 

(68)  The  theoretical  efficient  functioning  of  this  market  design  depends  on  a  number  of 
assumptions  that  are  rarely  satisfied  in  existing  wholesale  electricity  markets,  in 
particular that the demand can respond to variations of wholesale prices in real time 
and that generators do not enjoy a significant degree of market power.  

(69)  The  demand  for  electricity  is  typically  insufficiently  responsive  to  prices  because 
currently  prevailing  technical  features  of  electricity  delivery  do  not  allow  most 
customers to respond to price variations in real time. As a consequence, there may be 
situations  when  the  wholesale  energy  market  cannot  clear,  because  demand  remains 
above  available  generation  capacity  independently  of  the  price  level.  In  such 
circumstances,  some  kind  of  regulatory  intervention  is  needed  to  bring  supply  and 
demand in balance, e.g. by rationing demand and administratively setting a price. 

(70)  Economic theory indicates, under certain assumptions, that during periods of rationing 
it  is  optimal  to  set  a  price  at  the  level  of  the  value  of  lost  load  (hereafter,  'VOLL'). 
VOLL  is  equal  to  the  marginal  consumer  surplus  associated  with  a  unit  increase  in 
electricity  supplied  to  rationed  consumers.  In  other  words,  it  expresses  the  value 
attached  by  consumers  to  uninterrupted  electricity  supply.  A  regulated  price  at  the 
level of VOLL when the market does not spontaneously clear would in theory provide 
incentives to invest in generation capacity that reflect consumers' average willingness 
to pay for security of supply.27  

26   As  Cervigni  G.  and  Perekhodtsev  D.  (2013)  explain,  "pricing  in  conditions  of  scarcity  is  a  crucial  element  of  the 
wholesale electricity market's design. Since the available generation capacity is far greater than demand in most hours, 
the competitive market-clearing price very rarely departs from the system marginal cost. Therefore the generating units 
with the highest variable costs rely on the extremely high prices prevailing during very few hours of scarcity to cover 
their fixed costs." 

27   As  Cramton  P.,  Ockenfels  A.  and  Stoft  S.  (2013)  explain:  "The  market  responds  to  VOLL  by  building  additional 
capacity up to the point where a MW of capacity costs just as much as it earns from being paid VOLL during blackouts. 
(…) So at this point the cost of capacity equals the value of capacity to consumers, and beyond this point, consumer 
value per MW can only decline as the system becomes more reliable. Hence, the VOLL pricing rule causes the market 
to build the second-best, 'optimal' amount of capacity. This solves the adequacy problem – with help from a regulator." 
A first-best solution can only be obtained by enabling a fully responsive demand-side allowing the market to clear at all 
times  on  the  basis  of  individual consumers'  preferences  however,  and  a  capacity  mechanism  in which  the amount  of 

29 

 
 
                                                 
 
(71) 

In most Member States price caps currently exist which are not based on estimates of 
average  VOLL,  but  often  on  the  technical  bidding  limits  used  by  power  exchanges. 
Although the national authorities in Denmark, France, Ireland, Italy, Poland, Portugal 
and  Sweden  have  all  made  estimates  of  VOLL  in  their  markets,  only  Croatia  and 
Denmark indicated that price caps in their markets were influenced by the estimated 
VOLL.  

(72)  Although  VOLL  has  not  been  calculated  in  some  Member  States,  many  Member 
States that have calculated it report values that are well above day-ahead market price 
caps. Table 1 reports the price caps and estimates of VOLL in each of the 11 Member 
States, as obtained from responses to the sector inquiry. 

Table 1: Maximum price caps in the 11 Member States28 
Wholesale Price Caps and estimates of VOLL (EUR/MWh) 

Country 

Belgium 

Denmark 

Croatia 

France 
Germany 

Ireland 

Italy 

Poland 

Portugal 
Spain 

Sweden 

Day-ahead 

Intraday 

Balancing 

3,000 

3,000 

3,000 

3,000 
3,000 

9,999 

No cap 

No exchange 
trading. No OTC 
cap. 
9,999 
9,999 

1,000 (moving to 
3,000 in future) 

1,000 (moving to 
3,000 in future) 

3,000 

~350 

180 
180 

3,000 

3,000 

No cap 

180 
180 

No cap 

4,500 

5,000 

No cap 

9,999 
No cap 
No balancing 
market. Price cap 
TBC for future 
market design 
3,000 

~350 

No cap 
No cap 

5,000 

Source: European Commission based on replies to sector inquiry 

Estimate of 
VOLL29 
n.a. 
Between 2,933 
and 36,800 

n.a. 

26,000 
n.a. 

11,017.98 

3,000 
Between ~1,250 
and ~2,100 
3,000 
n.a. 
Between ~2,800 
and ~7,600 

(73)  The  cross-country  variation  observed  in  the  VOLL  estimates  reported  show  the 
heterogeneity of electricity demand across countries, but may also reflect differences 
in methodology. In practice it can be a challenge to estimate the VOLL accurately, so 

capacity to subsidise is set based on estimates of average consumer willingness to pay will also deliver a 'second-best' 
outcome. 

28   Note  that  in  some  countries  these  are  technical  price  caps  that  may  constrain  bidding  on  exchanges  but  are  not  an 

absolute regulatory cap on prices and would not prevent OTC exchanges at higher prices.  

29   Note  where  there  are  wide  bands,  this  may  be  because  studies  identified  different  VOLLs  for  different  consumer 
classes, and/or because studies identified different VOLLs depending on the duration and frequency of lost load. 

30 

 
 
 
 
 
 
                                                                                                                                                         
that it can be confidently expected that VOLL-based administrative prices incentivise 
the  optimal level  of  investments  in  generation capacity,  reflecting  the  real consumer 
willingness  to  pay  for  additional  security  of  supply.30  Notwithstanding,  rigorous 
VOLL  estimates  remain  the  best  approximation  to  what  the  optimal  administrative 
price cap would be. 

(74) 

However,  the  potential  exercise  of  market  power  or  the risk  of  market  manipulation 
might also have influenced the relatively low price caps seen in many markets. When 
generators  enjoy  some  degree  of  market  power,  they  may  abuse  it  by  engaging  in 
withholding  capacity  or  strategic  bidding  to  increase  wholesale  electricity  prices  to 
their  benefit.  The  risk  that  generators  implement  such  strategies  is  particularly  high 
when  the  system  approaches  situations  of  scarcity,  because  in  these  circumstances 
virtually  every  generating  unit  becomes  pivotal  and  enjoys  some  degree  of  market 
power.31  The  current  lack  of  demand  response  to  wholesale  price  variation  further 
contributes  to  making  the  exercise  of  market  power  more  likely  and  profitable, 
because  increases  in  prices  do  not  trigger  any  significant  reductions  in  the  final 
demand for electricity.32 

(75)  Regulators and competition authorities may find it difficult to distinguish instances of 
exercise  of  market  power  abuse  and  market  manipulation  from  genuine  scarcity 
conditions.  In  both  cases  the  main  observable  market  outcome  is  higher  wholesale 
prices.  Generators  can  for  instance  disguise  withholding  of  capacity  as  technical 
maintenance or failure. It is not easy either to assess whether generators bidding above 
their running costs are legitimately seeking to cover their fixed costs, or are seeking to 
make windfall profits thanks to the lack of sufficient competition or demand response.  

(76)  However, when asked whether concerns about market power had influenced decisions 
on  price  caps  in  their  markets,  only  the  Polish  national  authorities  and  the  Spanish 
Regulator confirmed. Belgium, Denmark, France, Ireland, Italy, Portugal, the Spanish 
Government and Sweden denied.  

(77)  A  number  of  market-power  mitigation  measures  have  been  applied  in  wholesale 
electricity markets – apart from permanent scrutiny by competition authorities and the 

See Cramton P., Ockenfels A. and Stoft S. (2013). 

30  
31   As  Joskow  P.  L.  (2008)  explains:  "Unfortunately,  the  supply and  demand  conditions which  should  lead  to  high  spot 
market prices in a well-functioning competitive wholesale market (i.e. when there is true competitive 'scarcity') are also 
the conditions when market power problems are likely to be most severe (as capacity constraints are approached in the 
presence  of  inelastic  demand,  suppliers'  unilateral  incentives  and  ability  to  increase  prices  above  competitive  levels, 
perhaps by creating contrived scarcity, increase)." 

32   As Spees K. and Lave L. B. (2007) explain referring to some past experiences in US markets: "A serious problem with 
the  deregulated  market  structure  is  that  the  system  operator  creates  an  auction  market  where  demand  is  completely 
unresponsive  to  price  and  all  successful  generators  are  paid  the  market  price;  this  market  design  offers  an  all  but 
irresistible  temptation  for  generators  to  manipulate  the  market,  sending  prices  soaring,  as  happened  in  California  in 
2000." 

31 

 
 
                                                 
increased monitoring of electricity trading under the REMIT Regulation33 – including 
forced capacity divestitures, long-term contracts, virtual power plants34 and price caps. 
The  latter  two  are  more  likely  to  create  or  contribute  to  a  missing  money  problem 
because they are based on constraining the ability of prices to increase in periods of 
scarcity.35  Especially  price  caps  close  to  the  marginal  operating  cost  of  the  last 
generation  unit  in  the  merit  order  curve  might  help  mitigate  concerns  about 
anticompetitive behaviour, but they are also likely to create or exacerbate the 'missing 
money' problem by curbing scarcity rents earned by generators.  

(78)  Allowing  prices  to  rise  to  VOLL  in  periods  of  scarcity  is  likely  to  entail  very  high 
wholesale prices, albeit during short periods of time. Concerns have been raised that 
such  high  prices  may  be  politically  or  socially  difficult  to  accept  where  there  is  a 
perception  that  relying  exclusively  on  scarcity  pricing  entails  higher  risks  (for 
instance,  spilling  over  to  retail  markets)  than  alternative  measures  based  on 
remunerating capacity through out-of-the market channels.36 However, experience in 
several  countries  shows  that  wholesale  market  participants  may  be  able  to  hedge 
against short-term price peaks, with limited additional costs for end consumers. 

(79) 

In  response  to  the  public  consultation  and  inquiry  questionnaires,  stakeholders  have 
identified other factors that may lead to price caps being set below VOLL. The system 
operator  in  Belgium  and  the  national  authorities  in  Denmark  and  Italy  identified  the 
Commission  Guideline  on  Capacity  Allocation  and  Congestion  Management,  which 
requires  the  establishment  of  'a  proposal  on  harmonised  maximum  and  minimum 
clearing prices to be applied in all bidding zones which participate in single day-ahead 
coupling…[taking]…  into  account  an  estimation  of  the  value  of  lost  load'37,  as  a 
potential  constraint  on  national  authorities'  discretion  regarding  national  price  caps. 
France and Germany also explained that in their markets no regulatory price caps have 
been set and the only caps are set by the exchanges. Some respondents to the sector 
inquiry  noted  that  the  higher  the  potential  market  prices  and  therefore  risk  market 
participants  are  exposed  to,  the  greater  the  requirements  for  collateral  and  the  more 
expensive it will become to operate on the market. 

33   Regulation  (EU)  No  1227/2011  of  the  European  Parliament  and  of  the  Council  of  25  October  2011  on  wholesale 

energy market integrity and transparency. 

34   Under a virtual power plant or VPP scheme the incumbent party is obliged to sell some of his generation capacity to 
third party market participants (e.g. new entrants). The buyer of the VPP contract has the option to consume power of 
his VPP against the agreed virtual production cost, but not the obligation and hence the contract can be seen as a call 
option. VPPs have been imposed by competition authorities in Europe both as a remedy in merger cases and to address 
dominance.  
For a more in-depth discussion of the various market-power mitigation measures see Cervigni G. and Perekhodtsev D. 
(2013). 

35  

36   As Besser J. G., Farr J. G. and Tierney S. F. (2002) claim: "In theory, energy and ancillary service markets alone can 
provide  incentives  for  investment  in  electricity  supplies.  However,  they  can  only  do  this  by  subjecting  consumers to 
price volatility, price levels, supply shortages, and a level of risk to reliability that costumers and policymakers would 
find unacceptable." 
http://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1445614788889&uri=CELEX:32015R1222. 

37  

32 

 
 
                                                 
(80)  While the discussion on the need for price caps and their optimal level is important in 
terms  of  market  design,  price  caps  may  not  be  the  only  factor  effectively  limiting 
market prices. Despite the existence of price caps lower than VOLL in many markets, 
price caps have rarely been reached in recent years in the Member States covered by 
the sector inquiry. Table 2 shows the maximum prices experienced in each of the last 
five years. Over the last five years, price caps were reached only in Denmark, Ireland, 
Italy,  and  Portugal.  In  each  of  Denmark  and  Ireland  caps  were  only  reached  on  a 
single occasion.38 

(81)  Regarding  the  reasons why  price  caps  have  only  rarely  been  reached, most  Member 
States'  national  authorities  that  chose  to  comment  suggested  that  this  reflects  that 
markets  are  currently  well  supplied  and  there  have  not  been  many  occasions  where 
electricity was scarce.  

38  

In  Denmark,  prices  reached  the  then  cap  of  EUR  2000  /  MWh  once,  on  hour  11  of  7  June  2013.  In  Ireland,  prices 
reached the EUR 1000 / MWh cap once in the 0530 balancing period on 26 February 2013. In Italy, the EUR 3000 / 
MWh price cap has been reached more frequently – for 31 intraday trading hours in 2011, once in the day ahead market 
and  for  four  intraday  trading  hours in  2012,  for  two  intraday  trading  hours in  2013,  for  16  intraday trading  hours in 
2014  and  for  eight  intraday  trading  hours  in  2015.  In  Portugal  intraday  price  caps  have  also  been  reached  relatively 
often – for four hours in 2012, nine hours in 2013 and six hours in 2015.  

33 

 
 
                                                 
Table 2: Highest prices experienced in the 11 Member States (EUR/MWh) 

Source: European Commission based on replies to sector inquiry 

(82)  Moreover,  prices  in  every  market  timeframe  (i.e.  intra-day,  day-ahead,  etc.)  are 
interdependent  and  the  incentives  of  market  participants  are  influenced  by  their 

34 

 
 
 
expectations about prices in markets closer to delivery. The rules by which imbalance 
settlements are calculated can for instance affect bids in the day-ahead market: even if 
there is no price cap in the day-ahead market, electricity suppliers will never choose to 
pay more for electricity in the day-ahead market than what they would be charged for 
being out of balance through imbalance settlement. Also, even if the balancing market 
price  is  in  principle  uncapped,  the  activation  of  operating  reserves,  dispatching 
emergency demand response or implementing voltage reductions are sometimes used 
to  balance  supply  and  demand  that  supress  price  signals,  instead  of  implementing 
involuntary curtailments of demand and let the balancing price rise up to VOLL.39 If 
these balancing services are not charged to reflect their full costs (including the cost of 
the unmet demand at VOLL), price signals in all market timeframes will be distorted, 
and  market  participants  will  adapt  their  behaviour  accordingly.  In  all  these  cases, 
balancing rules and interventions may impose an implicit cap on electricity prices. 

(83)  Another important way in which market prices may be artificially capped is through 
an inefficient delineation of bidding zones, as set out in more detail in Section 2.3.1.3. 
Where  supply  and  demand  is  matched  in  a  large  bidding  zone  in  which  there  is 
frequent  internal  congestion,  the  price  formed  by  the  market  does  not  reflect  the 
critical  location  of  supply  relative  to  demand.  TSOs  will  make  costs  to  manage  the 
congestion, mostly by applying redispatch measures, which are generally smeared out 
over all consumers in the zone. The price formed in the part of the bidding zone with 
excess generation will tend to be higher than it would be if low local demand rather 
than bidding zone-wide demand was used to set the price. And the price formed in the 
part of the bidding zone with excess demand will be too low to reflect the local reality. 
This is another way in which regulatory failures can cause missing money and prevent 
the  appropriate  investment  signals.  The  market  distortions  created  can  also  have  a 
significant distorting effect on competition and trade – for example because prices in 
areas of high demand are too low (effectively subsiding consumers in those locations) 
and  because  unscheduled  flows40  constrain  the  commercial  use  of  interconnection, 
preventing  trade  to  and  from  the  zone  and  undermining  incentives  for  further 
investment in interconnection.  

(84) 

Finally, electricity prices may not properly reflect scarcity if generators self-constrain 
their offers to avoid a perceived risk of competition law enforcement. Although there 

See Pfeifenberger J., Spees K. and DeLucia M. (2013). 

39  
40   Deviations  between  scheduled  flows  and  physical  flows  are  defined  as  unscheduled  flows.  Loop  flows  are  generally 
defined as those unscheduled flows that are caused by scheduled flows within a neighbouring bidding zone. ACER has 
undertaken  extensive  research  into  the  occurrence  of  loop  flows and  the  negative  impacts they have  on  cross  border 
flows, trade and social welfare in its Market Monitoring Report 2015:  
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_
2015.pdf.  

35 

 
 
                                                 
 
are  exceptions41,  in  principle  generators  are  free  to  offer  electricity  at  prices  above 
their short run marginal costs. Some respondents to the sector inquiry questionnaires 
and  consultation  noted  that  overarching  antitrust  and  sector  competition  rules 
(REMIT) place limitations on acceptable market behaviour. While this is true, and it is 
important to  ensure that  market power abuse can  be  detected and penalised and  that 
consumers  are  protected  when  competition  cannot  ensure  markets  deliver  fair 
outcomes, these rules should not be seen to prohibit the formation of high electricity 
prices when electricity is scarce.  

(85)  The European Court of Justice defined an excessive/unfair pricing abuse as charging a 
price which “has no reasonable relation to the economic value of the product”.42 The 
Court proposed a two-limb test to determine whether or not this is the case: (1) assess 
“whether  the  difference  between  the  costs  actually  incurred  and  the  price  actually 
charged is excessive” and, if so, (2) assess “whether a price has been imposed which 
is  either  unfair  in  itself  or  when  compared  to  competing  products”.43  Regarding  the 
first limb of the test, it is settled case law that the “costs actually incurred” do not only 
include  variable  costs  but  all  the  production  costs,  including  fixed  costs.44  The 
comparison between prices and costs actually incurred should therefore not be limited 
to short run marginal cost, but should also include fixed production costs.45  

(86) 

Furthermore, the presence of a second limb in the United Brands test signals that it is 
not  sufficient  for  the  antitrust  authorities  to  show  that  the  price  charged  is  high 
compared  to  the  costs  actually  incurred  to  conclude  that  such  price  constitutes  an 
infringement  to  antitrust  rules.  Instead,  the  authorities  also  have  to  demonstrate  that 
this  price  is  unfair  in  itself  or  when  compared  to  competitive  benchmarks.  The 
underlying  idea  is  that  even  dominant  undertakings  may  have  legitimate  reasons  to 
charge  high prices compared  to  their  cost of production, not  having  to  do with  their 
dominant  position.  In  the  words  of  the  United  Brands  judgment,  the  authorities 
therefore  have  to  show  that  “the  dominant  undertaking  has  made  use  of  the 
opportunities  arising  out  of  its  dominant  position  in  such  a  way  as  to  reap  trading 
benefits  which  it  would  not  have  reaped  if  there  had  been  normal  and  sufficiently 

41  

In  Ireland  a  'Bidding  Code  of  Practice'  states  that  generators  must  sell  electricity  to  the  pool  at  the  marginal  cost  of 
producing each unit of electricity, as well as a licence condition in all generation licences requiring short run marginal 
cost bidding. In Italy generators deemed to have a pivotal locational position can be termed 'must-run' units and face 
specific  bidding  restrictions,  and  in  2010  ENEL  made  commitments  in  the  context  of  an  antitrust  case  (case A4233, 
ENEL – Dinamiche formazioni prezzi mercato Energia elettrica in Sicilia) to limit offers from its plants in Sicily until 
new interconnection was constructed. The Croatian regulator and the Portuguese national authorities indicated that in 
principle generators were not free in their markets to bid above their short run marginal costs but did not refer to any 
specific rules stating this. Ireland is abandoning the current blanket restrictions as part of its move to the new I-SEM 
market design. 

42   Case 27/76, United Brands v Commission, ECLI:EU:C:1978:22, para 250.  
43   Case 27/76, United Brands v Commission, ECLI:EU:C:1978:22, para 252.  
44   Case 27/76, United Brands v Commission, ECLI:EU:C:1978:22, para 251 and 254.  
45   This  is  also  evidenced  by  the  price-cost  comparison  made  by  the  European  Commission  in  its  Port  of  Hesingborg 

decision (see Case COMP/A.36.568/D3 – Scandlines Sverige AB v Port of Helsingborg). 

36 

 
 
                                                 
effective  competition.”46  This  might  be  done  either  by  looking  at  competitive 
benchmarks or directly by estimating the economic value of the product.47  

(87) 

Finally, it is also settled case law of the European Court of Justice that "a dominant 
undertaking  [should]  set  its  prices  at  a  level  covering  the  great  bulk  of  the  costs 
attributable to the supply of the goods or services in question"48. It can therefore also 
be  derived  from  case-law  of  the  European  courts  on  predatory  pricing  abuses  that 
dominant electricity generators can legitimately seek to recover not only their variable 
costs but also their fixed investment costs. These fixed costs would in principle49 not 
be recouped by a peaking plant at the end of the merit order curve bidding its short run 
marginal cost.  

2.2.2.2

 Uncertainty on returns increases risk premiums required by investors 

(88)  Generators'  expectations  about  future  returns  on  their  investments  in  generation 
capacity are affected not only by the expected level of electricity prices, but also by 
several  other  sources  of  uncertainty,  such  as  increasing  price  volatility,  recurrent 
regulatory reforms and the uncoordinated decisions of competitors. 

(89)  The  increasing  weight  of  intermittent  renewable  technologies  makes  prices  more 
volatile and shortens the periods of operation during which conventional technologies 
are able to recoup their fixed costs.50 In such circumstances, even slight variations in 
the  level,  frequency  and  duration  of  scarcity  prices  have  a  significant  impact  on  the 
expected returns on investments, increasing the risk associated to investing in flexible 
conventional generation technologies. 

(90) 

Since the onset of the liberalisation of electricity markets, regulatory frameworks have 
gradually evolved over time, and are expected to continue to change to respond to the 
political objectives of decarbonisation, affordability and security of supply. Given the 
relatively  long  time  periods  over  which  investments  in  generation  capacity  are 
typically  expected  to  be  recouped,  the  lack  of  a  stable  regulatory  framework  adds 
uncertainty regarding the expected returns on investments in capacity. 

46   Case 27/76, United Brands v Commission, ECLI:EU:C:1978:22, para 249. 
47  

See  Case  COMP/A.36.568/D3  –  Scandlines  Sverige  AB  v  Port  of  Helsingborg  for  examples  of  relevant  elements  to 
consider when determining the economic value of a service/product. 

48   Case C-209/10, Post Danmark AS v Konkurrencerådet, ECLI:EU:C:2012:172, para 38. 
49   Unless demand response is setting higher prices in the market that this plant can capture, or market rules enable prices 
at  times  of  scarcity  to  be  set  based  on  the  value  to  consumers  of  secure  supplies  rather  than  the  direct  costs  of 
generation. 

50   Cramton P. and Ockenfels A. (2012) note that "all these effects imply that the 'missing money' problem is becoming 
more severe as the renewables' share grows." In the same vein, Joskow P. L. (2013) considers that "the expansion of 
subsidized intermittent generation and other subsidized generating investments have exacerbated and complicated the 
problem." 

37 

 
 
                                                 
(91) 

Investment decisions in the electricity sector are typically taken long before returns on 
investment  are  effectively  earned,  due  to  the  time  needed  to  construct  new  power 
plants.  At  the  same  time,  the  decentralised  nature  of  investment  decision-making 
means that each generator has limited information about the generation capacity that 
competitors will made available in the coming years. This constitutes an incentive to 
delay  investments  until  there  is  sufficient  reassurance  that  additional  generation 
capacity  is  actually  demanded  in  the  market.51  This  may  be  less  problematic  where 
generation  with  shorter  planning  and  construction  times  is  sufficient  to  ensure 
adequacy (for instance, small and highly flexible gas plants in certain areas), but may 
be more problematic where larger power plants with longer lead times of 10-15 years 
are  required.  The  result  is  what  has  been  referred  to  as  boom-bust  cycles:  alternate 
periods  of  shortages  and  overcapacity  resulting  from  lack  of  coordination  in  the 
investment decisions of competing generators.52 

(92) 

Investors  factor  in  all  these  sources  of  uncertainty  when  making  their  investment 
decisions. Different authors give different weight to each of these factors,53 but they 
all  contribute  to  increase  risk  for  investors.54  If  investors  demand  larger  risk 
premiums,  energy-only  markets  may  not  be  able  to  generate  sufficient  incentives  to 
invest even with high scarcity prices.  

2.2.2.3

 Public good features of reliability lead to insufficient investment signals 

(93)  The reliability of electricity systems has certain features of a public good. On the one 
hand,  investments  in  capacity  to  increase  the  system's  overall  reliability  to  meet  the 
preferences  of  the  most  demanding  consumers  also  reduce  everyone  else's  risk  of 
supply  interruption  at  no  extra  cost  (in  economic  terms,  this  is  the  feature  of  'no 
rivalry').  On  the  other  hand,  it  is  currently  not  possible  for  most  individual  final 
consumers to be selectively disconnected by the system operator on the basis of their 

51   According to De Vries L. J. (2007), there "are reasons for generating companies to delay investments until the need for 
generation capacity becomes reasonably certain. (…) Depending on the growth rate of demand, investment in reaction 
to price rises may not arrive soon enough to prevent a significant period of shortages." 

52   Cramton P. and Ockenfels A. (2012) formulate this in the following terms: "In a pure-market design, the decisions to 
build  new  capacity  are  made  independently.  This  induces  strategic  uncertainty:  because  one's  investment  in  new 
capacity tends to be more profitable if others invest less, there are incentives to not or to misinform about one's own 
intentions.  This  seems  partly  reflected  by  the  observation  that  there  is  typically  a  significant  gap  between  the 
announced plans to build new plants and actually executed plans. (…) The optimal strategy implies a random element 
and so the outcome is likely to be inefficient." 
Joskow P. L. (2008) for instance, notes that "large investments in production facilities whose output exhibits significant 
price volatility occur all the time (e.g. oil and natural gas)", but acknowledges the relevance of regulatory uncertainty 
"as  policymakers  have  not  been  shy  about  ex-post  adjustments  in  electricity  market  designs  and  residual  regulatory 
mechanisms, sometimes by a desire to hold up existing generators opportunistically." 

53  

54   As  De  Vries L.  J.  (2007)  explains,  "for  generating companies,  investing  in  excess  of  the  socially  optimal  volume  of 
generating  capacity  means  that  competitive  prices  will  be  too  low  to  recover  their  investment,  while  a  volume  of 
generating capacity that is below the social optimum leads to significantly higher average prices, which offset the lost 
turnover at least partly." 

38 

 
 
                                                 
individual VOLL (this is the feature of 'non excludability'). These two features are the 
ones that characterise a public good from an economic perspective.  

(94)  This means that in events of scarcity each consumer's likelihood of being disconnected 
is independent of his VOLL, making him unwilling to pay for reliability as much as he 
would  otherwise  be  willing  to.  Economic  theory  thus  suggests  that  in  such 
circumstances  a  decentralised  competitive  market  is  likely  to  provide  suboptimal 
incentives  for  generators  to  invest  in  generation  capacity,  which  would  therefore 
ultimately deliver suboptimal levels of system reliability compared to what consumers 
would have been willing to pay for if they were able to be individually disconnected 
on the basis of their individual VOLL.55  

2.2.3

  Conclusions on the lack of optimal incentives to invest 

(95)  European electricity markets suffer from a number of market and regulatory failures 
undermining investment incentives. Demand for electricity is largely inelastic due to 
technical  factors  and  regulatory  barriers,  which  implies  lack  of  responsiveness  of 
demand to price variation and leads to inefficient price signals. System operators use a 
variety of tools to force the market to clear in ways that supress market price signals. 
Price  caps  are  often  set  below  VOLL.  Uncertainty  about  expected  future  returns  on 
investment in generation capacity contributes to undermine incentives to invest.  

(96)  Electricity markets in the eleven Member States share most of these characteristics. It 
is therefore understandable that authorities and stakeholders pose the question whether 
the current design, rules and structure of electricity markets may lead to problems of 
generation  adequacy  in  the  future,  even  though  there  may  not  exist  such  a  problem 
today. Answering this question requires an in-depth assessment of the current situation 
of electricity markets, as well as of the expected evolution of both the demand and the 
supply sides in the coming years.  

2.3  What is being done to alleviate imperfections of EU electricity markets? 

(97)  Against the backdrop of reduced investment incentives and increased concerns about 
reliability levels in the future, Member States can on the one hand attempt to alleviate 
imperfections  of  the  current  markets  and  on  the  other  consider  intervening  in  the 
market by providing additional incentives to invest via separate payments that directly 
remunerate capacity. This section assesses the improvements that have been proposed 
and are being carried out on a national and European level to address the market and 
regulatory failures in today's electricity markets and assesses to which extent residual 
generation  adequacy  problems  may  exist  that  can  be  addressed  by  capacity 
mechanisms.  

55  

See Abbot M. (2001). 

39 

 
 
                                                 
2.3.1

  Improving the functioning of the electricity market 

(98)  Both at national and European levels, efforts are underway to implement better market 
designs  and  regulation  aimed  at  improving  market  functioning.  There  is  general 
consensus  that  there  exists  room  for  improvement  of  the  efficiency  of  electricity 
markets,  most  notably  by  enabling  demand  response,  broadening  supply-side 
participation  and  improving  the  efficiency  of  market  outcomes,  especially  during 
scarcity events.  

(99) 

2.3.1.1

 Setting appropriate price caps and enabling the formation of scarcity prices 

In a well-functioning market, prices that reflect VOLL when there is a risk of unmet 
demand  can  potentially  provide  reliable  signals  for  investment  in  the  overall  mix  of 
capacity  with  the  right  flexibility  and  reliability  characteristics  needed  to  meet 
demand.  Even if a capacity mechanism is introduced, appropriate electricity scarcity 
price  signals  will  continue  to  be  important56.  As  discussed  in  the  previous  section, 
allowing extremely high price peaks may present policy makers with other regulatory 
challenges, for instance because of the potential for abuse of market power. But most 
Member  States  did  not  agree  that  concerns  about  market  power  had  influenced  the 
choice  of  price  caps  in  their  markets,  and  the  only  reason  given  for  not  increasing 
price caps was the potential for increased exchange collateral requirements increasing 
overall system costs. Further work to quantify these costs and compare them against 
the  expected  efficiency  benefits  that  sharper  prices  should  bring  would  be  useful  to 
inform the future decisions on price caps required in the context of CACM.  

Balancing markets 

(100)  As  already  explained  in  the  previous  sections,  the  maximum  price  in  any  forward 
market is constrained by the maximum prices charged in the balancing market, which 
functions  as  an  implicit  price  cap  for  electricity  prices  in  forward  markets.  Some 
Member  States  already  have  no  price  caps  in  the  balancing  market,  yet  have  not 
experienced  prices  reflecting  VOLL  even  when  there  has  been  scarcity.  This  can  be 
the case when the balancing price, while not being subject to a cap, does not reflect 
the full cost of the services used  to balance the market or  the full  cost of the unmet 
consumer  demand  (represented  by  VOLL).  Member  States  should  therefore  ensure 
that balancing market rules, even in the absence of an explicit price cap, do reflect the 
full  costs  of  balancing  and  do  not  implicitly  constrain  electricity  prices  in  forward 
markets.  

56  

In all European markets it is electricity prices that determine how interconnection between bidding zones is used and 
help  ensure  that  imports  are  available  to  bidding  zones  experiencing  scarcity,  and  in  many  capacity  mechanisms 
designs – particularly those with a reliability option capacity product (see section 5.4) – the electricity price provides 
the signal for short term delivery of electricity and for investments in flexibility. 

40 

 
 
                                                 
Administrative scarcity pricing 

(101)  Administrative  scarcity  pricing  consists  in  the  introduction  of  rules  to  ensure  that 
electricity  prices  are  automatically  augmented  as  the  probability  of  unmet  demand 
increases,  increasingly  reflecting  the  VOLL.  This  means  that  prices  are  not  solely 
determined  by  the  bids  of  generators  when  scarcity  is  anticipated57,  but  include  an 
administrative  component.  As  the  loss  of  load  probability  increases,  for  example  as 
the system operator deploys available reserve capacity to meet demand, a price adder 
is applied automatically to the market price. 

(102)  The  best  known  example  of  this  approach  is  probably  ERCOT  in  Texas,  but  the 
approach  is  also  used  or  envisaged  in  some  European  markets.  In  May  2014  the 
British regulator concluded its review of imbalance settlement arrangements in the GB 
market  and  alongside  other  reforms  designed  to  make  imbalance  prices  more 
reflective  of  supply  and  demand  introduced  a  'reserve  scarcity  pricing  function'  that 
functions in a similar way to the Texan arrangements but in the balancing timeframe58. 
Ireland is planning a similar change to its market design, where the balancing market 
will  include  an  'administrative  scarcity  price'59,  the  Belgian  regulator  has  been 
exploring the possibility of taking a similar approach in Belgium60, and the approach 
was  recommended  by  the  International  Energy  Agency  in  its  2016  'Repowering 
Markets' report61.  

(103)  Administrative  scarcity  pricing  moves  away  from  a  pure  market  approach  to 
electricity  price  formation.  Like  in  a  capacity  mechanism,  it  is  a  regulatory 
intervention  designed  to  increase  security  of  supply  and  reward  the  reliability  of 
capacity and may involve State aid. The regulatory task of establishing an appropriate 
demand  curve  for  identifying  scarcity  prices  according  to  different  loss  of  load 
probabilities  is  very  similar  to  the  process  of  setting  the  demand  for  capacity  in  a 
volume-based capacity mechanism. However, administrative scarcity pricing does not 
create a separate revenue stream and price for capacity separate to the electricity price, 
and avoids the complications this causes for cross border electricity trading.  

Hedging price risks 

(104)  Measures designed to allow price spikes to occur, while managing any perceived risk 
associated with potentially very high prices, have been proposed and may be brought 

57   This may reduce risks of market power abuse, but under administrative scarcity pricing the possibility of strategic 

capacity withholding remains for portfolio generators.  

58   Ofgem,  2014:  https://www.ofgem.gov.uk/publications-and-updates/electricity-balancing-significant-code-review-final-

59  

policy-decision. 
I-SEM  Committee, 
103%20CRM%20Decision%201_0.pdf.  

2015: 

https://www.semcommittee.com/sites/semcommittee.com/files/media-files/SEM-15-

60   CREG, 2016: http://www.creg.info/pdf/Divers/Z1532FR.pdf. 
61  

IEA, 2016: http://www.iea.org/publications/freepublications/publication/REPOWERINGMARKETS.pdf.  

41 

 
 
                                                 
forward  by  market  participants  without  the  need  for  additional  intervention  by 
national  authorities.  For  instance,  the  introduction  of  hedging  products  which 
suppliers  can  buy  to  protect  themselves  against  peaks.  Options  are  widely  traded  in 
Australia – where price spikes are allowed – and are being introduced in Germany by 
EEX.62  

Increasing confidence in market outcomes 

(105)  Competition rules to prevent the abuse of market power are not intended to prohibit 
high electricity prices resulting from the competitive interaction of supply and demand 
when  electricity  is  scarce.  Effective  data  availability  and  market  monitoring  will 
increasingly be required to ensure confidence in market outcomes and the reliability of 
high  prices  as  a  signal of  market  fundamentals.  This  will  increase  the confidence  of 
market  participants,  regulators  and  governments  and  help  ensure  markets  are  left  to 
function  without  unnecessary  intervention,  The  continued  development  of  demand 
response and the opening up of markets across borders are also essential contributors, 
since they make the abuse of market power less likely and help ensure market prices 
genuinely  reflect  the  competitive  equilibrium  of  supply  and  demand,  and  eventually 
scarcity. 

2.3.1.2

 More efficient, market-based balancing and ancillary services 

(106)  The increase of intermittent renewables has created more uncertainty in forward and 
day-ahead trading and more volume volatility during the day, with system frequency 
risking falling and rising more quickly and drastically following a system disturbance. 
It  has  therefore  become  more  important  to  improve  short-term  markets  to  enable 
balance-responsible parties to balance their portfolios on the shorter term intraday and 
balancing  markets,  but  also  foster  the  development  of  ancillary  services  that  can 
respond in ever shorter timeframes to system disturbances.  

(107)  To  support  Member  States  in  their  effort  to  improve  their  balancing  and  ancillary 
services, the Commission is preparing legislation to this end, in particular with a view 
to fostering effective competition, non-discrimination, transparency and efficiency in 
balancing markets. The proposal will include no-regret measures such as moving gate 
closure  time63  closer  to  real  time  (the  closer  to  real  time,  the  more  accurate  the 
forecasts  of  potential  generators  are  on  what  they  will  be  able  to  generate  and  the 
forecasts  of  demand  response  operators  on  when  they  will  be  able  to  switch-off), 

62  

'An electricity market for Germany’s energy transition', White Paper by the Federal Ministry for Economic Affairs and 
Energy, July 2015. Available at:   
http://www.bmwi.de/English/Redaktion/Pdf/weissbuch-
englisch,property=pdf,bereich=bmwi2012,sprache=en,rwb=true.pdf  
See also: https://www.eex.com/en/about/newsroom/news-detail/eex--successful-start-of-trading-in-cap-futures/21902 

63   The Gate Closure Time is the time at which a market closes and trading is no longer allowed.  

42 

 
 
                                                 
standardising  and  limiting  the  products  to  be  traded  (e.g.  in  terms  of  preparation 
period,  ramp-up  time,  full  activation  time,  minimum  quantities,  deactivation  time 
etc.),  reviewing  the  products  to  ensure  they  are  suitable  both  for  generators  and 
demand  response  operators,  and  opening  up  national  balancing  markets  to  cross-
border capacities. 

(108)  The Commission moreover emphasises the importance of the correct remuneration of 
ancillary  services,  as  already  explained  in  section  2.3.1.1  concerning  balancing 
markets.  The  Commission’s  legislative  proposal  will  therefore  also  define  minimum 
rules  for  the  procurement  of  balancing  services.  As  a  first  step  towards  more 
generalised  market-based  procurement  of  all  ancillary  services,  the  proposal  will 
prescribe such competitive procurement of certain frequency ancillary services. 

2.3.1.3

 More efficient bidding zones reflecting transmission constraints 

(109)  Another  element  of  market  design  that  is  crucial  for  ensuring  efficient  locational 
signals for investment in generation and transmission, and the location of demand, is a 
more  efficient  definition  of  bidding  zones.  The  European  market  is  divided  into 
bidding zones within which market participants can trade electricity without having to 
acquire the rights to use transmission capacity. As such, the price formed in each zone 
reflects the overall demand/supply balance in the zone.  

(110)  Ideally, for electricity prices to appropriately signal local scarcity the market area or 
bidding zone needs to reflect the technical limits of the transmission system. The price 
in  a  very  large  zone  may  not  indicate  with  sufficient  precision  where  additional 
generation capacity is most needed and transmission constraints may cause inefficient 
plants to run instead of more efficient ones. As described in Section 2.2.2.1, this can 
cause  significant  distortions  to  competition  and  trade.  In  such  situations,  TSOs  are 
forced  to  revert  to  congestion  management,  often  in  the  form  of  re-dispatching 
measures64,  in  order  to  ensure  system  balance  and  minimize  loop  flows,  leading  to 
significant costs for consumers and further market distortions.  

(111)  Zones defined based on transmission constraints can allow zonal electricity prices to 
provide  more  accurate  signals  for  the  efficient  location  of  generation  capacity  and 
electricity  demand,  and  the  market-based  scheduling  of  generation  (i.e.  avoiding  the 
need  for re-dispatching). Of the Member  States assessed in the context of the sector 
inquiry,  Denmark,  Italy  and  Sweden  have  divided  their  electricity  market  in  two  or 
more bidding zones. 

64   A  TSO  that  applies  re-dispatching  requests  or  instructs  a  power  plant  to  adjust  their  power  generation  in  order  to 

address congestions and maintain system balance. 

43 

 
 
                                                 
(112)  A  document  published  by  ACER  in  201465  as  a  result  of  a  joint  initiative  between 
ACER and ENTSO-E provides a comprehensive and balanced view of the impact of 
the current bidding zone configuration on the electricity markets. In particular, it looks 
at the following factors: the efficient use of infrastructure, liquidity, hedging, market 
power and investment incentives.  

(113)  The  ACER  report  identifies  clear  positive  effects  on  effective  competition  and 
efficient  price  formation  of  a  bidding  zone  delineation  that  reflects  transmission 
constraints,  but  also  points  that  these  benefits  are  currently  not  reaped  due  to  the 
challenges of identifying clearly constrained lines to define bidding zone borders and 
also to the potential costs of network development. This difficulty is reflected by the 
limited  progress  that  is  being  made  in  the  ongoing  process  for  the  review  of  the 
current  bidding  zone  configuration  in  Europe,  as  prescribed  in  the  CACM  Network 
Code. The Market Design Initiative includes measures to improve the delineation of 
bidding zones. 

(114)  Replies  to  the  sector  inquiry  provided  mixed  views  on  the  current  ability  of  the 
electricity markets to generate the right locational signals for investment in generation 
capacity  in  the  national  territories  covered  by  the  present  sector  inquiry.  Member 
States  that  are  already  split  in  different  bidding  zones  are  generally  more  positive 
about  the  benefits  of  smaller  bidding  zones,  though  some  of  the  respondents  from 
these  countries  still  felt  there  was  room  for  improvement  as  even  where  there  are 
multiple  bidding  zones,  these  too  often  reflect  national  borders  rather  than 
transmission limits. 

2.3.1.4

 Further integration of demand response in the electricity market 

(115)  On the demand side, increased demand responsiveness can have important impacts for 
generation  adequacy  because  it  has  the  potential  to  flatten  demand  peaks  and  thus 
reduce  the  need  for  additional  generation  capacity  to  ensure  adequacy.  Its  role  will 
further increase with the shift towards generation from variable renewables, as coping 
with shorter time generation peaks and gaps will be more in the focus of the balancing 
concerns  in  many  Member  States.  Demand  response  can  be  realised  both  for 
household  and  small  industrial/commercial  consumers  –  where  smart  meters  are 
progressively  being  deployed66  and  aggregators67  are  facilitating  participation  in 
electricity markets – and for larger industrial consumers.  

65   Report on the influence of existing bidding zones on electricity markets (2014). 
66  

For instance, in 17 Member States the wide-scale deployment of smart metering devices is underway or planned and 
data  from  Member  States  show  that  72%  of  European  consumers  are  expected  to  have  a  smart  electricity  meter  by 
2020. Moreover, retail consumers can increasingly choose more flexible tariffs based on real-time prices. For instance, 
in  Finland  and  Sweden  retail  consumers  increasingly  opt  for  dynamically  priced  electricity  contracts  saving  15%  to 

44 

 
 
                                                 
 
(116)  Experience  has  shown  that  the  potential  to  integrate  significant  volumes  of  demand 
response on short notice is highest for industrial customers.  Industrial consumers are 
being  increasingly  incentivized  to  reduce  load  in  times  of  scarcity  by  making  them 
sensitive to wholesale prices, either directly responding to the real-time market signals 
or  through  commercial  offerings  from  their  suppliers.  Smart  grids  and  meters  help 
mitigating the problems related to the public good character of reliability as they allow 
individual  consumers  to  manage  their  consumption  on  the  basis  of  price  signals. 
Moreover,  a  manageable  demand  side  provides  an  additional  tool  to  TSOs  in 
balancing the system, by providing balancing or ancillary  services to the TSO or  by 
participating in a targeted scheme for interruptible loads.  

(117)  However, at present serious regulatory obstacles persist in a great majority of Member 
States, ranging from explicit prohibitions on becoming active on the wholesale market 
to the continuation of disincentivising grid tariff structures.68 Moreover, national legal 
frameworks  differ  considerably  across  the  EU,  for  instance  on  aggregation  or  the 
determination of baseline capacities. For these reasons, the Commission is proposing 
to  harmonise  some  basic  elements  related  to  the  treatment  of  the  participation  of 
demand response in the various time frames.   

2.3.1.5

 Further integration of renewable generation in the electricity market 

(118)  On  the  supply  side,  participation  can  be  broadened  to  ensure  that  all  potential 
contributors  are  able  to  deliver  what  they  physically  can  to  meet  peak  demand. 
Renewables for example have historically been shielded from price fluctuations in the 
market to help support the development of nascent technologies. However, now that 
RES generation is maturing and comprises a significant proportion of overall installed 
capacity,  there  is  an  increasing  opportunity  for  a  more  active  participation  in  the 
market. There is still a substantial number of Member States in which RES producers 
are  either  not  able  or  have  no  incentive  to  participate  in  the  wholesale  market  and 
react  to  price  signals,  for  instance  because  they bear  no responsibility  to  ensure that 
their actual generation output meets projections.  

(119)  The contribution of wind and solar will increase as necessary grid reinforcements are 
implemented  and  the  right  incentives  are  put  on  renewables  operators  through  their 

30%  on  their  electricity  bills.  Source:  Communication  from  the  Commission,  'Delivering  a  New  Deal  for  Energy 
Consumers' of 15 July 2015, COM(2015)339 final, page 3 – 5. 

67   Demand response aggregators typically enter into contracts with small consumers and sell the combined load reduction 

that these consumers can achieve together to the system operators, sharing the revenues with the participants. 

68   European Commission, JRC 'Demand Response status in EU Member States 2016', 

http://publications.jrc.ec.europa.eu/repository/bitstream/JRC101191/ldna27998enn.pdf.  

45 

 
 
                                                                                                                                                         
inclusion  in  balancing  markets.  Wind  capacity  is  increasingly  able  to  offer  ancillary 
services and to adjust its output in the balancing timeframe69.  

Table 2: Balancing Responsibility for RES in the eleven Member States 

Balancing Responsibility for RES 

Country 

Balancing responsibility 
Yes 
Yes 
No 
No 
FIP Only70 
Partly 
Partly 
Yes 
Yes 
Yes 
Yes 

Belgium 
Denmark 
Croatia 
France 
Germany 
Ireland 
Italy 
Poland 
Portugal 
Spain 
Sweden 
Source: European Commission, adapted from Commission Communication 'Delivering the internal 
electricity market and making the most of public intervention', 5 November 2013, C(2013)7243  

2.3.1.6

 Further cross-border integration of the electricity market 

(120)  Another  example  is  foreign  capacity.  The  participation  of  foreign  capacity  is 
optimized in the day-ahead market where market coupling has been implemented, but 
regulatory  arrangements  typically  do  not  allow  the  use  of  interconnection  closer  to 
real  time  when  scarcity  would  be  expected  to  emerge.71  The  use  of  cross  border 
resources in the intraday and balancing will help to ensure competition in all market 
timeframes, and Member States and TSOs should ensure that investments are made to 
relieve transmission constraints between bidding zones and enable the full benefits of 
the Single Market to be realised. 

(121)  Under market coupling rules, the only signal that is taken into account for determining 
cross border electricity flows is the electricity price, so it is important to ensure that 
electricity prices can rise to reflect consumers' willingness to pay. It is also critical that 
market  coupling  systems  ensure  that  different  price  caps  can  be  set  in  different 

69  

See  for  example  Fraunhofer  IWES,  DTU  Wind  Energy,  EWEA,  April  2013,  Capabilities  and  costs  for  ancillary 
services  provision  by  wind  power  plants.  Available  at:  http://www.reservices-project.eu/wp-content/uploads/D3-
RESERVICESAncillaryServicesfromWind_v1.3_final.pdf  

70   Balancing  responsibility  is  only  applied  to  those  renewable  generators  that  receive  a  feed-in  premium  and  thus 

participate in the market (currently some 80% of RES). 

71   However,  power  exchanges  have  initiated  pilot  projects  aimed  at  the  development  of  cross-border  intraday  trading 
based on implicit continuous trading, in accordance with the Commission's Target Model for Intraday and Commission 
Regulation  (EU)  2015/1222  of  24  July  2015  establishing  a  Guideline  on  Capacity  Allocation  and  Congestion 
Management. 

46 

 
 
 
                                                 
bidding zones if appropriate to reflect the different willingness to pay of consumers in 
different zones.  

2.3.1.7

 More stable, harmonised regulatory environment 

(122)  Finally,  though  reforms  are  necessary  to  improve  market  functioning,  the  extent  to 
which  an  electricity  market  delivers  signals  for  sufficient  investment  depends  on 
investors' view of long  term regulatory  stability. Regulatory stability  helps  create an 
environment in which longer term and forward trading can happen within the market, 
which can provide an important basis for supporting new projects. Alongside a stable 
regulatory framework for electricity prices, the longer term impact of carbon prices is 
an important consideration for investors, and a reformed European carbon market with 
a  functioning  Market  Stability  Reserve  that  addresses  the  surplus  of  emission 
allowances on the market will help to deliver this.  

2.3.2

  Addressing residual market failures with a capacity mechanism 

(123)  The  reforms  mentioned  in  the  previous  section  could  significantly  improve  the 
efficiency  of  electricity  markets.  Some  analysts  indicate  that  there  is  practical 
evidence that an energy only market design can realise sufficient investment without 
the need for mechanisms that make separate capacity revenues available to generators 
and/or demand response.72 However, other authors stress that such reforms alone may 
not  completely  solve  the  missing-money  problem.73  Either  because  market  reforms 
may  take  time  to  be  fully  implemented  or  because  they  may  be  insufficient  to  fully 
address the generation adequacy problem generated by the lack of optimal incentives 
to  invest  in  generation  capacity,  Member  States  may  want  to  establish  additional 

72   The electricity markets of Australia and Texas are often referred to as examples of functioning energy-only markets. In 
Australia, the price cap is set at VOLL, but market participants have ensured themselves against peaks by developing 
hedging  products  which  in  turn  allow  operators  of  peak  generation  units  to  earn  a  stable  income  in  the  energy-only 
market. In Texas, the electricity price is amplified by adding a pre-defined amount of money per MWh to the electricity 
price depending on the stress of the system. The lower the remaining reserves, the higher the sum that is disbursed to 
the  contributing  generators.  According  to  the  respective  regulatory  authorities,  both  of  these  markets  appear  to  have 
delivered sufficient investment to meet centrally determined reliability standards over many years. See for Australia: 
https://www.aer.gov.au/system/files/State%20of%20the%20energy%20market%202014%20-%20Chapter%201%20-
%20National%20electricity%20market%20A4_0.pdf and for Texas: Brattle Group’s 1 June 2012 report to the Public 
Utility Commission of Texas, “ERCOT Investment Incentives and Resource Adequacy” 
http://www.ercot.com/content/news/presentations/2013/Brattle%20ERCOT%20Resource%20Adequacy%20Review%2
0-%202012-06-01.pdf.  
See Joskow P. L. (2008): "The reforms to wholesale energy markets discussed above should help to reduce the missing 
money problem associated with the operation of many 'energy only' wholesale markets today. However it is not at all 
obvious that the missing money problem will be completely solved with these reforms or that they can be implemented 
overnight. These reforms may also increase market power problems and further increase price volatility." 

73  

47 

 
 
                                                 
 
measures  to  address  a  residual  missing  money  problem  and  ensure  generation 
adequacy.74 

(124)  While  it  is  possible  that  such  a  residual  missing  money  problem  subsists  even  after 
market  reforms,  the  Commission  does  not  conclude  here  that  there  is  a  need  for 
further  intervention  through  capacity  mechanisms  in  every  Member  State.  The  need 
for  a  capacity  mechanism  depends  on  the  objective  circumstances  in  each  market, 
which  will  need  to  be  thoroughly  assessed  by  the  competent  authorities  in  each 
Member  State,  taking  into  account  the  participation  in  an  increasingly  integrated 
electricity system at European level. 

(125)  While capacity mechanisms can be justified when a residual missing money problem 
is  identified,  capacity  mechanisms  cannot  replace  the  reforms  pending  to  make 
electricity  markets  more  efficient.  Each  of  the  opportunities  for  reform  identified  in 
the previous section are at the very heart of the effort, both at national and European 
levels,  to  bring  about  more  efficient  markets  that  provide  reliable  electricity  to 
consumers at the least possible cost. These reforms will allow exploiting as much as 
possible the potential of competitive markets to efficiently deliver reliable electricity 
to the benefit of final consumers. These reforms can therefore be neither neglected nor 
delayed. 

(126)  Correcting  the  market  and  regulatory  failures  that,  to  a  large  extent,  contribute  to 
erode  incentives  to  invest  in  generation  capacity  will  reduce  the  concerns  about  the 
reliability of European electricity systems. It will also  reduce the need for additional 
interventions  like  capacity  mechanisms,  minimising  potential  market  distortions  and 
saving public resources. Therefore, advancing in the market reforms discussed above 
is warranted irrespective of whether the implementation of any capacity mechanism is 
planned, and irrespective of the type of capacity mechanism envisaged. 

(127)  The  eleven  Member  States  under  assessment  in  this  inquiry  have  opted  for  the 
introduction of one or more capacity mechanisms to address perceived residual market 
failures.  The  designs  of  the  mechanisms  vary  widely,  but  all  have  in  common  the 
underlying  principle  of  enabling  revenues  for  capacity  providers  and  thus  they  may 
fall  within  the  category  of  state  aid  measures.  They  can  therefore  be  subject  to  the 
Union's  rules  on  state  aid  and  their  compatibility  with  these  rules  may  have  to  be 
assessed by the Commission.  

74  

See  Joskow  P.  L.  (2008):  'Lessons  learned  from  Electricity  Market  Liberalization':  "A  number  of  countries  are 
considering imposing resource adequacy, forward contracting obligations, or providing capacity payments to generators 
to overcome imperfections in wholesale and retail markets in order to restore incentives for investments in generating 
capacity and demand response capabilities consistent with traditional reliability levels." 

48 

 
 
                                                 
(128)  The  following  chapters  describe  and  assess  the  capacity  mechanisms  applied  or 

planned in the eleven Member States.  

49 

 
 
3. 

MEMBER STATE INTERVENTIONS: OVERVIEW AND CLASSIFICATION 

(129)  There  are  various  types  of  capacity  mechanisms.  They  can  be  categorised  to  some 
extent based on their basic characteristics, and within each category further parameters 
can  be  set  that  determine  the  precise  design.75  This  chapter  describes  the  six  basic 
types of capacity mechanism previously identified by the Commission, and identifies 
where the capacity mechanisms identified in the sector inquiry fit into this framework. 

(130)  The  chapter  briefly  describes  the  main  features  of  the  different  types  of  capacity 
mechanisms identified in the sector inquiry. More detail on specific design elements is 
provided in Chapter 5. 

3.1 

Types of capacity mechanisms 

(131)  The various types of capacity mechanisms can be grouped into two broad categories: 
targeted mechanisms and market-wide mechanisms. Within these two categories, it is 
also possible to distinguish volume-based mechanisms and price-based mechanisms.  

Figure 22: Taxonomy of capacity mechanism models 

Source: European Commission 

3.1.1

  Targeted mechanisms 

(132)  Targeted mechanisms are those where the amount of capacity required and the amount 
expected  to  be  brought  forward  by  the  market  are  identified  centrally.  The  capacity 
mechanism then provides support only to the additional capacity (or 'top up') expected 
to be needed beyond what would anyway be brought forward by the market.  

75   The Commission developed this categorisation in a Non Paper, which was discussed with Member States in a working 

group that took place on 30 June 2105. It is available here:  
http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_working_group_10_en.pdf.  

50 

 
 
 
                                                 
 
(133)  For the purposes of the sector inquiry, we have identified three basic types of targeted 

mechanism.76 

  Tender  for  new  capacity  –  typically,  the  beneficiary  of  such  a  tender  receives 
financing for the construction of a power plant that would bring forward the identified 
top up capacity. Once the plant is operational, in some models the top up capacity runs 
in the market as normal (without a guarantee that the electricity will be sold). It would 
also be possible for the plant to be supported through a power purchase agreement.  
  Strategic reserve – in a strategic reserve mechanism, the top up capacity is contracted 
and then held in reserve outside the market. It is only run when specific conditions are 
met (for instance, when there is no more capacity available or electricity prices reach a 
certain  level).  Typically  strategic  reserves  aim  to  keep  existing  capacity  available  to 
the system. 

  Targeted capacity payment – in this model, a central body sets the price of capacity. 
This  price  is  then  paid  to  a  subset  of  capacity  operating  in  the  market,  for  example 
only  to  a  particular  technology,  or  only  to  capacity  providers  that  meet  specific 
criteria. 

(134)  Both  the  strategic  reserve  and  the  tender  models  are  'volume-based'  mechanisms 
because the volume of capacity that receives support is determined at the outset. They 
differ from the 'price based' targeted payment model where there is no restriction on 
the amount of capacity that receives the payment, but rather a restriction on the type/s 
of capacity eligible.  

3.1.2

  Market-wide mechanisms  

(135)  In  a  market-wide  mechanism,  all  capacity  required  to  ensure  security  of  supply 
receives  payment,  including  both  existing  and  new  providers  of  capacity.  This 
essentially establishes 'capacity' as a product separate from 'electricity'.  

(136)  There are three basic types: 

  Central  buyer  –  where  the  total  amount  of  required  capacity  is  set  centrally,  and 
then  procured  through  a  central  bidding  process  in  which  potential  capacity 
providers compete so that the market determines the price.  

  De-central  obligation  –  where  an  obligation  is  placed  on  electricity  suppliers  / 
retailers to contract with capacity providers to secure the total capacity they need 
to  meet  their  consumers'  demand.  The  difference  compared  to  the  central  buyer 
model  is  that  there  is  no  central  bidding  process,  but  market  forces  should  still 
establish the price for the required capacity volume.  

76  

http://europa.eu/rapid/press-release_MEMO-15-4892_en.htm. 

51 

 
 
 
                                                 
  Market-wide capacity payment – where the price of capacity is set centrally, based 
on  central  estimates  of  the  level  of  capacity  payment  needed  to  bring  forward 
sufficient total capacity and then paid to all capacity providers in the market. 

(137)  These mechanisms provide support to all (or at least the majority of capacity providers 

in the market – there may still be some restrictions on eligibility). 

(138)  The central buyer and de-central obligation models are volume-based: in these models 
the volume of capacity required is set at the outset, while the price is determined by 
the  market.  The  market-wide  capacity  payment  is  price-based  since  the  price  for 
capacity  expected  to  achieve  sufficient  investment  is  fixed  at  the  outset,  while  the 
volume may vary depending on how the market reacts to that price.77  

(139)  Further variations are possible within the different models depending on the detailed 

design.  

3.2 

Capacity mechanisms in place in the 11 Member States 

(140)  The  Member  States  assessed  in  the  sector  inquiry  have  been  selected  because  they 
have  either  introduced  or  are  considering  introducing  one  or  more  capacity 
mechanisms.  The  combination  of  Member  States  was  also  chosen  to  constitute  a 
representative  sample  of  the  different  capacity  mechanism  types  being  developed  in 
Europe.  

(141)  The  mechanisms  brought  to  the  attention  of  the  Commission  by  respondents  to  the 
sector inquiry vary widely and categorising them according to the taxonomy provided 
in Figure 22 is not always straightforward.  

(142)  To  help  determine  whether  a  measure  or  practice  in  a  Member  State  qualifies  as  a 
capacity  mechanism  within  the  scope  of  this  inquiry,  the  Commission  has  identified 
the following indicators. Capacity mechanisms: 

  are generally initiated by or with the involvement of governments; 
  have the primary objective of contributing to security of supply; and 
  provide remuneration to capacity providers in addition to revenues they receive in the 
electricity  market,  or  instead  of  revenues  they  could  otherwise  have  received  in  the 
electricity market. 

(143)  A  particular  area  in  which  there  may  be  debate  about  what  constitutes  a  capacity 
mechanism  and  what  requires  State  aid  approval  is  in  the  specification  and 

77   Note even volume based mechanisms may be designed to enable some flexibility on the volume procured in reaction to 
prices of capacity (sloping demand curve), which is not known definitively until the allocation process takes place. This 
is for example the case in the planned Italian central buyer mechanism and in the GB capacity auction. 

52 

 
 
                                                 
procurement of ancillary services. TSOs typically procure frequency (balancing of the 
system)  and  non-frequency  (voltage  control  and  black-start)  ancillary  services  to 
ensure the management of the system. In most cases, they are mandated to do so by a 
general public service obligation to maintain system stability and security. Where such 
ancillary  services  are  procured  independently  by  TSOs,  and  where  in  particular  the 
determination of the precise volumes and types of services to be procured is left to the 
TSOs  without  Government  involvement,  there  will  be  a  strong  indication  that  the 
purchase  of  such  services  does  not  involve  State  aid  and  that  those  services  are 
therefore  not  covered  by  this  inquiry.  Such  indication  will  be  strengthened  when 
procurement  of  such  services  is  performed  in  a  transparent,  competitive  and  non-
discriminatory  way,  thereby  excluding  undue  advantages.  Another  element  to 
distinguish ancillary services from capacity mechanisms is the use and purpose of the 
services: when they are used in small volumes relative to the overall level of capacity 
in  the  market  and  only  to  provide  short  term  corrections  to  enable  system  security, 
they will more likely be considered ancillary services. 

(144)  However,  where  ancillary  services  appear  to  be  contracted  at  the  request  of 
governments and/or are used to ensure capacity is available to balance the system over 
longer periods, they can have the same effect as capacity mechanisms. Such measures 
may merit attention from the Commission and require State aid approval. 

(145)  In  some  cases  capacity  mechanisms  do  not  cover  the  whole  territory  of  a  Member 
State. In particular islands may be excluded from a capacity mechanism (as is the case 
in  one  Portuguese  scheme)  or  may  benefit  from  specific  support  measures  (for 
example,  Italy  has  implemented  separate  interruptibility  schemes,  one  for  the 
mainland and one for Sardinia and Sicily).  

(146)  Some  mechanisms  are  hybrid  forms  of  two  types  identified  in  the  taxonomy:  for 
example a Portuguese scheme which makes administratively determined payments to 
demand  response  beneficiaries,  in  return  for  their  being  available  –  effectively  in 
reserve – until the TSO asks them to reduce demand. This has elements of the targeted 
capacity  payment  model  (administratively  determined  payments  to  a  subset  of 
capacity  providers)  and  of  the  strategic  reserve  model  (beneficiaries  are  held  in 
reserve and instructed to run by the TSO). 

(147)  The sector inquiry identified seven countries that operate specific schemes for demand 
response  (usually  large  industrial  users)  that  at  first  sight  match  the  indicators  for 
identifying  a  capacity  mechanism:  France,  Germany,  Ireland,  Italy  Poland,  Portugal 
and Spain. Beneficiaries of such 'interruptibility schemes' are then held in reserve until 
required  by  the  TSO.  For  this  reason,  these  schemes  can  be  regarded  as  a  form  of 
strategic reserve. 

(148)  Other  measures  identified  by  respondents  have  some  features  of  a  capacity 
mechanism,  but  are  not  designed  primarily  to  ensure  security  of  supply  and  instead 

53 

 
 
address other objectives, for example the existing Danish schemes for combined heat-
power  (CHP)  generation  which  make  payments  for  availability  but  were  designed 
primarily to bring forward investment in CHP capacity and reduce emissions.78  

(149)  Although not a definitive view of the number of capacity mechanisms in the countries 
covered by the sector inquiry, Table 3 below was compiled on the basis of responses 
to  the  sector  inquiry  and  the  above  indicators  and  considerations,  and  gives  an 
impression of the number and type of the capacity mechanisms in place or considered 
in the countries.  

Table 3: Capacity mechanisms in the sector inquiry 

Source: European Commission based on replies to sector inquiry 

78   Denmark's support to CHP capacity has been the subject of previous State aid decisions  – see SA.30382, SA.35486, 

and SA.42519. 

54 

 
 
  
                                                 
Figure 23: Capacity mechanisms (existing, planned and on hold) in the 11 Member 
States – excluding interruptibility schemes 

Source: European Commission based on replies to sector inquiry 

(150)  The  following  sections in  this  chapter  describe  the  features  of  each  type  of  capacity 
mechanism with reference to the examples found in the inquiry. The different schemes 
are described in terms of three general design elements: 

 

 

 

the  eligibility  rules,  which  determine  any  restrictions  or  requirements  relating  to  the 
type, size and location of potential beneficiaries; 
the  allocation  process,  which  determines  the  way  in  which  eligible  beneficiaries  are 
selected,  and  the  way  in  which  the  capacity  remuneration  they  will  receive  is 
determined; and 
the  capacity  product,  which  determines  what  the  beneficiaries  must  do  in  return  for 
their capacity remuneration, and what the sanctions are if they do not do this. 

(151)  A more detailed analysis of these design elements is given in Chapter 5. 

3.2.1

  Tender for new capacity 

(152)  Examples  of  tenders  for  new  capacity  were  found  in  four  of  the  Member  States 

included in the sector inquiry: Belgium, France, and Ireland.  

55 

 
 
 
  Belgium  in  2014  launched  a  tender  to  attract  investment  in  700-900 MW  of  OCGT 
(open-cycle gas turbine) or CCGT (combined-cycle gas turbine) capacity. The tender 
was however abandoned in early 2015. 
In Croatia, the State owned energy company Hrvatska elektroprivreda (HEP) launched 
a tender in 2012 for investment in a new 515 MW coal-fired power station at Plomin 
on the Adriatic coast.  

 

 

  France launched a tender for the construction of a 450 MW combined cycle gas-fired 
power station in 2011 to deal with regional security of supply concerns in Brittany.79 
In  2003,  Ireland  developed  a  tender  mechanism  in  view  of  an  expected  shortfall  in 
capacity  from  2005  onwards.  The  process  resulted  in  the  construction,  in  2005  and 
2006 respectively, of a new CHP facility and a new CCGT with a combined installed 
capacity of over 500 MW.80 

3.2.1.1

 Eligibility 

(153)  All four tenders for new capacity specified many characteristics of the chosen capacity 
product in advance, including for example the size, technology type and location. The 
tenders in France and Belgium were limited to gas-fired plants only (with the tender in 
France limited only to CCGT capacity). The tender in Ireland was open to bids from 
any new centrally dispatchable thermal plants81. The tender in Croatia was limited to 
coal capacity at a specific coastal site with existing coal infrastructure and where coal 
can be imported. None of the four tenders were open to demand response. 

(154)  All tenders were limited to new projects, although the Belgian tender was eventually 
opened  to  existing  foreign  capacity  with  the  potential  to  be  incorporated  into  the 
Belgian  bidding  zone.  In  all  examples  long  contracts  were  available  (ten  years  in 
Ireland, twenty years in Croatia and France and up to seven years in Belgium).  

(155)  In  Croatia  and  France,  the  proposed  tender  required  a  single  bidder  to  fulfil  the 
identified  capacity  requirement.  In  Ireland,  the  2003  tender  was  open  to  multiple 
projects (of minimum 50 MW each) and in fact there were 2 successful beneficiaries 
that, taken together, were able to fulfil the identified requirement. 

(156)  The  French  tender  for  new  capacity  was  limited  to  capacity  physically  located  in  a 
specific area within Brittany. This locational requirement was justified by the need to 
ensure  voltage  control.  The  Belgian  and  Irish  tenders  were  open  to  projects  located 

79   The Commission opened a formal investigation into the measure on 13 November 2015. See:   

http://europa.eu/rapid/press-release_IP-15-6077_en.htm  

80   The mechanism received state aid clearance from the Commission in 2003.  

http://ec.europa.eu/competition/state_aid/cases/137628/137628_485545_28_2.pdf  

81   Centrally  dispatchable  plants  are  those  that  can  be  dispatched  at  the  request  of  power  grid  operators  (ie.  they  can 

reliably begin generating on request). 

56 

 
 
                                                 
 
outside  of  the  Member  States'  national  territory,  but  only  on  the  condition  that  they 
had dedicated transmission connections to the Belgian or Irish grid.  

3.2.1.2

 Allocation process 

(157)  In all of the tenders the price, but also the speed of development of potential projects 
were  considered.  In  Ireland,  bid  prices  were  adjusted  to  account  for  the  projects' 
locations and development dates; eventually the cheapest bundle of bids that met the 
requirement  was  selected.  In  the  French  and  Belgian  tender  price  was  not  the  only 
award criterion; for instance, in both procedures the construction time was also taken 
into  account.  The  French  authorities  also  considered  the  proposed  site  of  the 
installation and its impact on the environment, while in the Belgian tender procedure 
the "contribution to market functioning" (i.e. the contribution to a competition in the 
market, with a bias in favour of new entry) were also considered. 

3.2.1.3

 Capacity product 

(158)  In Belgium and France, the successful beneficiary would receive capacity payments in 
return  for  making  capacity  available,  and  could  participate  in  the  electricity  market 
and earn separate revenue from the sale of electricity. In France, these payments can 
be reduced both in case of non-availability and in case of a delay in the construction of 
the  installation.  In  Belgium  the  selected  power  plant(s)  would  have  needed  to  be 
available  during  winter  for  a  predetermined  amount  of  time,  while  in  Brittany  the 
availability obligations apply throughout the year. 

(159)  In Croatia, the successful beneficiary would receive availability payments per MW of 
capacity made available to HEP, and energy payments for the costs of each MWh of 
energy generated by the plant. 

(160)  In  Ireland,  the  successful  generators  received  'capacity  and  differences  agreements'. 
They  received  capacity  payments  for  their  availability,  and  were  free  to  run  in  the 
market  and  earn  separate  electricity  revenues.  However,  the  agreements  included  a 
claw-back mechanism since the generators had to repay the difference if market prices 
went above a pre-defined strike price. 

3.2.2

  Strategic reserve 

(161)  Examples of strategic reserves (excluding interruptibility schemes) were found in five 
of  the  Member  States  included  in  the  sector  inquiry:  Belgium,  Denmark,  Germany, 
Poland, and Sweden. Germany plans to operate more than one strategic reserve.  

 

In  Belgium  a  strategic  reserve  was  introduced  in  2014  as  a  back-up  for  peaks  in 
demand  during  the  winter  period.  800 MW  capacity  was  sought  in  the  first  year, 
3,500 MW in the second year, and 750 MW for the winter 2016-2017.  

57 

 
 
  Denmark  proposed  to  create  a  new  200 MW  strategic  reserve  in  its  Eastern  DK2 
bidding zone in 2016. The reserve was intended to be transitional until interconnection 
capacity is increased. However, the measure has not been implemented. 

  Germany  has  a  'network  reserve'  in  place  to  address  grid  bottlenecks  between 
generation in the north of the country and demand in the south. The reserve consists 
primarily  of  power  plants  that  have  signalled  their  intention  to  close  down  but  have 
been prohibited from doing so because they are deemed of importance for maintaining 
system stability ('system relevance'). These plants are moved into the network reserve, 
activated  when  there  is  insufficient  network  capacity  to  send  power  from  north  to 
south  ('mandatory  part')  and  reimbursed  for  the  costs  that  result  from  the  statutory 
interference with the rights of the plant operator. In case the combined capacity of the 
power  plants  that  have  been  prohibited  from  closing  is  insufficient  to  satisfy  the 
identified need for the network reserve, then a tender is organised to attract additional 
reserve capacity (the 'voluntary part'). In practice, this additional need is satisfied by 
power  plants  located  in  Austria  and  Italy.  The  network  reserve  differs  from  other 
strategic  reserves  not  only  because  of  its  regional  nature,  but  also  because  its 
activation is not triggered by a non-clearing market, but rather as an instrument for the 
TSOs in Southern Germany that allows them to maintain grid stability when there is 
insufficient  transmission  capacity  to  flow  power  to  the  south  of  the  country  ('re-
dispatch'). A review of the network reserve is currently ongoing.  

  Germany  is  also  considering  introducing  a  country-wide  strategic  reserve  of  2 GW 
('capacity reserve') as of 2018, to be held outside the market. The deployment of the 
capacity reserve is triggered when the day-ahead or intraday market does not clear and 
if no other measures are available to the TSO, so as to minimise market distortions.  
  Poland  has  created  a  strategic  reserve  comprising  830 MW  of  generation  capacity 
('cold  contingency  reserve').  The  cold  contingency  reserve  is  intended  to  be 
transitional for two years starting in 2016, with the possibility to extend for a further 
two years beyond this. 

  Sweden has operated a strategic reserve of up to 2 GW since 2003, designed to ensure 
sufficient capacity is available in the winter to cover peak load. The reserve currently 
comprises  1 GW  capacity.  The  reserve  was  due  to  be  removed  after  winter  2019/20 
but it will be extended for a further five years until 2025. 750 MW will be contracted 
for the period 2017-2025. 

3.2.2.1

 Eligibility 

(162)  The technological eligibility rules for strategic reserves are varied, with the reserves in 
Belgium, Denmark and Sweden open to demand response as well as generation, while 
the  German  network  reserve  and  the  Polish  reserve  are  only  open  to  generation 
capacity. Reserves are typically not designed to attract new generation capacity. 

(163)  Some reserves  are location-specific, meaning they aim to  address  grid congestion or 
capacity  shortage  only  in  certain  parts  of  a  Member  State.  None  of  the  strategic 
reserves  are  open  to  generators  located  outside  of  the  Member  State  operating  the 
reserve, except for the German network reserve. 

58 

 
 
3.2.2.2

 Allocation process 

(164)  In  general,  the  strategic  reserves  include  a  competitive  process  for  identifying  the 
capacity  providers  that  will  provide  reserve  services  and  in  all  examples  with 
competitive  processes  beneficiaries  are  paid  the  price  they  bid  for  the  services  they 
provide  (which  usually  includes  a  payment  for  being  available  and  a  separate 
activation  payment).  In  practice,  however,  there  is  not  always  enough  existing 
capacity on offer to allow for a competitive tender. 

3.2.2.3

 Capacity product 

(165)  In  all  examples  of  strategic  reserves  except  for  foreign  plants  participating  in  the 
German network reserve, selected capacity providers are held in reserve outside of the 
market.  They  can  no  longer  earn  revenues  from  the  sale  of  electricity,  and  can  only 
run  when  instructed  to  do  so  by  the  TSO.  In  practice  most  reserves  are  used 
infrequently82,  but  the  existing  reserves  are  usually  dispatched  when  the  day-ahead 
electricity market does not clear.  

(166)  If the capacity providers are not able to make themselves available or fail to deliver 
when  tested  or  called  by  the  TSO, then  they  generally  face  a  risk  of  missing  out  on 
future  availability  payments,  or  having  to  return  already  received  availability 
payments. 

3.2.2.4

 Dispatch rules and link with market pricing 

(167)  In Belgium and Sweden reserve capacity is dispatched if the day-ahead market fails to 
clear  and  there  would  be  involuntary  unmet  demand  without  the  reserve  capacity. 
Reserve  capacity  can  also  be  triggered  intraday  in  Belgium  if  the  TSO  anticipates 
scarcity  that  was  not  apparent  at  the  day-ahead  stage.  And  in  Sweden,  reserve 
participants  can  also  be  dispatched  by  the  TSO  after  gate  closure  in  the  regulating 
power market if there are insufficient commercial bids to meet demand.  

(168)  Once  reserve  capacity  is  dispatched  it  can  have  a  significant  impact  on  electricity 
market  prices.  In  Sweden,  in  periods  when  the  reserve  is  activated  electricity  prices 
are set by the highest commercial bid in the electricity market. In the Belgian reserve 
and the on hold Danish reserve, however, for periods when the reserve is dispatched 
and  its  capacity  is  required  to  meet  demand,  electricity  prices  are  set  to  a  pre-
determined  high  level  (4,500  EUR/MWh  in  Belgium,  and  3,000  EUR/MWh  in 
Denmark).  

82  

For example,  the  Swedish strategic  reserve  has been activated eleven times  between  2003 and 2015.  In  seven of  the 
twelve years of operation it was not activated at all. The Belgian reserve has not yet been activated.  

59 

 
 
                                                 
3.2.3

  Interruptibility schemes 

(169)  A  subcategory  of  strategic  reserves,  interruptibility  schemes  were  found  in  seven  of 
the  Member  States  included  in  the  sector  inquiry:  France,  Germany,  Italy,  Ireland, 
Poland, Portugal, and Spain.  

  Since 2010, Italy also has operated two interruptibility schemes: one for the two main 
islands (aiming to contract 500 MW in each of Sardinia and Sicily) and another for the 
mainland  contracting  3,300 MW.  The  scheme  for  the  two  islands  was  reformed  in 
2016, with the target volume being reduced to 400 MW in Sardinia and 200 MW in 
Sicily.  

  Between 2013 and 2016 German TSOs have organised monthly tenders for 3,000 MW 
of sheddable load provided by consumers larger than 50 MW. The scheme is presently 
being revised, whereby it is the intention of the German legislator to widen eligibility 
requirements by means of a lowering of the participation threshold (to 10 or 5 MW), 
by  shortening  contract  durations (from  one  month  to  one  week)  and  by allowing  for 
the possibility of pooling or aggregation of loads. Also the total amount to be procured 
would be reduced to 1,500 MW. 
In  September  2012,  the  Polish  TSO  launched  a  tender  to  attract  demand  response 
services. The first tender failed to attract any bids but four subsequent tenders between 
2013 and 2015 resulted in 200 MW demand response capacity being contracted. 

 

  Since  2011,  Portugal  has  operated  an  interruptibility  scheme.  1,410 MW  of  capacity 

was contracted under the scheme in 2015. 

  Since  2007  Spain  has  operated  an  interruptibility  scheme.  3 GW  of  capacity  was 

 

 

contracted in 2015. 
In  Ireland  the  Powersave  scheme,  operated  by  Eirgrid,  is  a  voluntary  scheme 
encouraging  large  and  medium  sized  customers  to  reduce  their  demand  when  total 
system  demand  is  close  to  available  supply.  With  up  to  50 MW  of  total  demand 
reduction potential it is considerably smaller than the other schemes. 
In  France,  an  interruptibility  scheme  is  in  place  since  2014,  to  be  used  during 
emergency situations only. Since late 2015, the law prescribes the exact amount to be 
procured by the TSO: 1,600 MW divided between two product categories.  

(170)  In  most  schemes,  beneficiaries  are  paid  a  fixed  price  for  each  MW  of  demand 
response  made  available  as  well  as  a  price  for  demand  reductions  actually  made 
(energy  delivered).  In  Poland  and  Ireland  beneficiaries  are  only  paid  for  energy 
delivered and receive no availability payment.  

(171)  There  is  a  difference  between  schemes  that  have  been  established  by  the  TSO  to 
provide  it  with  a  valuable  tool  for  ensuring  system  stability  and  schemes  that  have 
been introduced by the government to request a fixed amount of demand response to 
be contracted. Also where the capacity is requested by the government it may have a 
useful  function,  but  the  distinction  is  relevant  from  a  state  aid  perspective.  For 
instance, the interruptible load scheme established by the German government may be 

60 

 
 
used by the TSOs for re-dispatch purposes. By temporarily switching off loads in the 
South, the need for north-south flows is alleviated. 

3.2.3.1

 Eligibility 

(172)  By  definition  the  interruptibility  schemes  are  limited  to  demand  response  capacity. 
Some  schemes  have  further  restrictions  on  eligibility,  such  as  minimum  size 
requirements. 

(173)  None of the interruptibility schemes are open to beneficiaries located in other Member 

States. 

3.2.3.2

 Allocation 

(174)  Most  schemes  allocate  contracts 

through  a  competitive  process,  Prices  are 
administratively set in Ireland, Italy (only islands scheme as of 2016), and Portugal. In 
Germany, currently demand for the service generally outweighs supply so prices are 
set administratively.  Amendments to  the scheme  may address this issue by reducing 
the total demand. 

3.2.3.3

 Capacity product 

(175)  In all schemes, large energy users must agree to be automatically disconnected when 
needed  by  the  TSO.  There  is  generally  no  prior  notice  and  disconnection  is  often 
instant. Interruptions can last for up to several hours.  

(176)  There  are  schemes  where  the  product  specification  allows  the  TSO  to  respond  to 
immediate  balancing  issues,  such  as  frequency  restoration,  whereby  it  immediately 
remotely disconnects contracted loads, such as the German and Italian schemes. There 
are also schemes aimed at alleviating adequacy concerns of a longer term, such as the 
Irish  scheme  in  which  consumers  are  obliged  to  reduce  their  loads  themselves  upon 
notification  by  the  TSO  at  least  30  minutes  before  the  'Powersave'  event  starts. 
Beneficiaries  in  the  Irish  scheme  do  not  have  to  reduce  their  consumption,  but  are 
only rewarded if they do reduce their demand. 

3.2.4

  Targeted capacity payments 

(177)  Examples  of  targeted  capacity  payments  were  found  in  four  of  the  Member  States 
included  in  the  sector  inquiry:  Italy,  Poland,  Portugal,  and  Spain.  Portugal  operates 
two of these mechanisms, and Spain has operated four of these mechanisms. 

 

In 2003, Italy introduced targeted capacity payments for dispatchable generators. The 
mechanism was conceived as a transitional measure and Italy is planning to replace it 
with a central buyer mechanism. 

61 

 
 
  Poland  has  operated  an  operational  capacity  reserve  since  1  January  2014.  During 
working  days'  peak  hours  (8-22h),  all  available  centrally  dispatchable  capacity  (so 
excluding wind, CHP etc.) that has not secured power sales contracts or is not subject 
to a forced dispatch by the TSO (Poland has a central dispatch model) automatically 
constitutes  the  operational  reserve.  The  operational  reserve  plants  receive  a  level  of 
remuneration  per  MW  that  varies  depending  on  the  amount  of  capacity  constituting 
the operational reserve in a given hour but is in any case capped (in 2016, the hourly 
cap equalled 41.2 PLN/MW ~ 9.5 EUR/MW). 

  Portugal operates four targeted capacity payments schemes: 

o  an  'availability  incentive'  scheme  that  remunerates  thermal  plants  for  their 

availability; and 

o  an 'investment incentive' scheme which aims to incentivise investments in new 
hydro generation and in the repowering of existing pump storage units through 
a capacity payment83. 

o 

o  a power purchase agreement with a regulated company covering one coal and 
one gas-fired power plant (1.8 GW in total). The contracts run until 2024;   
the  Contractual  Equilibrium  Insurance  ('CMEC')  whereby  after  2004,  power 
stations  bound  by  PPAs  were  allowed  to  replace  them  by  a  legal  mechanism 
that grants them difference between market prices and what they would have 
received under the PPA; it covers 3.8 GW of capacity and is valid until 2027.   

  Spain operates three targeted capacity payments schemes: 

o  an 'investment incentive' scheme since 2007 for new nuclear, gas, coal, hydro, 

and oil plants; 

o  an 'availability incentive' scheme since 2007 for new and existing gas, coal, oil 

and hydro with storage; and 

o  an  'environmental  incentive'  scheme  since  2007  for  coal  plants  that  fitted 

sulphur dioxide filters. 

  Between 1997 and 2007 Spain operated another capacity payment mechanism called 
the  'power  guarantee'.  The  mechanism  was  replaced  by  the  currently  operational 
capacity payments schemes.  

  Between  2010  and  2014,  Spain  also  operated  a  'supply  guarantee  constraints 
resolution' mechanism which supported domestic coal production by providing plants 
burning  domestic  coal  with  priority  dispatch84  and  regulated  prices.  Some  market 
participant respondents noted that Spain may develop a new support scheme for plants 
burning domestic coal. However, Spain has explained that it has no plans to develop 
any new capacity mechanism.  

83  

84  

Pump storage units are hydropower facilities in which water can be raised by means of pumps and stored to be used for 
the later generation of electricity. 
Plants subject to priority dispatch will be selected to generate electricity ahead of plants with lower running costs that 
would otherwise have been chosen to meet demand. 

62 

 
 
                                                 
3.2.4.1

 Eligibility 

(178)  Most of the targeted capacity payments schemes are open to dispatchable generation 
(coal, gas, hydro with storage, and sometimes oil). But there are many variations, for 
example  the  hydro-specific  investment  incentive  scheme  in  Portugal,  the  investment 
incentive in Spain which is also open to nuclear, and the environmental incentive in 
Spain which is only open to coal plants.  

(179)  Although they are all national schemes and therefore geographically restricted to the 
territory  of  the  Member  State  implementing  them,  most  of  the  targeted  capacity 
payments are otherwise non location-specific.  

(180)  None of the targeted capacity payments schemes are open to demand response, nor are 
they  open  to  beneficiaries  located  outside  of  the  Member  States  operating  the 
schemes. 

(181)  Most targeted capacity payments schemes are open to existing and new generators and 

provide annual capacity payments with no longer term contracts. 

3.2.4.2

 Allocation process 

(182)  By definition, capacity payments mechanisms involve an administrative price-setting 
and  allocation  process  rather  than  a  competitive  price-setting  process.  The  level  of 
remuneration  is  set  centrally  –  e.g.  in  Italy  by  the  regulator  –  and  then  paid  to  all 
eligible capacity providers.  

3.2.4.3

 Capacity product 

(183)  In  general,  the  beneficiaries  of  targeted  capacity  payments  must  make  their capacity 
available  during  peak  demand  periods,  or  face  penalties  requiring  them  to  repay  or 
forego  capacity  remuneration.  However,  beneficiaries  of  the  Spanish  investment 
incentive  are  simply  obliged  to  build  and  operate  an  eligible  power  plant  with  no 
additional performance requirements. 

3.2.5

  Central buyer 

(184)  Examples  of  central  buyer  schemes  were  found  in  three  of  the  Member  States 
included  in  the  sector  inquiry:  Ireland,  Italy,  and  Poland.  All  three  mechanisms  are 
still in  development and  are not  yet operational. Examples  of central  buyer schemes 

63 

 
 
are also found in the UK (British mechanism)85, and in the United States including in 
the ISO New England and PJM systems on the East Coast.86 

 

 

Ireland  intends  to  replace  the  existing  market  wide  capacity  payment  mechanism  in 
2017  with  a  market-wide  central  buyer  capacity  mechanism  based  on  reliability 
options. Reliability options are a type of capacity product and are described in more 
detail in Section 5.4.2.1. 
Italy  is  planning  to  replace  its  existing  targeted  capacity  mechanism  with  a  central 
buyer mechanism, where reliability options would be traded in auctions organised by 
the TSO.  

  Poland  is  planning  to  make  various  reforms  to  its  electricity  market  and  also  to 
implement  a  central  buyer  mechanism,  and  aims  to  hold  the  first auction  as  early  as 
2017. The proposed design appears to be similar to the British mechanism. 

3.2.5.1

 Eligibility 

(185)  Although still in development, the Irish, Italian and Polish central buyer schemes are 
both  intended  to  be  open  to  all  potential  capacity  providers  including  both  new  and 
existing  resources,  and  demand  response.  Central  buyer  models  allow  different 
contract durations, ranging from one to fifteen year contracts in the EU mechanisms 
(incl. GB). 

(186)  In  terms  of  geographic scope,  the  Irish  mechanism  is  expected  to  operate  across  the 
whole  island  of  Ireland.  The  Italian  mechanism,  by  contrast,  is  being  designed  as  a 
zonal system to  match  Italy's underlying electricity  market which is  divided into six 
bidding zones. This means demand for capacity will be established for each of the six 
zones, and a separate capacity price established in auctions for each zone depending 
on  the  local  balance  of  supply  and  demand.  The  British  mechanism  is  open  to  the 
participation  of  interconnectors,  but  not  to  foreign  capacity.  The  Irish  and  Italian 
schemes have not yet developed rules for foreign capacity participation but intend to 
enable foreign participation. Poland's intentions for cross border participation are not 
yet clear.  

85  

See  Commission  decision  C  (2014)  5083  final  of  23.7.2014  in  Case  SA.35980  (2014/N-2)  –  United  Kingdom  - 
Electricity market reform – Capacity market. The public version of the decision is available at: 
http://ec.europa.eu/competition/state_aid/cases/253240/253240_1579271_165_2.pdf. 

86   Although the sector inquiry has not gathered additional information on mechanisms in countries outside the 11 included 
Member  States,  key  points  from  the  design  and  operation  of  these  mechanisms  still  offer  valuable  insights  for  the 
inquiry and are therefore occasionally mentioned in this report. 

64 

 
 
                                                 
 
3.2.5.2

 Allocation process 

(187)  The  central  buyer  mechanisms,  by  definition,  involve  a  central  process  in  which  all 
capacity providers offer their capacity and it is 'bought' by a single buyer on behalf of 
electricity suppliers/consumers.  

3.2.5.3

 Capacity product 

(188)  In the Irish and Italian schemes, the capacity product is a 'reliability option' which will 
oblige  the  capacity  providers  to  pay  the  difference  between  a  reference  electricity 
price  and  a  strike  price  specified  in  the  reliability  option  contract  whenever  the 
reference  price  exceeds  the  strike  price.  In  the  British  mechanism,  providers  must 
have delivered their contracted capacity in any periods in which it was required, and if 
they failed to deliver (or only partially delivered) after a four hour warning was given, 
penalties will apply.  

3.2.6

  De-central obligation 

(189)  The  only  de-central  obligation  scheme  subject  to  the  inquiry  is  the  one  being 
implemented  in  France.  Due  to  the amendments  that  have  been  proposed  to  make  it 
comply  with  the  State  aid  rules87,  the  mechanism  has  become  more  hybrid,  since  it 
now also includes aspects typical of a central buyer mechanism. 

3.2.6.1

 Eligibility 

(190)  All potential capacity providers including demand response and both new and existing 

projects can be granted capacity certificates in the French scheme.  

(191)  Foreign  generation  and  demand  response  capacity  can  participate  directly  to  the 
French  capacity  mechanism,  though  to  the  extent  that  the  neighbouring  TSO  enters 
into  a  cooperation  agreement  with  the  French  TSO  relating  for  instance  to  the 
certification and testing of foreign capacities. Absent such cooperation agreement, the 
interconnectors with the respective neighbouring Member State can get certified and 
sell their certificates in the French capacity market. 

87   The  Commission  opened  a 

formal 

investigation 

the  measure  on  13  November  2015.  See: 
http://europa.eu/rapid/press-release_IP-15-6077_en.htm.  The  Commission's  decision  is  publicly  available  (in  French) 
at:  http://ec.europa.eu/competition/state_aid/cases/261326/261326_1711140_20_2.pdf.  The  French  authorities  have 
subsequently  amended  the  mechanism  to  comply  with  the  requirements  of  the  Energy  and  Environmental  Aid 
Guidelines. Even though some amendments still need to be implemented in law, the remainder of this Staff Working 
Document will refer to the amended French capacity mechanism. 

into 

65 

 
 
                                                 
3.2.6.2

 Allocation Process 

(192)  The de-central obligation model is essentially based on a market for tradable capacity 
certificates.  Capacity  operators,  on  the  one  hand,  obtain  guarantees/certificates  to 
attest  of  their  capacities,  while  suppliers,  on  the  other  hand,  have  an  obligation  to 
obtain  capacity  certificates  in  proportion  to  their  customer  portfolios'  peak  demand 
(adjusted to take account of thermosensitivity). There is an obligation for the largest 
capacity  operators  (>  3  GW)  to  offer  specified  volumes  of  certificates  in  different 
public  auctions  preceding  the  delivery  year,  while  other  capacity  providers  are  free 
either to participate to those auctions or to trade their capacity certificates bilaterally 
OTC.88 

3.2.6.3

 Capacity product 

(193)  In  the  French  scheme,  capacity  providers  must  make  the  capacity  they  have  sold  as 
certificates available in peak demand hours identified in advance by the TSO. In such 
hours, suppliers must either reduce their customers' demand or ensure that they have 
sufficient  certificates  to  cover  the  peak  consumption  of  their  consumers  (adapted  to 
represent  a  cold  winter).  If  suppliers  hold  insufficient  certificates,  or  capacity 
providers  make  insufficient  capacity  available,  capacity  imbalance  penalties  will 
apply. 

3.2.7

  Market wide capacity payments 

(194)  Ireland  introduced  a  market  wide  capacity  payment  mechanism  in  2007  to  provide 

additional revenue to remunerate market participants for their fixed costs.89 

3.2.7.1

 Eligibility 

(195)  The capacity payments are paid to all generators in the market, as well as to providers 

of demand-response and storage that contribute to meeting demand.  

(196)  The  Irish  scheme  also  makes  payments  to  foreign  capacity  providers  –  however,  it 
does  this  by  providing  a  capacity  payment  on  top  of  the  Irish  electricity  price  for 
providers of imports to Ireland (and also deducts the capacity payment for exporters of 
electricity from Ireland). 

88   Note in central buyer schemes the secondary trading of capacity obligations / contracts may also be possible after the 

89  

initial allocation through the capacity auction/s. 
Ireland's electricity market operates as a single market across the Republic of Ireland and Northern Ireland. Due to the 
cross-jurisdictional market arrangements in the Irish electricity system, where the Commission refers to Ireland in this 
report it is usually referring to the island of Ireland which comprises territory of the Republic of Ireland and the United 
Kingdom. Although the Irish electricity market is currently being reformed, in the current design generators can only 
bid their short run marginal costs in the energy market which means prevents peaking generators recovering their fixed 
costs without additional remuneration. 

66 

 
 
                                                 
3.2.7.2

 Allocation process 

(197)  As  with  the  targeted  capacity  payment  schemes,  the  Irish  market's  wide  capacity 
payment involves an administrative price-setting process where the value of capacity 
payments is calculated by the Irish and Northern Irish regulators. Capacity providers 
receive a capacity payment for every 'trading period' in which they were available. 

3.2.7.3

 Capacity product 

(198)  Capacity payments in the Irish market are highest at times of tighter capacity margins, 
which incentivises generators to be available at these times. Moreover, the generators 
have  to  declare  themselves  available  to  be  called-upon  by  the  TSO  in  real-time  and 
performance penalties apply if they do not comply with instructions from the TSO.  

3.3 

Conclusions 

(199)  35 mechanisms have been identified in the eleven Member States under assessment – 
including  past,  existing,  abandoned  and  planned  mechanisms.  Three  Member  States 
have used tenders for new capacity, and six examples of strategic reserves were found. 
Four  countries  have  used  targeted  capacity  payment  schemes,  but  the  inquiry  found 
nine  examples  of  this  model  because  Spain  and  Portugal  operate  more  than  one 
different scheme of the same type. Two Member States are developing central buyer 
mechanisms similar to those already operating in the United States and UK. Only one 
Member State is developing a de-central obligation mechanism, and there is only one 
example of a market wide capacity payment mechanism.  

(200)  There  seems  to  be  a  trend  away  from  price-based  towards  volume-based  schemes. 
There is only one proposed capacity payment scheme; all schemes currently proposed 
or in development are volume-based.  

(201)  The  following  Chapters  will  describe  and  assess  specific  features  of  the  identified 
schemes in more detail in order to learn lessons from the design and operation of the 
various capacity mechanisms identified.  

67 

 
 
 
 
4. 

ADEQUACY ASSESSMENTS AND RELIABILITY STANDARDS 

4.1 

Introduction 

(203)  A necessary starting point in the process of determining whether or not to implement a 
capacity mechanism is to make an assessment of the generation adequacy90 situation 
and  how  it  is  expected  to  develop  in  the  future.  Based  on  the  outcomes  of  such 
adequacy  assessment  Member  States  can  establish  whether  and  how  much 
intervention  is  necessary,  for  instance  by  comparing  the  outcome  of  the  adequacy 
assessment  to  a  pre-determined  ‘reliability  standard’  that  sets  a  level  of  security  of 
supply that is deemed appropriate.  

(204)  In  the  context  of  the  sector  inquiry  the  Commission  has  asked  public  bodies  and 
market participants whether and how they have carried out adequacy assessments and 
how  the  assessments  relate  to  reliability  standards  –  where  these  are  in  place  –  and 
how they have influenced the choice and the design of the existing or future capacity 
mechanisms.  Respondents  were  also  asked  for  information  on  past  reliability 
problems and their expectations for the future. 

(205)  As  adequacy  assessments  and  reliability  standards  are  used  to  define  the  potential 
generation  adequacy  problem,  they  are  also  a  necessary  basis  for  the  analysis  in  the 
subsequent  chapters,  namely,  whether  market  or  regulatory  failures  have  been 
correctly  identified,  whether  alternative  and/or  complementary  measures  have  been 
considered and put in place, and whether the remedies that have been introduced have 
been appropriate to address the identified problem. 

4.2 

Findings of the sector inquiry 

4.2.1

  Reliability incidents are rare 

(206)  The sector inquiry asked public bodies whether reliability issues had occurred in the 
past  in  their  Member  State  or  are  expected  to  occur  in  the  future.  The  respondents 
indicate that unmet demand due to generation inadequacy has been extremely rare in 
the past five years.  

(207)  In  nine  out  of  ten  Member  States,  no  such  problems  have  occurred  at  all.  The  only 
exception was Poland, where a large amount of forced plant outages coincided with a 
heat  wave  in  August  2015.91  These  findings  were  confirmed  by  Member  State 

90   Throughout the Report the term ‘generation adequacy’ refers to the ability of the totality of generating units to meet the 
demand at all times. It is distinct from the wider ‘system adequacy’ which relates to the ability of the entire system, i.e. 
including notably the transmission and the distribution grid, to meet demand at all times. 
In the interim report, the Commission had found that in Italy generation adequacy issues had arisen on the islands of 
Sardinia  and  Sicily  which  are  not  well  connected  to  the  grid  on  the  mainland.  However,  the  Italian  authorities  have 
made it clear that these issues are to be regarded as network related, rather than generation adequacy related.  

91  

68 

 
 
                                                 
responses  to  targeted  questions  from  the  Commission.  Of  the  Member  States  that 
calculate a loss of load expectation – a group to which Poland and Italy do not belong 
– none had experienced an actual generation induced loss of load event in the past five 
years. 

(208)  This in turn confirms observations made in the Commission's 2014 Energy Prices and 
Costs report which concluded that Europe outperforms all other regions in the world 
when  it  comes  to  reliability  of  supplies.92  It  also  confirms  one  of  the  conclusions in 
Chapter 2 that the general increase in capacity and in particular in RES, has resulted in 
a situation in which the difference between peak demand and supply has widened and 
capacity margins – that is, the simple difference between installed capacity and peak 
demand – have increased.  

Table 4: The necessity of capacity mechanisms and actual reliability problems 

Source: European Commission based on replies to sector inquiry93 94 

4.2.2

  More adequacy problems are expected in the future 

(209)  Although most Member States do not experience reliability issues at present, Table 4 
also  demonstrates  that  a  clear  majority  of  public  bodies  indicate  that  they  are  of  the 
opinion that reliability problems are expected to arise in the coming five years. Only 
in  two  out  of  ten  Member  States  the  expectation  is  that  no  reliability  problems  will 
occur  in  the  medium  term,  but  these  Member  States  expect  their  overcapacity  to 
reduce in  the  longer term even  though  they currently display a  comfortable capacity 
margin. 

92   Commission Staff Working Document, SWD(2014)20 of 22 January 2014:  
http://eur-lex.europa.eu/resource.html?uri=cellar:ba385885-8433-11e3-9b7d-
01aa75ed71a1.0001.01/DOC_3&format=PDF.  
93   Croatia did not provide information on these questions.  
94  

Please note that compared to the Interim Report, two changes were made to this graph. i) the second column on Italy 
has  been  updated  to  reflect  the  fact  that  the  reliability  problems  on  the  islands  Sardinia  and  Sicily  were  grid  related 
rather than generation adequacy related. ii) the second and third column on Poland: the second to 'Yes' because of the 
reliability issues that  occurred  in  summer  2015,  and  the  third  to  'Yes'  in  view of  recent  information  provided  by  the 
Polish Electricity Association. The Polish Electricity Association points out that both ENTSO-E and the Polish TSO do 
expect Adequacy problems in Poland. The fact that Poland now envisages the introduction of a central buyer capacity 
mechanism indeed suggests that adequacy concerns exist. 

69 

 
 
 
                                                 
 
(210)  As  discussed  in  Chapter  2,  a  number  of  market  developments  and  failures  have 
contributed  to  the  increased  uncertainty  about  future  generation  adequacy.  Public 
bodies  have  expressed  two  key  concerns.  Firstly,  the  expected  closure  of  existing 
plants – mentioned by public bodies from Belgium, France, Poland and Spain – and, 
secondly,  the  inability  of  the  future  generation  mix  to  cover  peak  demand,  as 
underlined  by  public  bodies  from  Belgium,  France,  Ireland,  Italy,  Poland,  Portugal, 
Spain and Sweden.  

(211)  In  a  majority  of  cases,  these  concerns  originate  from  the  'missing  money'  problem 
referred to in Chapter 2: particularly as the shares of intermittent renewables increase 
and  the  profitability  of  conventional  power  plants  declines  the  underlying  question 
arises  whether  sufficient  flexible  back-up  capacity  will  be  available  when  demand 
peaks but renewables cannot produce.  

(212)  The underlying reasons stated by Member States for the occurrence of missing money 
in  their  local  markets  appear  to  be  different.  In  Germany  for  instance,  the  rapid 
increase  of  renewables  combined  with  the  phasing  out  of  nuclear  power  plants  and 
difficulties  in  expanding  the  grid  have  led  to  local  adequacy  issues,  which  may  be 
alleviated  in  the  long  run  when  additional  transmission  lines  are  built.  As  a  result, 
Germany  has  introduced  a  measure  that  prevents  power  plants  in  the  South  from 
closing, the network reserve.  

(213)  In Poland, the concerns addressed by the Polish cold contingency reserve are not of a 
locational, but rather of a temporal nature: increased emission standards will force a 
number  of  old  and  polluting  coal  power  plants  out  of  the  market,  but  already 
committed, new generation units may not be operational before the old ones will have 
closed. Poland therefore anticipates its contingency reserve to be transitory. However, 
the  fact  that  Poland  now  envisages  the  introduction  of  a  central  buyer  capacity 
mechanism, may suggest that it now has longer term adequacy concerns. 

(214)  Ireland and Italy set-up their tender and capacity payment mechanisms respectively in 
direct  response  to  acute  adequacy  concerns  that  occurred  in  2003.  Similarly,  in 
Belgium the lower profitability of (ageing) thermal plants was expected to lead to the 
closure  of  power  plants  and  caused  the  Member  State  to  implement  its  strategic 
reserve in 2014. 

(215)  Identifying the underlying causes properly can help targeting the need, type and size 
of  a  capacity  mechanism,  but  even  where  a  solution  responds  to  the  identified 
problem,  it  is  important  that  it  is  proportionate,  that  alternative  solutions  have  been 
assessed  properly  and  that  it  is  not  distortive  for  instance  by  harming  market 
functioning or increasing market power.  

70 

 
 
4.2.3

  Member States carry out increasingly advanced adequacy assessments  

(216)  To  substantiate  their  concerns  about  the  future  generation  adequacy,  respondents  to 
the  sector  inquiry  often  refer  to  the  assessments  carried  out  for  their  Member  State, 
usually by their TSO.  

(217)  The generation adequacy assessment needs to take into account that both demand and 
supply vary considerably during the day, during the year and over the years. They are 
dependent  on  a  wide  array  of  variables.  Moreover,  in  liberalised  markets  without 
central  planning,  the  decision  on  whether  to  invest  in  or  divest  generation  units  and 
whether to produce or not is in the hands of market participants and – for reasons of 
business  confidentiality  –  there is  often  very  limited  information  available  about  the 
commercial plans of individual operators. Various respondents to the interim report of 
the present inquiry suggested that one approach to this challenge could be to include 
an economic assessment of the expected profitability of the generators in the market. 
Even if the decision to remain active, mothball or close down remains in the hands of 
the operator, such economic assessment, which could look at elements such as plant 
efficiency, generation technology and the projected development of fuel prices, would 
provide an indication of the continued profitability of each plant that could be taken 
into account in assessing the overall generation fleet expected to be available in future. 
It  appears  from  these  responses  that  this  element  is  thus  far  not  taken  into  account 
anywhere in Europe, but its introduction foreseen in any of the ongoing modernisation 
and harmonisation efforts as described in the conclusion of this Chapter.  

(218)  An  additional  challenge  is  that  adequacy  assessments,  in  order  to  provide  useful 
information in time to devise and implement appropriate remedies, need to be able to 
look far ahead, e.g. five to ten years, which significantly increases uncertainty. 

(219)  All Member States that are part of the sector inquiry measure the security of supply 
situation  in  their  country  by  carrying  out  an  adequacy  assessment  in  which  one  or 
more  methodologies  are  applied  that  give  an  indication  of  the  potential  of  the 
generation  fleet  to  meet  demand  in  the  system  at  all  times  and  under  varying 
scenarios. Moreover, in all Member States the TSO is the main responsible body for 
carrying out the calculations. In a minority of countries this is followed by either the 
government  or  the  national  regulatory  authority  ('NRA')  scrutinising  the  TSO's  data 
and publishing a monitoring report. 

71 

 
 
Table 5: Member State practice in carrying out adequacy assessments 

Source:  European  Commission  based  on  replies  to  sector  inquiry95,  see  Box  1  for  a  description  of 
capacity margins, LOLP, LOLE, and EENS 

(220)  With  an  increasing  proportion  of  variable  renewable  resources,  electricity  systems 
have  become  more  complex.  To  address  this  increased  complexity,  a  majority  of 
Member  States  have  replaced  relatively  simple,  ‘deterministic’  assessment  metrics  – 
which  simply  compare  the  sum  of  all  nameplate  generation capacities  with the  peak 
demand in a single one-off moment – by more complex ‘probabilistic’ models, which 
are  able  to  take  into  account  a  wide  range  of  variables  and  their  behaviour  under 
multiple scenarios. This includes not only state of the art weather forecasts, but also 
factors  in  less  predictable  capacity  sources  such  as  the  contribution  from  demand 
response, interconnectors or renewable energy sources. 

(221)  Such  advanced  adequacy  assessments  provide  signals  to  market  participants,  TSOs, 
regulators,  consumers  and  policy  makers  on  the  most  probable  development  of  the 
adequacy situation. On this basis, parties active in the electricity sector can choose to 
invest or divest and to produce or consume more or less electricity. Box 1 briefly sets 
out the various methods and their advantages and disadvantages. 

Box  1  Methodologies  to  assess  generation  adequacy:  from  deterministic  to  probabilistic 
models 

Today, a variety of adequacy assessment methodologies are applied across Europe. One of the 
simplest measures to determine the level of generation adequacy is the  capacity margin. This 
'deterministic'  methodology  simply  expresses  the  relation  between  peak  demand  in  the 
electricity  system  and  the  reliably  available  supply,  usually  as  a  percentage.  For  instance,  a 
system  with  11  GW  of  installed  capacity  and  10  GW  of  peak  demand  has  a  10%  capacity 
margin.  In  two  of  the  eleven  Member  States  only  this  relatively  simple  capacity  margin  is 
calculated.  

95 

Croatia did not provide information on these questions. 

72 

 
 
 
                                                 
However, deducing the likelihood of generation related adequacy problems from these simple 
metrics  is  not  possible  with  a  high  level  of  accuracy/confidence  for  the  following  reasons.  A 
simple  capacity  margin  calculation  does  not  give  a  reliable  impression  of  the  adequacy 
situation  due  to  the  increase  in  variable  renewables,  as  shown  in  Chapter  2.  No  form  of 
generation can always output its full nameplate capacity with 100% reliability. The intermittent 
nature of solar and wind generation means that these sources in particular cannot always be 
assumed to be available and contribute at nameplate capacity during periods of high demand. 
The  practice  of  assigning  an  expected  average  contribution  to  various  sources  of  input  is 
referred to with the term de-rating.  

Measuring  capacity  margins  by  comparing  peak  demand  and  de-rated  total  supply  can 
therefore  improve  the  accuracy  of  the  capacity  margin  a  measure  of  generation  adequacy. 
However,  although  a  deterministic  model  can  determine  an  average  contribution  that  can  be 
safely  expected  to  be  received  from  the  various  sources,  it  cannot  do  this  as  accurately  as  a 
probabilistic  model.  Furthermore,  a  simple  deterministic  method  can  conceal  internal  grid 
bottlenecks. For instance, in Germany the overall amount of generation is expected to remain 
positive compared to its overall demand for at least the coming five years, but nevertheless a 
network reserve has been in place and regularly used in the South of Germany since 2012 to 
cope  with  network  constraints  within  Germany  by  enabling  re-dispatch  capabilities  for  the 
TSOs in the southern regions.  

A  more  sophisticated  method  to  measure  generation  adequacy  is  the  calculation  of  a  loss  of 
load  probability  (LOLP),  which  quantifies  the  probability  of  a  given  level  of  unmet  demand 
over  a  certain  period  of  time.  Figure  23  above  shows  that  around  half  of  the  Member  States 
carry out a LOLP calculation. Often, LOLP is expressed as a loss of load expectation (LOLE) 
which  sets  out  the  expected  number  of  hours  or  days  in  a  year  during  which  some  customer 
disconnection is expected. (for example, if 1 day in 10 years some customers would need to be 
disconnected, LOLE would be 0.1 days or 2.4 hours). This probabilistic approach can take into 
account variations in demand over the years as a result of climate fluctuations. 

LOLP/LOLE do not measure the total shortfall in capacity that occurs at the time when there 
are  disconnections,  and  neither  LOLP/LOLE  nor  capacity  margins  measure  the  amount  of 
unmet  demand.  This  would  require  a  measurement  of  expected  energy  not  served  (EENS) 
which  would  be  expressed  in  MWh  over  a  specific  time  period  (e.g.  a  year).  EENS  thus  also 
makes it possible to monetize the shortfall in a system where VOLL96 has also been calculated 
(see below) since the amount of EENS can then be multiplied by VOLL.  

4.2.4

  Member State practice in setting reliability standards 

(222)  Adequacy  assessments  contribute  to  an  informed  decision  about  the  necessity  of 
capacity  mechanisms  in  the  market.  If  a  capacity  mechanism  is  introduced,  a 
transparent  reliability  standard  is  needed  to  determine  the  appropriate  size  of  the 

96  

For a more detailed explanation of VOLL, see paragraph 2.2.2.1 

73 

 
 
                                                 
mechanism.  A  reliability  standard  expresses  a  trade-off  between  cost  and  reliability 
and  determines  which  long-term  level  of  security  of  supply  is  deemed  appropriate. 
Although  it  is  easy  to  argue  that  a  system  must  be  100%  reliable,  achieving  100% 
reliability  would  entail  extremely  high  costs  and  in  fact  would  be  technically 
impossible. 

(223)  As  Table  6  demonstrates,  a  majority  of  the  Member  States  included  in  the  sector 
inquiry make use of a reliability standard to identify the appropriate level of security 
of electricity supply in their territory.  

(224)  In Member States that calculate a LOLE in the context of their adequacy assessment, 
the standard is sometimes expressed as a tolerated number of hours in which there is 
some (unquantified amount of) loss of load. Targets generally range from 3 to 8 hours. 
In  Member  States  that  only  calculate  a  capacity  margin,  the  reliability  standard  or 
target is expressed in terms of a capacity margin percentage. Comparing the outcome 
of the adequacy assessment with the standard provides an indication as to potentially 
missing  capacity  and  hence  the  need  for  and  size  of  a  capacity  mechanism.  Once  a 
capacity  mechanism  is  introduced,  the  reliability  standard  is  also  required  as  a 
reference point for identifying the amount of capacity to procure through the capacity 
mechanism (or, in a price-based mechanism, the price to set).  

Table 6: Member State practice in setting a reliability standard  

Source: European Commission based on replies to sector inquiry979899 

97   The Belgian LOLE (P95) refers to a 95th percentile standard according to which during severe conditions of which the 

chance is 5% (i.e. a very cold winter that occurs once in 20 years) the LOLE must be inferior to 20 hours.  

74 

 
 
 
                                                 
(225)  Responses to the Commission's second questionnaire provide further insight into the 

relation between LOLE calculations and reliability standards.  

(226)  None  of  the  six  Member  States  that  established  a  LOLE  reliability  standard  have 
experienced  any  LOLE  events  in  the  past  five  years.  However,  only  Ireland  and 
Portugal responded affirmatively to the question whether the absence of any lost load 
in  practice  suggested  that  their  standards  were  routinely  exceeded.  France  and 
Belgium said that five years' absence of loss of load does not mean that the standard is 
routinely  exceeded,  given  that  the  standard  is  based  on  probabilistic  methods  taking 
into account a large amount of possible situations. 

(227)  In  Ireland,  a  revision  procedure  was  carried  out,  but  it  was  decided  that  the  current 
level should be maintained. In Portugal, the public bodies indicated that although an 
evaluation  takes  place,  but  a  revision  of  the  standard  is  not  foreseen.  The  Danish 
public  bodies  instead  indicated  that  the  methodology  of  determining  their  standard 
will change from being based on historic data to a 'politically determined' standard.  

(228)  To  determine  their  reliability  standard,  a  number  of  Member  States  make  use  of  a 
calculation of VOLL. Where a Member State calculates VOLL, it estimates the value 
an average consumer places on secure electricity supplies at any point in time. In other 
words,  it  is  the  price  point  at  which  the  consumer  is  indifferent  between  paying  for 
electricity and being cut off. By using it to determine a reliability standard, it goes one 
step further and de facto determines that protection by way of a capacity mechanism 
should  not  go  beyond  the  level  of  protection  that  would  be  achieved  through  a 
perfectly  functioning  free  market  for  electricity.  The  higher  the  degree  of  protection 
desired, the more (back-up) capacity is needed and therefore the higher the price tag 
attached  to  it.  In  order  to  determine  the  cost  of  additional  protection  against 
disconnections  through  additional  capacity  investment,  some  countries  calculate  the 
cost of new investment by estimating the cost of a 'Best New Entrant (BNE)' or 'Cost 
of New Entry (CONE)'. The estimate is usually based on the costs of a new peaking 
plant  (since  this  represents  a  cheaper  way  of  providing  marginal  capacity  than  a 
baseload  plant).  A  comparison  of  VOLL  and  BNE/CONE  can  identify  the  point  at 
which the value for consumers of investment in additional capacity is maximised – at 

Croatia did not provide information on these questions. 

98 
99   The German capacity reserve is triggered when the day-ahead or intraday market do not clear and all other instruments 
have  been  exhausted.  The  market  not  clearing  means  in  practice  that  offers  at  the  maximum  bid  price  (3,000  and 
10,000) remain unmatched in the day-ahead and intraday market respectively. Balancing responsible parties pay 20,000 
Euro/MWh after deployment of the reserve, if they contributed to the shortage in the system and therefore the need to 
deploy the capacity reserve. 

75 

 
 
                                                                                                                                                         
the  point  at  which  the  incremental  cost  of  insuring  customers  against  power  cuts  is 
equal to the incremental cost to customers of power cuts.100  

(229)  Linking  the  reliability  standard  to  the  level  of  capacity  that  reflects  the  maximum 
value  consumers  place  on  being  supplied  with  electricity,  means  that  an  economic 
efficient  level  of  protection  is  set  and  that  expensive  overprotection  is  avoided. 
Therefore,  a  reliability  standard  based  on  VOLL  and  BNE/CONE  constitutes  in 
principle  the  efficient  target  guiding  any  intervention  in  the  market  with  the  aim  of 
ensuring optimal security of supply.  

(230)  Less  than  half  of  the  countries  calculate  VOLL  and  use  it  as  their  basis  for 
determining their reliability standard.101 A possible reason that not all Member States 
make use of a VOLL to ensure an economically sensible level of protection may be 
that it is difficult to calculate an appropriate average VOLL. Electricity has a different 
value  for  different  users  and  differs  over  time.  An  additional  complexity,  as 
underlined  in  Chapter  2,  is  that  most  electricity  consumers  are  currently  not  able  to 
individually  express  their  valuation  of  electricity  for  every  time  slot.  VOLL 
calculations 
true  (but  unknown)  value  of 
disconnection  with  an  administrative  average  value.  The  average  VOLL  in  each 
Member  State  or  bidding  zone  is  also  likely  to  be  different,  reflecting  the  different 
cost of a MWh of unserved energy to different types of consumers and/or consumers 
in  different  parts  of  Europe.  However,  although  calculating  VOLL  is  challenging, 
seven countries in the inquiry have made an estimate of VOLL (see Section 2.2.2.1), 
and no consultation or questionnaire respondents have justified an alternative way to 
calculate an appropriate reliability standard. 

therefore  attempt 

to  replace 

the 

(231)  Moreover,  a  majority  of  the  countries  that  have  established  a  reliability  standard  do 
not link the capacity demanded through their capacity mechanism to the achievement 
of  this  standard.  This  means  that  the  reliability  standard  does  not  fulfil  its  main 
function, namely to ensure an appropriate level of capacity. For instance, respondents 

101  

100   One  of  the  countries  in  the  sector  inquiry  considering  such  approach  is  Ireland.  It  has  provided  a  more  thorough 
discussion  on  this  topic  in  its  consultation  paper  on  the  detailed  design  of  its  envisaged  capacity  mechanism: 
https://www.semcommittee.com/publications/topics/19  
In  Italy  a  different  approach  to  VOLL,  reliability  standards  and  the  determination  of  the  amount  of  capacity  to  be 
remunerated in its planned capacity mechanisms is applied. The Italian planned capacity mechanism makes the targeted 
reliability  standard  dependent  on  the  demand  and  supply  in  the  capacity  market.  The  demand  curve  is  estimated 
through a probabilistic approach which embeds the probabilistic generation adequacy assessment, but does not make 
explicit a targeted reliability standard. In the Italian proposal, the reliability standard depends on how much will it cost 
to achieve a certain level of reliability and on how much consumers are willing to pay for it. Hence, the lower the bids 
in the auction, the more capacity will be contracted; and the higher the VOLL of consumers, the more capacity will be 
contracted. This approach reflects the idea that the cheaper additional security of supply, the more consumers will be 
ready to pay for it. The capacity mechanism in Great Britain and the planned mechanism in Ireland incorporate this idea 
by way of a sloping demand curve (though in GB and Ireland a long term reliability standard is also set based on the 
expected cost of capacity). 

76 

 
 
                                                 
to the sector inquiry argued that the amount of capacity to be procured in the Belgian 
strategic reserve and in the interruptibility scheme in Spain was overestimated.  

(232)  The sector inquiry also provides evidence that some Member States fail to scale down 
their capacity requirements on the basis of a comparison between the standard and the 
outcome  of  the  adequacy  assessment.  For  instance,  Spain  applies  a  10%  capacity 
margin  as  its  reliability  standard.  The  current  situation  demonstrates  there  is  43% 
capacity  margin.  Instead  of  limiting  the  capacity  measure  to  the  achievement  of  the 
applicable standard, Spain has continued to pay capacity payments.  

4.3 

Assessment 

4.3.1

  The absence of a common approach in assessing adequacy 

(233)  The increased concerns of Member States about future generation adequacy have led 
to the development and application of more sophisticated and more reliable adequacy 
assessments. However, the fact that an increasing number of countries apply a similar 
methodology,  based  on  an  hourly  LOLE,  does  not  mean  the  outcomes  can  now  be 
compared easily with one another. In fact, the assumptions used by Member States to 
calculate  their  LOLE  vary  widely  and  are  not  clearly  communicated.  This  has  a 
number of potential negative effects: it decreases transparency on the actual level of 
protection sought, it reduces the potential for using cross-border data to inform local 
assessments  and  it  may  lead  to  inappropriately  sized  capacity  mechanisms.  Since 
assumptions and scenarios chosen in the individual assessment (e.g. “one in 20 year” 
vs “one in 50 year” winter peak, or how imports are taken into account in a national 
adequacy  assessment)  can  have  an  important  impact  on  the  outcome  of  the 
assessment, it is important to make the assessment as transparent and comparable as 
possible.  

(234)  The absence of a common approach means that no comparison between the Member 
States can be made as to their relative generation adequacy without fully exploring the 
individual methodologies used. As a result, Member States cannot simply rely on the 
assessment of a neighbouring country and use that as input to their own assessment. 
As  such,  the  potentially  important  contribution  of  interconnectors  may  not  be  fully 
taken into account. The diverging approaches of Member States  become apparent in 
defining what constitutes a LOLE-event and in the approach to de-rating the various 
elements in the generation mix.  

(235)  In the interim report, the Commission concluded that there is no common definition of 
what qualifies as a 'reliability event' and thus contributes to LOLE-hours. As a result, 

77 

 
 
it  is  not  clear  to  what  extent  interventions  by  the  TSO  to  prevent  brownouts102  or 
blackouts  –  such  as  issuing  generation  maximisation  instructions,  using  ancillary 
services to fill a supply gap, or implementing voltage reductions – qualify as LOLE-
events. A 2012 report on the Texan electricity market provides an interesting example 
of  how  the  application  of  a  LOLE  standard  can  cause  confusion.103  The  market 
operator  ERCOT  explains  that  its  legal  '1-day-in-10-years'  LOLE  standard  has  in 
Texas traditionally been interpreted as '1-outage-event-in-10-years' and not as a total 
of 24 hours during which there is lost load every ten years. It is however aware that 
other market areas of the US, such as in its northern neighbouring market SPP, use the 
latter  interpretation,  and  that  again  other  market  operators  do  not  use  the  1-in-10 
standard  at  all  in  determining  their  target  reserve  margins.  It  furthermore  notes  that 
although  there  is  consensus  in  Texas  about  the  interpretation  of  allowing  not  more 
than  one  LOLE-event  in  ten  years,  there  is  no  definition  as  to  what  constitutes  an 
'event',  which  means  that  all  events  carry  the  same  weight,  irrespective  of  their 
seriousness,  for  the  purpose  of  calculating  the  standard.  Obviously,  the  size  and 
duration  of  an  event  clearly  influence  how  much  consumers  are  affected  by  it.  The 
report remarks that the EENS standard does not have this weakness as it expresses the 
standard in the amount (in MWh) of the non-served energy. 

(236)  Where the question of definition and determination of LOLE has not been answered 
with  sufficient  clarity,  the  ensuing  uncertainty  not  only  makes  comparability  of  the 
level  of  generation  adequacy  across  borders  problematic,  it  also  creates  a  large 
discretion  for  TSOs  to  determine  the  volume  of  the  additional  safety  margins  they 
believe  are  needed  in  a  way  that  may  initially  appear  to  be  based  on  VOLL  and 
therefore consumers' willingness to pay but which in practice targets a far higher level 
of reliability.  

(237)  There  is  a  risk  related  to  leaving  large  margins  of  discretion  to  the  TSO,  because 
depending  on  its  responsibilities  and  regulation,  it  may  have  an  incentive  to 
overprotect.  A  transparent  approach  is  therefore  important  to  objectivise  risk 
perception.  There  is  great  consensus  among  both  public  bodies  and  market 
participants  responding  to  the  sector  inquiry  questionnaires  that  a  more  harmonised 
approach to determining generation adequacy is necessary. 

102   A brownout is less serious than a blackout in the sense that it is merely a short voltage reduction and not a complete 
loss  of  power.  Brownouts  can  be  intentionally  used  by  network  operators  to  temporarily  accommodate  increased 
demand.  Brownouts  can  however  damage  special  equipment  used  in  industrial  processes  that  require  stable  power 
flows. 

103   The Brattle Group, “ERCOT Investment Incentives and Resource Adequacy, Report to the Public Utility Commission 

of Texas, of 1 June 2012, page 101. Available at: 
http://www.ercot.com/content/gridinfo/resource/2015/mktanalysis/Brattle_ERCOT_Resource_Adequacy_Review_201
2-06-01.pdf.  

78 

 
 
                                                 
 
(238)  Following the publication of the interim report of this sector inquiry, the Commission 
has  asked  additional  information  as  to  how  Member  States  that  calculate  LOLE 
determine  which  events  contribute  to  LOLE  hours  and  the  response  has  been 
consistent: events count as LOLE events only when there is lost load that is caused by 
the  inadequacy  of  generation  units  in  the  market,  i.e.  the  insufficient  availability  of 
supply to meet demand. TSO interventions to stabilise the grid and ensure security of 
supply,  such  as  by  using  ancillary  services  or  balancing  reserves  do  not  generally 
count as LOLE events.  

Box 2: Putting LOLE in perspective 

Reliability  standards  are  generally  established  to  represent  a  long  term  average  target.  In 
practice however there may be no unmet demand in some years and a much higher level that 
the reliability standard in others. The 3 hours on average per year LOLE standard in France 
for  instance  is  derived  from  a  calculation  that  predicts  a  30  hour  disruption  every  ten  years 
when there is for example a particularly severe winter and high demand for electric heating.  

The standards can also appear alarming. The standard of an average of 8 hours in which there 
is  some  loss  of  load  each  year  in  Ireland  for  example  sounds  alarming  if  'black  outs'  are 
expected for 8 hours each year. It is important to realise that LOLE hours should not be viewed 
as hours in which a major blackout takes place leaving entire market areas without power, but 
may  be  solved  by  TSOs  without  major  impacts,  i.e.  by  using  instruments  such  as  temporary 
voltage  reductions  or  the  selective  disconnection  of  large  industrial  users.  When  not  seen  in 
perspective,  a  Loss  of  Load  Expectation  may  give  the  wrong  impression  that  blackouts  are 
expected. And even the 8-hour per year standard in Ireland – which on the face of it is the most 
relaxed  standard employed in  Europe  – translates  into  a system security  level of  99.9%  - i.e. 
99.9% of the time no one will be involuntarily disconnected. 

Indeed, for most Member States network failures, for example after weather events that damage 
network  infrastructure,  have  historically  led  to  far  more  involuntary  unmet  demand  than 
generation inadequacy104.  

(239)  The  absence  of  a  common  approach  also  becomes  apparent  with  regard  to  the  de-
rating105  of  capacity  (most  importantly  for  renewables  and  imports),  which  further 
complicates  cross-border  comparison  and  objective  insight  into  the  actual  adequacy 
situation in a country or bidding zone. There may be good reasons that contributions 
of  such  sources  differ  per  country,  but  a  common  approach  on  the  underlying 
principles  would  create  an  objective  basis  for  cross-border  comparison.  A  large 
number  of  market  participants  that  have  responded  to  the  public  consultation 

104  

In 2014 ENTSO-E identified over 1000 security of supply incidents. Most of these were minor  but there were some 
more serious disturbances, for example storms on 12 February 2014 leaving 250,000 homes in Ireland without power. 
See https://www.entsoe.eu/Documents/SOC%20documents/Incident_Classification_Scale/151221_ENTSO-
E_ICS_Annual_Report_2014.pdf.  
105   See Box 1 for a description of de-rating. 

79 

 
 
                                                 
following the publication of the interim report subscribe to this conclusion and express 
their wish for more clarity in the calculation of LOLE hours and their translation into 
reliability standards, in order to objectivise their authorities' interventions in the form 
of capacity mechanisms. 

4.3.2

  Reliability standards are not used to ensure appropriate intervention 

(240)  Ideally, comparing the outcomes of an adequacy assessment with the desired level of 
protection  laid  down  in  a  reliability  standard  that  takes  into  account  the  average 
consumer's willingness to pay for security of supply provides an objective indication 
as  to  whether  or  not  intervention  in  the  market  to  foster  generation  adequacy  is 
necessary and to what extent. At present, this is however not common practice.  

(241)  Some  Member  States  do  not  have  reliability  standards  and  Member  States  that  do 
apply them  often do not explicitly  link them to  the type and extent  of their  capacity 
mechanism.  Moreover,  a  majority  of  countries  does  not  calculate  a  VOLL  for  their 
market, nor use it in setting a market price cap or a reliability standard. 

(242)  This results in a situation in which the necessity and the size of a capacity mechanism 
are not always based on a proper economic assessment. As a consequence, there is a 
risk  that  interventions  in  the  market  become  subjective  and  hence  sub-optimal. 
Objectivising the need for and degree of interventions can be done by adopting a well-
defined VOLL as a key indicator in determining an appropriately maximum level of 
protection. 

4.4 

Conclusions 

(243)  Despite  the  absence  of  reliability  issues,  Member  States  are  concerned  about  future 
generation  adequacy  for  a  variety  of  reasons,  mostly  linked  in  some  way  to  the 
missing  money  problem.  A  thorough  problem  identification  can  help  tailoring  an 
intervention  in  the  electricity  market  to  solve  the  precise  problem  and  adequacy 
assessments  can  help  quantifying  the  extent  of  the  adequacy  problems.  By  using 
different scenarios in a transparent and comparable manner, adequacy assessments can 
help  demonstrate  whether  an  identified  problem  is  of  a  transitional  nature.  A 
reliability  standard  can  ensure  that  intervention  takes  place  up  to  a  level  consumers 
would wish to pay for. 

(244)  However,  practice  demonstrates  that  whilst  increased  concerns  about  generation 
adequacy have been accompanied by the development of better adequacy assessments, 
the  proper  follow-up  to  those  assessments  does  not  take  place,  mostly  because 
reliability standards are not always based on sound economic assessment. As a result, 
regulatory decisions on capacity markets are not sufficiently evidence-based and most 
capacity mechanisms are not tailor-made to secure the capacity shortfall identified by 
an adequacy assessment compared against a reliability standard based on VOLL.  

80 

 
 
(245)  Demonstrating necessity of intervention is a prerequisite for any capacity mechanism 
to be accepted under State aid rules. A more harmonised and transparent approach to 
adequacy assessments and VOLL can contribute to objectivising the need for and size 
of interventions.  

(246)  Several harmonisation efforts are already ongoing at European level. The TSOs of the 
Pentalateral  Energy  Forum106  have  carried  out  a  common  adequacy  assessment  at 
regional  level  using  a  probabilistic approach  with  an  hourly  resolution.  It  includes  a 
common  approach  to  de-rating  RES  based  on  historic  climate  data,  and  to  the  de-
rating of interconnection capacity. 

(247)  Also  ENTSO-E  publishes  a  Europe-wide  yearly  system  outlook  and  long  term 
adequacy  forecast  (SO&AF)  on  the  basis  of  Article  8  of  the  Electricity  Regulation 
(EC) No 714/2009. ENTSO-E develops and improves its methodology regularly and 
has  established  a  Target  Methodology  that  will  include  the  use  of  a  probabilistic 
method,  an  extensive  range  of  indicators  and  state  of  the  art  RES  and  climate 
simulations.  The  first  SO&AF  under  the  updated  methodology  will  be  published  in 
2016. 

(248)  As regional and European-wide methodologies mature and become more reliable, they 
should  increasingly  be  used  as  a  basis  for  assessing  the  necessity  of  introducing 
capacity mechanisms. Respondents to the public consultation support this conclusion 
strongly,  pointing  out  that  whilst  Member  States  should  be  able  to  apply  a  national 
standard  that  differs  from  their  neighbours,  the  standards  should  be  comparable  and 
have a common methodology as their basis.  

(249)  With  its  energy  market  design  initiative,  the  Commission  intends  to  strengthen  the 
requirements related to the European and national adequacy assessments. It proposes 
an  obligation  on  Member  States  to  adopt  a  reliability  standard  that  is  based  on  the 
value of lost load and expressed as a function of LOLE or EENS. The calculation of 
these metrics should be based on a to-be developed common European methodology. 
Moreover, the Commission intends to prescribe in more detail what the Europe-wide 
framework  for  generation  adequacy  assessments  and  standards  should  contain.  For 
instance, it should take into account the economic outlook of the plants in the market, 
the regulatory barriers that persist in the market and the potential for market reforms 
to help improve the situation in the future. All these proposals should contribute to a 
more objective approach to calculating generation adequacy and therefore reduce the 
risk of non-economic over- or underprotection.  

106   Austria, Belgium, France, Germany, Luxembourg, the Netherlands, Switzerland. The full report is available here: 

www.benelux.int/download_file/view/4201/3852/  

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5. 

DESIGN FEATURES OF CAPACITY MECHANISMS 

5.1 

Introduction 

(250)  This chapter presents the findings on the design features of the capacity mechanisms 

in the 11 Member States covered by the sector inquiry. 

(251)  Once Member States have assessed their generation adequacy situation and concluded 
that there is a need for the introduction of a form of support for generation capacity, 
they  face  a  range  of  choices  to  design  a  suitable  capacity  mechanism  to  address  the 
identified  adequacy  problem.  There  are  a  number  of  considerations  to  be  made 
irrespective  of  the  type  of  capacity  mechanism.  Chapter  5  aims  to  present  the  most 
important of those design choices, which are considered in three categories: 

  Eligibility: who gets to participate in the capacity mechanism? 

  Allocation: how does the selection process among the eligible parties work and how is 

the level of capacity remuneration determined? 

  Product design: what do participants in the scheme have to do, and what happens if 

they don't do it?  

(252)  For  each  of  those  categories,  examples  from  the  capacity  mechanisms  found  in  the 
inquiry will be presented to illustrate the impact of those choices on the effectiveness 
of the mechanism. 

(253)  This final report also includes a new section on the ways in which the design choices 
in a capacity mechanism can alter the potential for the abuse of market power both in 
the capacity mechanism itself, and in the electricity market.  

5.2 

Eligibility 

5.2.1

  Eligibility criteria in capacity mechanisms 

(254)  Once  Member  States  have  identified  the  residual  market  failures  that  they  want  to 
address with a capacity mechanism, they need to decide which capacity providers can 
contribute  to  procuring  the  identified  capacity  need  and  should  be  made  eligible  to 
participate  in  the  mechanism.  Well-designed  eligibility  criteria  enable  an  optimal 
selection  of  capacity  providers  to  address  the  identified  security  of  supply  problem. 
Open criteria encourage participation of all potential sources, whereas more narrowly 
defined criteria limit the pool of potential contributors. 

(255)  This  section  analyses  the  eligibility options  available  to  policy  makers,  and  assesses 
whether there may be valid reasons for limiting a capacity mechanism to a single or 
very  few  capacity  sources.  The  eligibility  rules  can  explicitly  or  de  iure  limit 

82 

 
 
participation  to  certain  pre-determined  capacity  types,  or  set  performance  related 
criteria that have the equivalent effect by de-facto excluding of one or more types. 

5.2.2

  Findings of the sector inquiry on eligibility 

(256)  The  sector  inquiry  demonstrates  that  Member  States  design  and  target  the  eligibility 

criteria in their capacity mechanism mainly on the basis of: 

(1) Generation technologies: Member States may for different reasons selectively exclude 
specific  generation  technologies  from  a  capacity  mechanism  or  favour  others  within 
the mechanism. Indeed, the majority of capacity mechanisms covered by the present 
inquiry is de facto targeted at one or more technologies and excludes others; 

(2) Demand  response:  there  are  several  reasons  Member  States  may  want  to  foster  the 
participation of demand response. As underlined in Chapter 2, an active demand side 
could deliver  significant benefits to market functioning. And because some forms of 
demand  response  can  deliver  capacity  at  short  notice  it  is  increasingly  a  useful 
competitor in capacity mechanisms. 

(3) Storage providers: Member States furthermore need to determine whether storage can 
usefully  contribute  to  address  the  generation  adequacy  they  have  identified.  Storage 
can significantly contribute to security of supply by storing electricity when it is cheap 
and  abundant,  and  again  releasing  it,  usually  on  short  notice,  when  it  is  scarce  and 
expensive.  Storage  can  however  only  provide  that  capacity  (or  in  other  words  be 
available) for short periods of time.  

(4) New vs. existing capacity: another eligibility choice that Member States need to make 
is  whether  they  want  to  include  new  or  existing  capacity  in  their  mechanism,  or  a 
combination  of  both.  Where  Member  States  were  concerned  that  no  investments  in 
new capacity took place, they have often tended to focus on attracting new capacity, 
while  when  they  were  concerned  that  a  considerable  amount  of  existing  capacity 
would  go  offline  in  the  near  future,  they  have  often  tended  to  focus  on  keeping 
existing  plants  on  stand-by  outside of  the  market  (i.e.  they have  introduced  strategic 
reserves). 

(5) Location: in case of a geographically delimited capacity problem, Member States have 
sometimes  chosen  to  limit  participation  to  the  capacity  mechanism  to  the  capacity 
providers  in  the  zone  that  experiences  the  capacity  problem.  Additionally,  many 
Member  States  only  consider  capacities  on  their  own  territory  and  do  not  take  into 
consideration foreign capacities. 

(257)  This  section  is  divided  into  sub-sections  that  address  each  of  these  design 

considerations.  

(258)  Table 7 below provides a general overview of the types of capacity providers that are 

sought by each of the capacity mechanisms covered by the sector inquiry: 

83 

 
 
Table 7: Overview of eligible capacities (table includes existing, planned and past schemes) 

Source: European Commission based on replies to sector inquiry 

5.2.2.1

 Generation technology neutrality 

Rationale for selectivity 

(259)  A  clear  majority  of  the  existing  and  planned  capacity  mechanisms  covered  by  this 
inquiry  exclude  one  or  more  generation  technologies.  There  appear  to  be  various 
reasons why governments wish to encourage or discourage the participation of certain 
technologies. Environmental considerations for instance may inspire the exclusion of 
lignite,  coal  or  nuclear  power  plants.  Member  States  have  also  used  capacity 
mechanisms to  promote indigenous  energy sources as  a secondary objective.  This  is 
for instance the case of the investment incentive mechanism in Portugal, in which only 
hydro  power  plants  can  participate.  It  was  also  the  case  in  the  2010-2014  Spanish 
scheme in support of power plants using indigenous coal. 

84 

Member StateCapacity mechanismEligibilityBelgiumTender for new capacityCCGT and OCGTFrance Tender for new capacity in BrittanyCCGTIrelandTender for new capacityThermal generation capacityItalyTargeted capacity paymentsGeneration capacity that can participate in the ancillary services marketPoland Operational reserveCentrally dispatched generation capacityAvailability incentiveThermal generation capacityInvestment incentiveHydroAvailability serviceThermal generation (except nuclear) and hydro (with storage)Investment incentiveNuclear, gas, coal, hydro and oil entering into service before 1 January 2016Environmental incentiveCoal plantsSupport to power plants using indigeneous coalCoal plantsBelgiumStrategic reserveGeneration capacity announced for closure or mothballed and non-generation DSRMinimum demand response purchase obligation of 50MWDenmarkStrategic reserveAll types of generation capacity (existing and new), DSR and storageNetwork reserveAll types of generation capacity (incl. storage) announced for closure or mothballing but considered "system relevant". If insufficient, tender for additional capacity consisting de facto of foreign plants (incl. storage)Capacity reserveAll types of generation capacity (existing and -in future- new)PolandCold contingency reserveCentrally dispatched generation capacity entitled to a temporary derogation from IED emission standards as of 1 January 2016SwedenStrategic reserve Generation capacity and demand response. Minimum demand response purchase obligation of 25%ItalyCentral buyer reliability obligation schemeAll generation capacity (existing and new). Italy exploring to include DSR and foreign capacity as of 2017 auctionIreland Central buyer reliability obligation schemeAll types of generation capacity (existing and new), DSR and storage. In principle also open to cross border generation capacity.FranceSupplier obligationAll types of generation capacity (existing and new), DSR and storage. France is publicly consulting on possibility of direct cross border participation.IrelandMarket-wide capacity paymentsAll types of generation capacity (existing and new), DSR and storage, foreign capacity and interconnectorsGermanyInterruptibility schemeDemand response >50MWInterruptibility scheme for Sardinia and SicilyDemand response >1MWInterruptibility scheme for the mainlandDemand response >1MWIrelandInterruptibility schemeDemand response >0.1MW and not active as demand response in the marketPolandInterruptibility scheme Demand response >10MWPortugalInterruptibility scheme Demand response >4MWSpainInterruptibility schemeDemand response >5MW or >90MW (two auctions)*size requirements only given for interruptibility schemes - size requirements also apply in other schemes                                                                                          ItalyTender for new capacityReserveGermanyCentral buyerTargeted capacity paymentSpainPortugalMarket-wide capacity paymentDe-central obligationInterruptibility scheme* 
 
 
(260)  Member States may also wish to narrow participation in their capacity mechanism to 
target the type of capacity that they consider most suitable to alleviate a shortage of 
certain types of capacities or capacities with specific abilities. Where existing capacity 
for example cannot ramp up and down quickly enough to react to sudden changes in 
demand,  a  Member  State  may  wish  to  target  a  mechanism  only  to  flexible  capacity 
such  as  demand-response,  storage  or  gas-fired  generation.  The  question  is  then 
whether  such  objectives  cannot  be  better  attained  through  better  remuneration  of 
ancillary services rather than through a capacity mechanism. 

(261)  Some  capacity  mechanisms  explicitly  exclude  capacities  which  already  receive 
subsidies via other, separate support schemes. This may on the one hand be mandated 
by  rules  prohibiting  the  cumulation  of  aid.  On  the  other  hand,  full  participation  and 
fair  competition  can  only  work  if  a  level  playing  field  exists  between  potential 
capacity  providers  more  generally,  through  the  elimination  of  subsidies  other  than 
capacity payments to specific capacities. 

(262)  The  sector  inquiry  found  that  most  Member  States  support  renewable  energy  and 
combined heat-power generation in principle through separate support schemes. While 
there are in principle different objectives behind RES support schemes (which aim to 
reduce  greenhouse  gas  emissions)  and  capacity  mechanisms  (which  aim  to  ensure 
security  of  supply),  there  is  some  recognition  of  the  value  of  RES  for  security  of 
supply.  Accordingly,  more  recent  capacity  mechanisms  tend  to  allow  RES  to 
participate  (while  at  the  same  time  including  safeguards  to  avoid  cumulation  of  aid 
from  different  mechanisms).  This  is  for  instance  the  case  of  the  French  de-central 
obligation  scheme  where  RES  producers  are  awarded  certificates  (and  receive  the 
higher  of  the  income  from  the  certificates  or  the  "normal"  RES  subsidies),  and  the 
British  capacity  market  (where  RES  can  participate  provided  they  opt  out  of 
alternative support schemes). It appears that RES will also be able to participate in the 
planned Italian and Irish reliability option mechanisms. 

Openness of capacity mechanisms to different generation technologies 

(263)  To  assess  how  the  different  types  of  capacity  providers  participate  in  capacity 
mechanisms  the  following  sections  distinguish  between  the  explicit  and  implicit 
exclusion of generation technologies.  

Explicit exclusion 

(264)  Some  capacity  mechanisms  are  explicitly  technology  specific,  determining  a  single 
type of generation technology to fulfil the identified capacity need. This applies to all 
tenders  for  new  capacity:  the  tenders  in  Brittany  (CCGT)  and  Belgium  (CCGT  and 
OCGT)  targeted  only  gas-fired  power  plants;  in  Ireland  it  was  limited  to  thermal 
generation capacity.  

85 

 
 
(265)  The only capacity payment schemes explicitly open to all generation technologies are 
the Irish and Italian one.107 All the other capacity payment mechanisms covered by the 
inquiry are open to specific generation technologies. Typically, participation is limited 
to  thermal  generation,  with  the  exception  of  the  Portuguese  investment  incentive 
mechanism which is open only to hydroelectric plants. In some cases, only a subset of 
thermal plants is eligible, such as for instance in the Spanish environmental incentive 
scheme and the Spanish scheme for power plants using indigenous sources which are 
only open to coal-fired power plants.  

(266)  In contrast, none of the strategic reserves explicitly excluded certain technology types. 
As  discussed  in  the  next  section,  there  were  however  implicit  criteria  that  de  facto 
limited participation. 

(267)  The  market-wide  capacity  mechanisms  in  the  inquiry  were  usually  open  to  all 
generation  technologies.  As  already  explained  above,  they  however  differ  in  their 
treatment of RES. 

Implicit exclusion 

(268)  Eligibility  criteria  are  in  some  instances  defined  in  such  a  way  that  in  practice  only 

certain capacity providers can participate.  

(269)  A  first  category  of  requirements  that  may  lead  to  the  exclusion  of  certain  types  of 
generation  are  size  requirements.  In  the  mechanisms  covered  by  the  inquiry,  they 
range from a 0.1 MW threshold –for certification in the French de-central obligation 
scheme108– to a 450 MW threshold for participation in the tender for new capacity in 
Brittany.109  The  higher  the  threshold,  the  more  likely  it  de  facto  excludes  smaller 
generators (especially RES) and also demand response providers.  

(270)  A  second  category  relates  to  environmental  standards.  The  sector  inquiry  found  the 
example of the Spanish environmental incentive mechanism that required coal plants 
to install a sulphur dioxide filter to participate. In contrast, participation in the Polish 
cold contingency reserve is reserved for plants that enjoy a temporary derogation from 
emission  standards  under  the  industrial  emissions  Directive110  and  are  therefore  too 

107   Participation  in  the  Italian  scheme  is,  in  principle,  open  to  all  plants  admitted  to  participate  in  the  ancillary  services 
market. However, size and performance requirements for the ancillary services market lead to the implicit exclusion of 
certain generation technologies, such as renewables.  

108   Although smaller capacities can aggregate to surpass the threshold. 
109   Size requirements are for example to be found also in the Belgian tender for new capacity (400 MW for CCGTs and 40 
MW for OCGTs), the tender for new capacity in Ireland (50 MW), the Italian targeted capacity payments (10 MW), the 
Portuguese  targeted  capacity  payment  mechanisms  (30  MW),  the  Spanish  investment  incentive  capacity  payment 
mechanism (50MW) and all interruptibility schemes. 

110   Directive 2010/75/EU of the European Parliament and of the Council of 24 November 2010 on industrial emissions. 

86 

 
 
                                                 
polluting to operate in the market. The mechanism therefore in practice addresses old 
coal and lignite plants only. In the French capacity mechanism, stricter environmental 
criteria are applied but only to new projects (see sub-section 5.2.2.4 below). 

(271)  A third  category  includes  criteria that are based  on the technical performance of  the 
capacity  provider,  such  as  power  plant  efficiency,  ramp-up  time  or  the  ability  to 
provide  certain  ancillary  services.  Power  plant  efficiency  requirements  were  for 
instance set in the Belgian and French (Brittany) tenders for new capacity.111 In both 
cases,  the  Member  State  also  required  that  the  power  plants  were  able  to  provide 
certain ancillary services. As these tenders were explicitly addressed at specific types 
of newly built power plants, the efficiency and ancillary services requirements did in 
practice not exclude certain technologies but rather act as minimum standards for the 
offers.112  Participation  in  the  Italian  targeted  capacity  payment  mechanism  is  only 
open to plants that are admitted to participate in the ancillary services market. This has 
led  to  the  de  facto  exclusion  of  generation  capacity  that  cannot  be  programmed  to 
increase  or  reduce  load  as  required  for  the  performance  of  ancillary  services 
(essentially certain RES, such as wind or solar). 

(272)  Another  technical  performance  criterion  relates  to  ramp  up  times.  The  Belgian 
strategic reserve for instance requires a 6.5 hour ramp-up time for participating power 
plants  whilst  keeping  the  door  open  for  even  longer  ramp-up  times  if  these  can  be 
justified by the bidders. The planned Greek flexibility remuneration mechanism (not 
included in the sector inquiry) grants capacity payments to individual plant capable of 
increasing  electricity  generation  at  a  rate  greater  than  8  MW/min  with  three  hours' 
notice (starting from hot conditions). 

(273) 

Finally, Member States often de-rate capacities to reflect their actual value to supply 
electricity  during  scarcity  periods,  for  example  taking  into  account  average 
maintenance  needs  or  average  load  factor.  De-rating  is  common  in  market-wide 
mechanisms  including  a  large  variety  of  capacity  providers.  De-rating  is  either 
determined centrally  (as  in  the  Italian  and  British  central  buyer  mechanisms  and  the 
Spanish  availability  incentive  mechanism)  or  de-centrally  by  the  individual  capacity 
providers subject to ex-post control (as in the French de-central obligation scheme). In 
either  case,  the  capacities  will  only  participate  in  the  mechanism  to  the  de-rated 
extent. If for example a 400 MW power plant is only expected to make 60% of its full 

In the Belgian example the efficiency requirements were different for OCGTs and CCGTs.   

111  
112   However, in practice the Belgian tender attracted bids from existing foreign plants which proposed to disconnect from 
their Member State's grid in order to connect to the Belgian grid and become part of the Belgian TSO's balancing zone 
(thereby increasing the amount of capacity available to Belgium). To the extent the minimum power plant efficiency 
requirement or requirement to be able to perform ancillary services had the effect of limiting such foreign offers, they 
in fact acted as implicit eligibility factors. 

87 

 
 
                                                 
installed  capacity  available  on  average,  it  will  be  able  to  participate  in  the  capacity 
mechanism only with up to 240 MW).113 

(274)  De-rating is particularly relevant for renewables because of their intermittence. In the 
French mechanism, renewables producers may opt out of the self-de-rating regime and 
apply  a  pre-determined  de-rating  factor  instead.  In  that  case,  their  risk  for  being  in 
negative  imbalance  for  being  unavailability  is  reduced  because  they  are  only 
considered  unavailable  if  their  unavailability  is  caused  by  technical  reasons  (not 
meteorological reasons). 

5.2.2.2

 Demand response 

Rationale for selectivity 

(275)  Demand response can reduce peak demand and therefore reduce the overall need for 
generation  and  transmission  capacity.  Moreover,  by  putting  a  price  on  their 
willingness  to  reduce  demand,  demand  response  providers  and  aggregators  reveal 
their  individual  Value  of  Lost  Load,  as  explained  in  Chapter  2.  The  participation  of 
demand  response  in  capacity  mechanisms  is  also  of  particular  importance  from  a 
competition  perspective  since  it  may  foster  new  entry  and  help  ensure  existing 
capacity providers face competition. 

(276)  Some Member States target demand response specifically by means of interruptibility 
mechanisms.  Such  schemes  may  be  intended  to  kick-start  demand  response  and 
unlock its potential, in particular from energy intensive industries.  

Openness of capacity mechanisms to demand response 

(277)  While almost all Member State support demand response by means of some form of 
capacity  remuneration,  it  does  not  always  compete  on  equal  footing  in  capacity 
mechanisms or is even implicitly or explicitly excluded. Even separate interruptibility 
schemes are not always open to all types of demand response. 

Explicit exclusion 

(278)  Demand response is explicitly excluded from all tenders for new capacity covered by 
the sector inquiry since these target specifically certain generation technologies. It is 
equally  excluded  from  all  targeted  capacity  payment  schemes  subject  to  the  sector 
inquiry, but is included in the market-wide Irish capacity payment scheme. 

113   Note:  in  the  case  of  self-de-rating,  in  theory  the  respective  power  plant  could  participate  to  the  capacity  mechanism 
with its full 400MW of installed capacity, but it will then be subject to unavailability penalties in order to discourage 
overestimating  of  capacities.  The  strength  of  non-performance  penalties  is  therefore  particularly  important  in 
mechanisms that allow self de-rating.  

88 

 
 
                                                 
(279)  Demand  response is  furthermore excluded from some strategic reserves (Polish  cold 
contingency  reserve  and  German  network  reserve)  but  included  in  others  (Belgium, 
Denmark and Sweden). In the Belgian and Swedish reserve, demand response is only 
subject to limited competition from generation since they define a minimum share of 
demand  response.  The  requirement  to  contract  a  minimum  amount  of  demand 
response  results  in  practice  in  a  separate  category  of  strategic  reserve  that  does  not 
directly  compete  with  generation  and  therefore  does  not  increase  competition  in  the 
capacity  mechanism.  In  Belgium  the  special  treatment  of  demand  response  was 
welcomed  by  demand  response  aggregators  as  an  efficient  way  to  kick-start  their 
development, and it appears to have such effect as the participation of DSR increased 
from 100 MW to 300 MW. Kick-starting the development of new DSR can be further 
stimulated  by  allowing  only  new  DSR  to  participate  to  the  capacity  mechanism  for 
instance  by  limiting  the  participation  to  one  year.  In  the  on  hold  Danish  strategic 
reserve,  10%  of  the  total  volume  required  would  have  been  available  with  a  special 
capacity product to enable competition between demand response and generators. 

(280)  Market-wide capacity mechanisms almost always encompass demand response. This 
is  true  for  the  current  Irish  capacity  payment  scheme  and  the  planned  Irish  central 
buyer  scheme,  but  also  for  the  French  de-central  obligation  scheme.  The  planned 
Italian  central  buyer  mechanism  does  currently  not  allow  for  the  participation  of 
demand response, but Italy plans to include demand response at a later stage.  

(281)  Conversely,  in  many  Member  States,  demand  response  is  still  targeted  specifically 
through  separate  mechanisms.  This  is  the  case  in  Germany,  France,  Ireland,  Italy, 
Poland,  Portugal  and  Spain,  where  support  is  granted  through  a  separate  strategic 
reserve type of mechanism only aimed at demand response, commonly referred to as 
an interruptibility mechanism.  

Implicit exclusion 

(282)  The  eligibility  of  demand  response  to  a  capacity  mechanism  may  de  facto  be 

influenced by the Member State's design choices on the following points: 

  size requirements; 

 

the lead time between capacity contracting and capacity delivery; and 

 

the product design (and in particular the availability duration, testing and requirement 
to provide collateral), explained in more detail in sub-section 5.4.2.1.  

(283)  As mentioned above in sub-section 5.2.2.1, some schemes may limit participation to 
capacity exceeding a certain size. Although a minimum threshold may be appropriate 
to  keep  the  scheme  manageable,  if  that  threshold  is  set  too  high,  this  may  present  a 
barrier  to  entry  to  smaller  demand  response  providers,  particularly  if  aggregation  is 
not allowed. A number of interruptibility schemes targeting demand response services 

89 

 
 
set such thresholds. For example, in the existing German interruptibility scheme a 50 
MW threshold applies (although in the future this is likely to be lowered to 10 MW 
and aggregation will become possible), while in Spain separate auctions are held for 5 
MW and 90 MW loads with no possibility for aggregation.  

(284)  The lead time is the time between the conclusion of the allocation process and the start 

of the delivery obligation for the successful bidders. 

(285)  In the originally planned strategic reserve for Denmark, the lead time was only about 
one month, while in Sweden it appears to have been around 11 months for generation 
and 2.5 months for demand response in the most recent tenders for delivery in winter 
2015/16. 40% of market participants in Belgium considered that the two-month lead 
time was insufficient for the sourcing of demand response. This concern was voiced 
also by respondents in Denmark. However, in all strategic reserves in which demand 
response  can  participate,  the  lead  time  is  the  same  for  demand  response  and 
generation. These reserves have also in practice succeeded in attracting some demand 
response  capacity  which  proved  reliable  when  activated.  In  interruptibility  schemes, 
the  lead  time  varies  from  one  month  to  3  years.  Irrespective  of  the  lead  time,  the 
duration of the scheme as such is considered important for the participation of demand 
response operators. 

(286)  Under  the  French  de-central  obligation  scheme,  demand  response  providers  will  be 
able to carry out the certification process from four years up to two months prior to the 
start  of  the  delivery  year,  while  a  minimum  three-year  lead  time  is  provided  for 
existing generation. Furthermore, participants in the mechanism will be able to adjust 
their position at any time before the delivery period and even after the delivery period 
(though  –in  certain  cases-  at  cost).  Market  participants  welcomed  the  flexible  lead 
time  envisaged  for  demand  response  and  the  possibility  of  continuously  trading 
capacity certificates as it would facilitate their participation.  

(287)  Market participants in Italy expressed the view that the four-year lead time proposed 
for  the  planned  central  buyer  mechanism  would  be  too  long  for  demand  response 
providers,  who  would  not  be  able  to  commit  too  long  in  advance  of  the  delivery 
period. The British capacity mechanism includes a one year ahead auction in addition 
to the main four year ahead auction, which enables the fine-tuning of the amount of 
capacity  to  be  procured  for  each  delivery  year  to  reflect  the  latest  available  demand 
projections, but was also intended to help enable demand response participation. 

(288)  As  regards  product  requirements,  their  impact  is  illustrated  for  example  by  the 
experience with the Polish interruptibility scheme. The first auction organised by the 
Polish TSO for the procurement of interruptible load was postponed as no offers were 
received. Subsequent auction rounds with less strict participation conditions were able 
to  attract  only  limited  amounts  of  interruptible  capacity  (up  to  around  200  MW  of 
capacity  after  a  total  of  five  auction  rounds  spread  over  four  years).  According  to 

90 

 
 
market  participants,  the  potential  for  interruptible  load  services  in  Poland  is  much 
bigger  and  one  of  the  reasons  why  the  auction  did  not  manage  to  unlock  the  full 
potential  of  demand  response  has  to  do  with  the  products  requirement  (demand 
response providers find it difficult to understand the the baselining methodology and 
identify the actual demand reduction obligation) and the level of remuneration offered 
(payment for actual interruptions without availability payments). 

5.2.2.3

 Storage 

(289)  The sector inquiry found no capacity payments dedicated solely to storage capacities. 
The four market-wide capacity mechanisms covered by the sector inquiry, the existing 
Irish  capacity  payment  scheme,  the  planned  Irish  and  Italian  central  buyer  schemes 
and the French de-central obligation scheme, all appear to be open to storage. In the 
case of the German network reserve and the on hold Danish strategic reserve storage 
would be eligible to participate. 

5.2.2.4

 New vs. existing capacities 

Rationale for selectivity 

(290)  With  respect  to  the  inclusion  of  new  and  existing  capacities,  the  sector  inquiry  has 
shown  that  the  focus  of  Member  States  is  often  either  entirely  on  attracting  new 
capacity or on avoiding the closure of existing capacity, rather than both. The capacity 
mechanisms are therefore often tailored entirely to  address either  of those problems. 
At one end there is the tender for new capacity, aiming to attract new capacity only, 
while at the other end there is the strategic reserve aimed at keeping plants that were 
announced for closure or mothballing available to the system. 

Openness of capacity mechanisms to new and existing capacities 

Explicit exclusion 

(291)  In  four  Member  States  (Belgium,  France,  Portugal  and  Spain),  separate  capacity 

schemes for new and existing capacity providers co-exist or are planned.114  

(292)  In  the  three  tenders  for  new  capacity  identified  as  part  of  the  sector  inquiry  (the 
abandoned  tender  in  Belgium  and  the  ones  in  Ireland  and  Brittany),  contracts  were 
offered  to  new  generation  capacity  only.  Existing  capacity  would  receive  no 
remuneration. 

114  

In  the  case  of  Belgium,  a  tender  for  new  capacity  was  envisaged  alongside  the  strategic  reserve  but  was  later 
abandoned. 

91 

 
 
                                                 
(293)  None of the strategic reserves covered by the sector inquiry explicitly excluded new 
capacity.  Equally  in  the  central  buyer  models  in  Britain  and  being  developed  in 
Ireland and Italy both existing and new capacity can participate. The same is true for 
the  French  de-central  obligation  scheme,  where  both  new-build  generation  capacity 
and existing capacity can be certified and consequently receive tradable certificates. 

(294)  Capacity  payment  mechanisms  are  almost  always  open  to  both  new  and  existing 
capacities.  In  certain  cases,  however,  capacity  payment  mechanisms  may  be 
specifically  targeted  at  new-build  capacity.  This  is  for  instance  true  for  the  Spanish 
and Portuguese investment incentive mechanisms. 

Implicit exclusion 

(295)  Even  in  cases  where  both  new  and  generation  capacity  can  theoretically  compete, 

either of them can de facto be excluded by: 

 

lead time;  

  contract duration; or 

  specific prequalification requirements. 

(296)  The  concept  of  lead  time  is  not  applicable  to  the  capacity  payment  mechanisms 
covered by the sector inquiry because there is no time gap between the allocation and 
the delivery obligation. This is because in this kind of mechanism, capacity providers 
are  either  automatically  selected  or  are  selected  upon  the  submission  of  a  simple 
application form, as long as they fulfil the eligibility criteria. Table 8 below provides 
an overview of the lead time in the remaining capacity mechanisms.  

92 

 
 
 
Table 8: Lead time in the capacity mechanisms covered by the sector inquiry  

Source: European Commission based on replies to sector inquiry 

(297)  It appears from Table 8 that strategic reserves tend to have shorter lead times than the 
other  volume-based  mechanisms.  Despite  in  theory  being  open  to  new  and  existing 
generation capacity, they managed to attract only existing generation. 

(298)  40%  of  market  participants  in  Belgium  believe  that  the  two-month  lead  time  is 
insufficient  to  carry  out  the  technical  investments  needed  to  bring  the  selected 
installations in line with the requirements of the strategic reserve. 

(299)  In Ireland, the tender for new capacity was launched in 2003 and became operational 
by  the  planned  deadline  in  2006.  The  lead  time  for  the  tenders  for  new  capacity  in 
Belgium and France was not set in advance but had to be proposed by tenderers and 
was  evaluated  as  part  of  the  award  criteria.  In  the  French  tender,  the  regulatory 
authority (CRE) expressed reservations about the proposed timeframe for completion 
of the project by the successful bidder. 

93 

Member State                        Capacity mechanismLead time *Belgium Tender for new capacityProposed by tenderersFrance Tender for new capacity in BrittanyProposed by tenderersIrelandTender for new capacity3 yearsBelgiumStrategic reserve~ 2 months DenmarkStrategic reserve1 monthNetwork reserve- mandatory1 year**Network reserve - voluntary4.5 monthsCapacity reserveNot yet knownPolandCold contingency reserve~ 2 yearsStrategic reserve - generation8-11 months Strategic reserve -demand response 2.5 months GermanyInterruptibility scheme2 weeksInterruptibility scheme for Sardinia and Sicily3 years Interruptibility scheme for the mainland3 years to 1 month PolandInterruptibility scheme Not availablePortugalInterruptibility scheme Not applicable*SpainInterruptibility scheme~ 4 months Ireland Planned central buyer mechanismNot yet known ItalyPlanned central buyer mechanism4 years Supplier obligation- existing generation4 to 3 yearsSupplier obligation - new generation 4 years to 2 monthsSupplier obligation -demand response4 years to 2 months* The concept of lead time is not applicable to capacity payments SwedenFrance**Planned closure must be announced 12 months aheadInterruptibility services schemeItalyTender for new capacityStrategic reserveGermanyCentral buyer mechanismDecentralised mechanism  
 
 
(300)  A  lead  time  of  four  years  for  both  new  and  existing  capacity  applies  in  the  British 
central  buyer  mechanism  and  is  envisaged  in  the  Italian  one.  The  British  2014  and 
2015 four year ahead auctions managed to attract about 2,621 MW and 1,936 MW of 
new  generation  capacity,  respectively.115  Under  the  British  central  buyer mechanism 
an additional auction is held one year ahead of delivery and capacity providers can re-
trade  their  capacity  in  a  secondary  market,  and  the  Italian  mechanism  provides  for 
adjustment auctions and secondary trading of reliability obligations.116  

(301)  Conversely,  under  the  French  de-central  obligation  scheme,  different  lead  times  are 
envisaged  for  new  and  existing  capacity.  The  latter  must  be  certified  between  three 
and four years ahead of the delivery year while new generation capacity (like demand 
response)  can  be  certified  up  to  two  months  prior  to  delivery.  It  is  noteworthy  that 
capacity certificates can be traded for the whole duration of the lead period.  

(302)  The  vast  majority  of  market  participants  in  France  and  Italy  consider  the  lead  time 
appropriate  to  allow  the  participation  of  new  generation  capacity  provided  that  the 
necessary  authorisations  and  permits  have  already  been  obtained  at  the  time  of  the 
capacity  allocation.  However,  market  participants  in  France  pointed  out  that  the 
mechanism,  which  is  in  principle  based  on  bilateral  trading,  will  be  successful  in 
triggering new investments only if clear price signals are provided at the beginning of 
the  lead  period.  For  that  purpose  the  French  authorities  revised  the  mechanism  to 
include  a  central  buyer  element,  whereby  the  TSO  contracts  competitive  new 
capacities  longer  term  (7  years).  The  contract  is  in  the  form  of  a  contract  for 
difference,  comparable  to  a  feed-in  premium.  The  price  of  the  individual  offers  will 
serve  as  a  'strike  price':  if  the  capacity  market  price  is  above  the  strike  price,  the 
capacity provider will pay back the difference; if the market price is below the strike 
price the capacity provider will receive a subsidy covering this difference. 

(303)  This moreover illustrates that the length of the contracts concluded under the capacity 
mechanisms  is  equally  essential  to  determine  the  competition  between  new  and 
existing capacity. In principle, a longer contract duration provides additional coverage 
against uncertainty on future revenues. Long contracts can therefore reduce the rate of 

115   The total capacity purchased amounts approximatively to 49,259 MW in 2014 and 46,354 MW in 2015. See National 

Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at: 
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;  and  National  Grid,  Provisional  Auction  Results,  T-4 
Capacity Market Auction 2015, available at  
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/2015%20T-
4%20Capacity%20Market%20Provisional%20Results.pdf  
In the Italian central buyer mechanism the main auction (T-4) will be followed by yearly adjustment auctions with the 
aim  of  enabling  capacity  providers  to  re-negotiate  the  contracted  obligations  and  the  TSO  to  adjust  the  amount  of 
capacity to be procured in concomitance with the approaching of the delivery period. Hence, for these auctions the lead 
time  varies  from  three  to  one  year.  Furthermore,  participants  will  be  able  to  further  adjust  their  position  through 
continuous trading in the secondary market during the period from the adjustment auction and the delivery period. 

116  

94 

 
 
                                                 
 
 
return  required  by  the  promoters  of  new  investment  projects  and  facilitate  external 
project financing. These considerations must however be balanced against the benefits 
of  shorter  contracts,  which  allow  for  the  reflection  of  rapidly  evolving  market 
conditions and avoid locking-in certain technologies. 

(304)  Table 9 below provides an overview of the duration of contracts or certificates in the 

capacity mechanisms covered by the inquiry.  

95 

 
 
Table 9: Contract length in the capacity mechanisms covered by the sector inquiry 

Source: European Commission based on replies to sector inquiry117 

(305)  In  strategic reserves  open to  both  new and  existing generation capacity, the contract 
length is the same for both and ranges from 1 to 3 years. An exception is the German 
network reserve that allows for contracts of up to 5 years. In any event, these strategic 
reserves have managed to attract only existing generation capacity (and in some cases 
demand  response).  Market  participants  consistently  expressed  the  opinion  that 
strategic  reserves  are  not  fit  to  promote  investments  in  new  capacity.  Moreover, 
several  market  participants  have  argued  that  one  and  two-year  contracts  may  not  be 
sufficient to refurbish existing generation units. 

117   Plants  in  the  German  network  reserve  can  be  forced  to  remain  in  the  network  reserve  beyond  the  indicated  contract 

lengths of 2 and 5 years so long as the relevant TSO continues to consider them 'system relevant'. 

96 

 
 
 
                                                 
(306)  In  the  case  of  the  inquired  capacity  payment  mechanisms  open  to  both  new  and 
existing capacity, the duration of contracts is one year. An exception is the Portuguese 
availability  incentive  payment  scheme  which  grants  the  payments  for  the  entire 
operational  lifetime  of  new  plants  and  for  the  remaining  lifetime  of  existing  plants. 
With respect to the duration of the payment schemes as such, it is indefinite in Italy 
and  Portugal,  while  it  is  limited  to  10  years  in  Ireland  and  one  year  in  Spain. 
According to the Irish authorities, the mechanism has managed to attract investments 
in  generation,  demand  response  and  storage  since  its  introduction  in  2007.  On  the 
other  hand,  market  participants  from  those  countries  where  the  duration  of  the 
mechanisms is short (Spain) or the level of remuneration has varied significantly over 
time  (Spain  and  Portugal)  are  of  the  view  that  the  mechanism  mainly  aims  at 
preventing existing generation from exiting the market. They have also noted that the 
changes  in  the  level  of  remuneration  create  uncertainty  and  undermine  signals  for 
investments.  

(307)  In  the  planned  Italian  central  buyer  mechanism,  the  contract  length  is  the  same  for 
new and existing generators. Market participants in Italy are generally of the view that 
contracts  of  three-year  duration  may  be  sufficient  to  attract  investments  in  new 
generation capacity. Others however pointed out that this duration is only sufficient to 
avoid  mothballing  which  would  be  the  objective  of  the  mechanism  given  that  most 
CCGT units in Italy are new and efficient. 

(308)  Initially,  in  the  French  mechanism  one-year  contracts  were  considered  sufficient  to 
address  the  missing  money  problem  for  existing  generators  and  other  capacity 
providers,  but  market  participant  respondents  stated  that  the  mechanism  would  not 
attract investments in new capacity. For that purpose, as explained above, the French 
authorities revised the mechanism to include a central buyer element, where the TSO 
contracts competitive new capacities longer term (7 years) on contracts for difference. 

(309)  The British capacity mechanism was the first among those open to new and existing 
capacity  to  differentiate  in  the  contract  lengths  for  new  and  existing  capacities.  The 
2014 and 2015 auctions attracted approximatively 2,621 MW and 1,936 MW of new 
generation  capacity  respectively.  In  view  of  different  obligations  pertaining  to  such 
new capacities, in 2014 92% of the new generation capacity was awarded long term 
(14  and  15  year)  contracts  (2,423  MW),  while  in  2015  only  50%  (982.50 MW)  of 
new-build generation chose those types of contracts.118 

118   See National Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at: 
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;  and  National  Grid,  Final  Auction  Results,  T-4  Capacity 
Market Auction for 2019/2020, available at: 

97 

 
 
                                                 
 
 
 
(310)  Likewise,  all  three  tenders  for  new  capacity  (Belgium,  France  and  Ireland)  offer 
longer contract durations ranging from 6 to 20 years. In Spain, 20 year contracts are 
available under the investment incentive capacity payment scheme. In Portugal, where 
10-year  contracts  are  allocated  for 
the  construction  of  new  hydroelectric 
installations119, installed hydro capacity is expected to increase from 5.6 GW in 2014 
to 7.9 GW in 2020. 

(311)  Additionally,  new  generation  capacity 

is  often 

implicitly  excluded 

through 
preselection  criteria,  such  as  the  15  months  prior  announcement  for  closure  in  the 
Belgian  strategic  reserve,  the  requirement  for  plants  to  derogate  from  emission 
standards under the IED in the Polish cold contingency reserve or the prohibition for 
plants to return to the market once they have entered the German strategic reserve. In 
all  these  cases,  new  generation  capacities  are  effectively  excluded  or  strongly 
discouraged from participating. 

(312)  But  there  are  also  cases  where  additional  requirements  apply  to  new  capacities, 
without  necessarily  excluding  new  projects.  For  example,  in  the  French  capacity 
mechanism  stricter  environmental  criteria  apply  for  new  projects  willing  to  benefit 
from long-term contracts. Such "positive discrimination" was considered justified by 
France  since  the  state  had  a  direct  role  in  contracting  such  capacity  (thereby 
guaranteeing their remuneration for a longer period), whereas this could not be said of 
capacity contracted directly by other market players (suppliers). 

5.2.2.5

 Locational requirements within the Member State 

Rationale for location requirements within the Member State 

(313)  One main reason to include locational capacity requirements in a capacity mechanism 
is to take account of network constraints and ensure capacity is built or maintained in 
particular places. 

Locational requirements in capacity mechanisms 

(314)  The  capacity  mechanisms  covered  by  the  inquiry  are  in  general  open  to  capacity 
irrespective  of  its  location  within  the  Member  State  although  separate  rules  often 
apply to islands.120  

https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf  

119   Note: in this Portuguese investment incentive scheme for hydro power plants, 10 year contracts are equally granted for 

the repowering of existing plants, in order to extend their lifetime. 

120   Participation in capacity mechanisms in Portugal and France is limited to capacity providers located on the mainland, 
while  the  British  capacity  mechanism  excludes  capacity  providers  located  in  Northern  Ireland.  Moreover,  Italy  has 
separate interruptibility auctions for Sardinia and Sicily.  

98 

 
 
                                                                                                                                                         
(315)  Exceptions  are  the  tender  for  new  capacity  in  Brittany  and  the  Italian  central  buyer 
mechanism where participation is linked to the location of the capacity provider in a 
certain  region  within  the  Member  State.  The  on  hold  Danish  strategic  reserve,  the 
German network reserve and the Swedish reserve also have locational requirements.  

Explicit exclusion 

(316)  Explicit locational eligibility requirements can be found in the tender for new capacity 
in Brittany, given that the new power plant must be built in a certain area of Brittany. 
In  the  Swedish  reserve,  only  capacity  located  in  South-Sweden  can  be  contracted 
while  the  on  hold  Danish  reserve  was  intended  to  contract  only  capacity  located  in 
East-Denmark.  Furthermore,  the  central  buyer  mechanism  in  Italy  envisages  zonal 
capacity  auctions,  which  means  demand  for  capacity  will  be  established  for  each  of 
six zones in Italy, and a separate capacity price established in auctions for each zone 
depending on the local balance of supply and demand. 

Implicit exclusion 

(317)  Implicit locational requirements are to be found in the 'mandatory part' of Germany's 
network reserve, which is de facto restricted to generators located in South-Germany.  

5.2.2.6

 Cross-border locational requirements 

Rationale for excluding cross-border participation 

(318)  Member States mostly limit participation in the mechanism to capacity located in their 
territory, citing various reasons mostly based around the relative lack of control their 
TSOs have over foreign capacity and the inability to ensure imports when they might 
need them without reserving interconnector capacity for this purpose  – which would 
undermine  the  efficiency  of  the  Single  Market  by  reducing  the  interconnection 
available to traders.  

Openness of capacity mechanisms to foreign capacities 

(319)  Table  10  shows  the  current  approaches  taken  with  regard  to  foreign  capacity  in  the 
Member  States  included  in  the  sector  inquiry,  based  on  information  provided  by 
public body respondents. Since all of the existing mechanisms covered by the inquiry 
either explicitly include or exclude foreign capacity, this subsection does not make a 
distinction between explicit and implicit exclusion. 

(320)  Portugal,  Spain  and  Sweden  appear  to  take  no  account  of  imports  when  setting  the 
amount  of  capacity  to  support  domestically  through  their  capacity  mechanisms.  In 
Belgium,  Denmark  and  Italy,  expected  imports  are  reflected  in  reduced  domestic 
demand  in  the  capacity  mechanisms.  The  only  examples  of  capacity  mechanisms 
which allowed, allow or plan to allow the direct participation of cross-border capacity 
are found in Belgium, France, Germany and Ireland.  

99 

 
 
(321)  Foreign  plants  were  allowed  to  participate  in  the  Belgian  tender  for  new  capacity, 
provided that they would subsequently become part of the Belgian bidding zone even 
if geographically located in another Member State. 

(322)  In France, a hybrid model of explicit cross-border participation is proposed. Foreign 
generation  and  demand  response  capacity  will  be  able  to  participate  directly  to  the 
French capacity mechanism through a market based process that  enables the foreign 
capacity  or  the  interconnector  to  each  receive  a  share  of  capacity  remuneration 
depending on the relative scarcity of each121. France intends to enable the delivery of 
foreign capacity under this system from 2019. 

(323)  None of the strategic reserves are open to generators located outside of the Member 
State  operating  the  reserve,  except  for  the  German  network  reserve  which  contracts 
capacity outside of Germany provided that it can contribute to alleviating security of 
supply  problems  in  Southern  Germany  through  re-dispatch  abroad.  As  explained  in 
more detail in sub section 7.1 of Annex II to this report, it appears that the situations 
in  which  cross-border  reserve  capacity  could  actually  be  useful  to  the zone  with  the 
strategic reserve, are limited unless interconnector capacity was reserved specifically 
to allow the reserve to be dispatched across border. This however would be inefficient 
because it would permanently reduce the amount of interconnection capacity available 
commercially for market coupling. 

(324)  In  the  Irish  tender,  foreign  capacity  could  participate  if  it  could  demonstrate  its 
contribution  to  Irish  security  of  supply  –  no  foreign  capacity  was  selected  in  the 
tender.  In  the  existing  Irish  capacity  payments  model,  foreign  capacity  can  benefit 
from capacity payments. However, the method for enabling this participation involves 
levies and premiums on electricity prices and is not therefore compatible with market 
coupling  rules  which  require  electricity  prices,  not  capacity  premiums/taxes,  to 
provide the signal for imports and exports.122 

(325)  A condition of the State aid approval for the British capacity mechanism was that the 
participation of interconnected capacity would be enabled. Since December 2015 the 
British capacity mechanism has included interconnectors with Britain, which are de-
rated by the TSO and can then participate as price takers (i.e. they cannot bid above a 
predetermined threshold without having to justify the need for that higher support) in 
capacity auctions. Interconnectors receive one year capacity agreements at the auction 

121  

Interconnection tickets will be allocated per interconnector on the basis of that interconnectors’ contribution to security 
of supply in France. They are then auctioned border by border. Capacities that win interconnector tickets in the auctions 
can  get  certified  and  receive  certificates  to  the  amount  of  their  certified  capacity.  Subsequently,  they  will  be  able  to 
trade their capacity certificates on the French capacity market. 

122   Note however that the Irish capacity mechanism does operate across the UK and Irish border because of joint market 

arrangements and a single bidding zone covering Ireland and Northern Ireland.  

100 

 
 
                                                 
clearing  price,  in  return  for  a  capacity  obligation  requiring  the  delivery  of  capacity 
towards Britain at times of scarcity. 

(326)  More  Member  States  are  now  apparently  ready  to  follow  in  the  UK  and  France's 
footsteps  and  aim  to  develop  cross-border  participation  in  their  mechanisms.  Ireland 
published a decision paper on the design of its future capacity mechanism indicating 
that  an  'interconnector  led  model  will  be  used  at  the  inception  of  the  capacity 
remuneration mechanism, moving to a hybrid option later where both interconnectors 
and external capacity providers are paid for their contribution to the I-SEM generation 
security  standard'123,  and  also  Italy  is  apparently  considering  future  foreign 
participation in its capacity mechanism.  

123   Second CRM Decision paper, SEM-16-022 of 10 May 2016, 

https://www.semcommittee.com/sites/semcommittee.com/files/media-files/SEM-16-
022%20I%20SEM%20CRM%20Detailed%20Design%20Decision%20Paper%202.pdf, p. 5  

101 

 
 
 
                                                 
Table 10: Approach to cross-border participation in the capacity mechanisms in sector inquiry countries 

Source: European Commission based on replies to sector inquiry 

102 

 
 
Both interconnectors and foreign capacity provide security of supply 

(327)  The  contribution  foreign  capacity  makes  to  a  neighbour's  security  of  supply  is 
provided partly by the foreign generators, storage or demand response providers 
that deliver electricity, and partly by the transmission (interconnection) allowing 
power  to  flow  across  borders.  Depending  on  the  border,  there  can  be  a  relative 
scarcity of either interconnection or foreign capacity.  

(328)  In its 24 September consultation on options for cross border participation in the 
French  de-central  obligation  scheme,  RTE  included  analysis  of  the  extent  to 
which interconnection with its neighbours is a limiting factor to receiving imports 
at  times  of  scarcity  in  France.  In  only  15%  of  scarcity  situations  in  France, 
interconnectors between Belgium and France are congested (i.e. there is no more 
capacity available to transfer electricity from Belgium to France). But in 95% of 
scarcity  situations  in  France,  interconnectors  between  France  and  Spain,  France 
and Switzerland, and France and Italy are congested.  

Figure 24: Probability that interconnectors are congested at times of stress in 
France 

Source: RTE Consultation on cross-border participation 

(329)  RTE's  analysis  shows  that  while  there  may  be  a  relatively  strong  security  of 
supply  benefit  to  France  of  increased  investment  in  generation  and  demand 
response  capacity  in  Belgium,  there  is  likely  to  be  relatively  little  security  of 
supply  benefit  to  France  of  increased  investment  in  generation  or  demand 
response capacity in Spain, Switzerland or Italy; on those borders, France would 
see increased security of supply from increased investment in interconnection.  

103 

 
 
 
(330)  This  complicates  the  design  of  an  efficient  solution  for  enabling  cross  border 
participation  in  capacity  mechanisms  since  it  requires  an  appropriate  split  of 
capacity remuneration between interconnector and foreign capacity to reflect the 
relative scarcity of each. It also ideally requires this split to adapt over time – for 
example  through  a  design  that  increases  the  reward  for  foreign  capacity  and 
reduces  the  reward  for  interconnection  if  over  time  the  proportion  of 
interconnection  increases.  The  'hybrid'  approach  to  cross  border  participation 
proposed  in  France  should  address  this  issue,  and  is  in  line  with  the  proposal 
published  as  part  of  the  interim  report  of  the  sector  inquiry  (see  Annex  2).  The 
Market Design Initiative will propose further rules to assist Member States with 
the  implementation  of  hybrid  solutions  that  appropriately  reward  both  foreign 
capacity and interconnection. 

5.2.3

  Issues encountered in relation to eligibility 

5.2.3.1

 Despite  trend  towards  opening,  high  selectivity  of  existing  capacity 
mechanisms 

(331)  The findings on the various capacity mechanisms indicate that most mechanisms 
are  still  targeted  at  a  limited  range  of  capacity  providers.  The  sector  inquiry 
shows that implicit participation requirements are not only as frequent as explicit 
ones,  they  are  also  equally  effective  in  reducing  the  range  of  eligible  capacity 
providers. 

(332)  There is however a growing tendency towards more encompassing mechanisms. 
This  trend  is  illustrated  by  the  recent  British  central  buyer  mechanism,  the  de-
central supplier obligation scheme in France, the planned central buyer scheme in 
Ireland and, so far to a lesser degree, by the mechanism being developed in Italy 
which for the time being excludes demand response. 

5.2.3.2

 Selectivity leads to less competition 

(333)  Eligibility criteria are of particular importance from a competition perspective. If 
allowing  for  a  wide  participation,  a  competitive  bidding  process  allows  the 
market  to  bring  forward  the  technologies  that  can  most  cost-efficiently  provide 
the  required  capacity.  Competitive  pressure  should  provide  capacity  providers 
with incentives to bid at the level that corresponds to the funding they require to 
provide the necessary capacity product. 

(334)  The supply curve in the most recent British capacity auction (see Figure 25) and 
the  mix  of  different  capacity  types  selected  in  the  auction  (see  Figure  26) 

104 

 
 
suggests that extending the pool of eligible capacities should increase competitive 
pressure and lead to a lowering of the price paid for capacity.124 

Figure 25: British Capacity Market 2015 auction supply curve 

Source: National Grid125 

(335)  In the 2015 British capacity auction 46.35 GW of capacity was contracted to the 
different  types  of  capacity  included  in  the  left  hand  pie  chart  of  Figure  26 
whereas 11.37 GW of different capacity types participating to the auction did not 
receive  contracts  (see  the  pie  chart  at  the  right  hand  side  of  Figure  26.  In  this 
case,  the  exclusion  of  storage  capacity,  for  instance,  would  have  required  the 
procurement of 2,617 MW of other, more expensive (since not selected) types of 
capacity.  In  other  words,  less  competition  for  the  capacity  contract  would  have 
led  to  a  higher  overall  capacity  price  and,  a  contrario,  increased  competition 
leads  to  lower  capacity  prices.  By  opening  up  the  pool  of  eligible  resources  as 
much as possible without jeopardising the objective of the mechanism, Member 
States can therefore attain security of supply at a lower price. 

124   Note  if  demand  is  reduced  to  account  for  excluded  capacity  then  the  price  paid  for  capacity  may  also  reduce. 
However, if capacity is excluded there is less certainty about whether it will actually be available in the delivery 
year.  Any  exclusion  also  reduces  the  potential  for  new  entry,  which  will  help  increase  competition  and  exert 
downward pressure on prices.  

125   National  Grid  -  Final  Auction  Results  T-4  Capacity  Market  Auction  for  2019/20.  Full  report  available  here: 

https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf 

105 

 
 
 
 
                                                 
Figure 26: Results of 2015 T-4 British capacity auction; left: capacity providers 
contracted; right: non-selected capacity providers 

Source: National Grid126 

5.2.3.3

 Interruptibility schemes should not result in overcompensation of industry 

(336)  There  is  a  risk  that  interruptibility  schemes  are  not  competitive  (for  instance 
because of high participation thresholds, as described in sub-section 5.2.2.2) and 
overcompensate  participating  industries.  A  reason  is  that  it  is  difficult  for 
governments to estimate the actual costs of load reductions or load-shifting. Some 
of these mechanisms were indeed criticized by respondents to the sector inquiry 
as  constituting  indirect  subsidies  to  energy  intensive  industries.  This  was 
particularly the case for interruptibility mechanisms that were in practice hardly 
ever  used  (for  instance  in  Portugal  and  Spain)  or  where  the  remuneration  level 
was  much  higher  than  the  one  paid  to  generators  under  another  capacity 
mechanism  (as  in  Italy).  In  Poland,  in  contrast,  the  demand  response-specific 
capacity mechanism remunerated demand only if actual curtailments were carried 
out  by  the  TSO  (i.e.  per  MWh  payments  instead  of  per  MW  payments). 
the  TSO  curtailed  demand 
Moreover,  during  actual  scarcity  periods, 
administratively (without remuneration) rather than through the mechanism. 

(337)  Separate demand response schemes may however be justified to unlock demand 
response potential. This objective was most explicitly present in the UK Capacity 
Market where two transitory auctions (TA) were organised to unlock “unproven” 
demand  response,  which  could  subsequently,  once  they  won  a  TA  contract  and 

126  

Ibid. 

106 

 
 
 
 
 
                                                 
therefore became “proven”, participate to the general capacity auctions in order to 
increase competition in those. 

5.2.3.4

 Selectivity leads to a snowball effect 

(338)  The  selective  remuneration  of  certain  types  of  capacity  only  will  aggravate  the 
missing  money  problem  of  non-remunerated  types  of  capacity  and  more  often 
than  not  eventually  require  the  development  of  additional  support  measures 
targeted at those capacity types. 

(339)  An  example  is  the  fragmented  landscape  of  capacity  payment  mechanisms  in 
Spain.  As  early  as  in  1997  Spanish  power  plants  started  receiving  targeted 
capacity  remuneration.  This  however  did  not  appear  sufficient  to  address  the 
generation adequacy problems, since in 2007 the scheme was complemented by 
an  interruptibility  scheme  and  later  still,  in  2010,  by  a  preferential  dispatch 
scheme for indigenous sources (coal).127 

(340)  Another  example  is  the  tender  for  new  capacity  that  is  conceived  as  an 
emergency  response  to  a  perceived  urgent  need  for  new  generation  capacity 
which  the  market  does  not  bring  forward.  If  this  is  indeed  the  objective  of  the 
tender, and it is not accompanied by energy market improvements, it ignores the 
reasons  why  the  market  fails  to  make  the  investment  decision  on  its  own 
initiative.  If  market  participants  are  not  confident  that  the  investment  will 
generate  a  positive  return  on  investment  and  therefore  fail  to  make  new 
investments, this may indicate that there is a general missing money problem in 
the market, such that market conditions are already negative for existing plants. 
The addition of a subsidized power plant to the merit order would only aggravate 
that situation. In other words, the addition of new generation capacity would only 
aggravate  the  missing  money  problem  of  existing  capacity.  This  was  evidenced 
by  the  information  received  by  the  Commission  when  Belgium  intended  to 
develop  a  tender  for  new  gas-fired  production  capacity,  which  was  argued  to 
further  deteriorate  the  already  negative  business  models  of  existing  gas-fired 
power plants. It is then only a matter of time until either a solution for the missing 
money problem of the existing plants imposes itself or the need for another tender 
or  capacity  mechanism  arises  (as  a  result  of  existing  capacity  closing  or 

127  

In order to obtain sufficient running hours to make the selected coal plants viable, under that scheme the selected 
coal plants are dispatched prior to other plants, even if these other plants have placed a lower bid in the market. 

107 

 
 
                                                 
mothballing).  Indeed,  in  all  cases  where  a  tender  was  launched,  it  was 
accompanied or followed by another mechanism.128 

(341)  Although  it  can  not  be  excluded  that  Member  States  suffer  from  multiple  and 
diverse market failures, these can usually be addressed by a single market-wide 
capacity  mechanism  that  allows  for  competition  between  a  broad  spectrum  of 
potential capacity providers. Where Member States wish to opt for a piece-meal 
approach,  they  risk  creating  inefficiencies  and  their  mechanisms  will  therefore 
generally  be  found  to  not  be  appropriate  or  to  lead  to  overcompensation.  The 
exception to this rule is the separate support to unlock demand response potential, 
in view of the considerations made on interruptibility schemes in section 6.2.3. 

5.2.3.5

 Capacity mechanisms do not address causes of locational capacity issues 

(342)  Where  there  is  a  locational  capacity  problem  (i.e.  there  is  either  not  enough 
generation  capacity  located  in  that  particular  region  or  that  region  is  poorly 
connected  to  neighbouring  regions),  this  is  a  sign  that  the  electricity  market  is 
failing  to  provide  the  required  signals  for  investment  in  the  right  places,  or  for 
sufficient transmission investments to mitigate any locational problem. 

(343)  The  sector  inquiry  has  found  two  types  of  capacity  mechanisms  that  have 

selective locational requirements within a Member State's territory: 

(i)  those that correspond to bidding zones, such as the existing Swedish and on hold 
Danish reserve which only procure capacity in specific parts of the country, and 
the  Italian  central  buyer  mechanism  which  is  country-wide  but  sets  different 
demand levels for different bidding zones; and  

(ii) those  that  are  intended  to  encourage  investment  in  particular  locations  within 
large  bidding  zones,  for  example  the  Brittany  tender  and  German  network 
reserve.129 

(344)  All  of  these  mechanisms  can  maintain  or  obtain  more  capacity  in  a  specific 
region. However, the reserves may not be appropriate in the longer term because 
their aim is generally to keep existing capacity from mothballing or closing and 
not to enable new investments. Similarly, tenders can provide a quick-fix solution 
for a lack of investment in a certain region, but they will have to be accompanied 

128   For  France,  the  tender  was  accompanied  by  the  de-central  obligation  mechanism,  for  Ireland,  the  tender  was 
followed  by  a  market-wide  capacity  payment  mechanism  and  in  Belgium  the  tender  was  launched  while  in 
parallel a strategic reserve was developed. 

129   Also Ireland is considering building locational signals into their planned capacity mechanism, but it has not been 

decided in what way the new mechanism will take locational requirements into account. 

108 

 
 
                                                 
by other measures aimed at improving local investment signals to avoid the need 
for another tender in the future. Only the Italian central buyer mechanism appears 
to  have  the  potential  to  address  the  underlying  market  failures  preventing 
investment in a particular region in the longer term by allowing the corresponding 
regional electricity and capacity prices in Italy's bidding zones to provide suitable 
investment signals. 

5.2.3.6

 The exclusion of foreign capacity distorts the Single Market for energy 

(345)  The  exclusion  of  foreign  capacity  from  capacity  mechanisms  reduces  the 
efficiency  of  the  Single  Market  and  increases  costs  for  consumers.  The  most 
damage  is  done  if  Member  States  make  no  assessment  of  the  possibility  of 
imports  when  setting  the  amount  of  capacity  to  contract  through  a  capacity 
mechanism  (in  a  volume-based  model)  or  setting  the  price  required  to  bring 
forward  the  required  volume  (in  a  price-based  mechanism).  This  approach  will 
lead to overcapacity in the capacity mechanism country, and if each country has a 
capacity  mechanism  and  does  the  same  thing,  overcapacity  throughout  Europe. 
The potential unnecessary costs of this overcapacity have been estimated at up to 
EUR 7.5bn per year in the period 2015-2030.130 

(346)  As shown in Table 10 above, some Member States have recognised this problem 
and  attempted  to  address  it  by  taking  account  of  expected  imports  (at  times  of 
scarcity)  when  setting  the  volume  to  contract  in  their  capacity  mechanism.  But 
although this approach recognises the value to security of supply of connections 
with  the  Single  Market  for  energy  and  reduces  the  risk  of  domestic  over-
procurement  it  does  not  address  two  further  ways  in  which  the  exclusion  of 
foreign  capacity  from  capacity  mechanisms  can  have  distortive  impacts  across 
border: 

(i)  If  only  domestic  capacity  receives  capacity  payments,  there  will  be  a  greater 
incentive  for  domestic  investment  than  investment  in  foreign  capacity  or 
interconnectors. Signals for investment will therefore be skewed in favour of the 
capacity  mechanism  zone  and  there  will  be  less  than  optimal  investment  in 
foreign capacity and in interconnector capacity. 

(ii) If capacity mechanisms provide incentives for short term operation on top of the 
electricity  price  signal  (through  capacity  obligations  and  penalties)  they  will 
reduce the potential effectiveness of the electricity price as a signal for efficient 
short  term  market  operation,  demand  response  and  imports.  This  is  because  it 

130   See Booz & Co, 2013, 'Study on the benefits of an integrated European energy market': 

https://ec.europa.eu/energy/sites/ener/files/documents/20130902_energy_integration_benefits.pdf 

109 

 
 
                                                 
  
would never make sense to have a combination of electricity prices and capacity 
mechanism  penalties  providing  a  stronger  short  term  signal  for  operation  than 
electricity prices at VOLL, which represents consumers' maximum willingness to 
pay.  This  issue  is  not  discussed  further  here,  but  is  considered  in  sub-section 
5.4.3.2.  

5.2.3.7

 Split  of  capacity  remuneration  between  interconnectors  and  foreign 
capacity 

(347)  If a capacity mechanism only rewards interconnection or foreign capacity, it will 
not  fully  correct  the  distortions  the  capacity  mechanism  causes  to  investment 
incentives.  To  ensure  the  right  investment  incentives,  the  revenues  from  the 
mechanism  paid  to  the  interconnector  and/or  the  foreign  capacity  should  reflect 
the  relative contribution  each  makes  to  security of  supply  in  the zone  operating 
the  capacity  mechanism.  Where  interconnection  is  relatively  scarce  but  there  is 
ample  foreign  capacity  in  a  neighbouring  zone,  the  interconnectors  should  thus 
receive the majority of capacity remuneration.131 This would reinforce incentives 
to  invest  in  additional  interconnection,  which  is  the  limiting  factor  in  this  case. 
Conversely, where there is ample interconnection but scarcity of foreign capacity, 
the  foreign  capacity  should  receive  most  of  the  capacity  remuneration.  In  this 
case,  foreign  capacity  is  the  limiting  factor  that  should  receive  additional 
incentives. 

5.2.3.8

 Risk of increasing fragmentation from diverse cross-border solutions 

(348)  As explained in sub-section 5.2.2.6, some Member States have developed or are 
attempting  to  develop  solutions  to  enable  cross  border  participation  in  their 
capacity  mechanisms  –  France,  Ireland  and  the  UK  for  example.  When 
developing  solutions  for  explicit  participation  of  interconnectors  or  foreign 
capacity to their mechanism, Member States need to address a number of policy 
considerations. For example, an explicit participation model needs to identify: 

  whether  there  should  be  any  restriction  on  the  amount  of  capacity  that  can 
participate  from  each  connected  bidding  zone  –  including  considering  more 
remotely connected zones; 

  what type of capacity product (obligations and penalties) should apply to foreign 

capacity providers; and 

131   For regulated interconnectors, any capacity congestion rents earned would need to be appropriately regulated (eg. 
refunded  to  consumers  in  the  connected  markets  if  the  interconnector's  revenues  –  including  the  capacity 
revenues – are above its regulated cap). See Regulation 714/2009 Articles 16 and 17. 

110 

 
 
                                                 
  which foreign capacity providers are eligible to participate – for example whether 
a  mechanism  should  be  open  to  interconnectors  and/or  to  foreign  capacity 
(demand response, generation, storage). 

(349)  The  risk  with  an  uncoordinated  approach  is  that  the  Single  Market  becomes 
increasingly  fragmented  and  complex,  with  specific  different  rules  emerging  on 
each border. 

(350)  It is therefore not surprising that 85% of market participant respondents and 75% 
of  public  body  respondents  to  the  sector  inquiry  questionnaire  felt  that  rules 
should  be  developed  at  EU  level  to  limit  as  much  as  possible  any  distortive 
impact of capacity mechanisms on cross national integration of energy markets. 
As  explained  in  sub-section  5.2.3.6  above,  one  of  the  main  ways  in  which 
capacity  mechanisms  create  distortions  cross  border  is  if  they  are  limited  to 
national  capacity.  The  Commission  therefore  developed  a  potential  approach 
concerning  aspects  of  cross  border  participation  which  is  included  in  Annex  2. 
France has proposed to adopt the approach outlined in Annex 2 in its mechanism 
and the Market Design Initiative includes proposals to require the implementation 
of such an approach in future. 

5.2.4

  Conclusions on eligibility 

(351)  To obtain as much competition as possible in the capacity mechanism, Member 
States  should  design  a  mechanism  that  is  as  encompassing  as  possible  so  that 
different  types  of  capacity  providers  are  effectively  put  into  competition  with 
each  other.  This  may  require  specific  arrangements  to  accommodate  certain 
capacity types, the benefit of which should again be balanced against the possible 
discrimination created by differentiated treatment of different capacity resources.  

(352)  Although  certain  selective  capacity  mechanisms  may  appear  to  be  appropriate 
solutions  to  address  immediate  or  transitory  capacity  concerns,  in  the  long  run 
they  often  do  not  really  target  the  underlying  adequacy  problem  and  even  risk 
aggravating  it.  They  may  therefore  trigger  the  need  for  additional  capacity 
mechanisms  to  address  the  fallout  of  the  initial  mechanism(s).  However,  since 
parallel capacity mechanisms fail to foster competition between different types of 
capacity providers, they should be avoided as much as possible. 

(353)  Unless interconnectors and foreign capacity providers receive remuneration from 
capacity  mechanisms  reflecting  the  extent  to  which  they  deliver  security  of 
supply for the capacity mechanism zone, signals for investment will be skewed in 
favour  of  the  capacity  mechanism  zone  and  there  will  be  less  than  optimal 
investment  in  foreign  capacity  and  in  interconnector  capacity.  This  inefficiency 
will increase costs for consumers overall.  

111 

 
 
(354)  Despite the repeated acknowledgement by the European Council of the need for a 
fully-functioning and interconnected energy market, cross border participation in 
capacity mechanisms remains rare in practice. There may therefore be a need for 
a  set  of  principles  or  rules  harmonising  the  cross-border  participation  of 
capacities  in  different  capacity  mechanisms,  including  the  definition  of  a 
common  product  to  account  for  the  capacity  to  be  supplied  from  neighbouring 
markets.  Such  harmonized  approach  appears  to  have  the  potential  to  avoid  the 
complexity  that  might  arise  if  individual  solutions  are  developed  for  each 
mechanism or border, while still allowing Member States the flexibility to design 
different  capacity  mechanisms  to  address  the  problems  that  best  address  their 
local issues. 

5.3 

Allocation Process 

5.3.1

  The role of the allocation process in capacity mechanisms 

(355)  This section covers the 'allocation process', used to select the capacity providers 
that  will  receive  capacity  remuneration  and to  determine  the  price  paid  to  these 
beneficiaries.  

(356)  The  capacity  mechanisms  covered  by  the  sector  inquiry  either  use  an 

administrative or a competitive allocation process.  

(357)  When an administrative allocation process is employed all the capacity providers 
that  meet  the  eligibility  requirements  are  selected  without  competition  and  the 
remuneration  of  capacity  is  set  in  advance  by  the  Member  State  authorities  or 
negotiated bilaterally between the latter and the capacity provider. 

(358)  In  a  competitive  allocation  process,  eligible  capacity  providers  participate  in  a 
bidding process and the capacity remuneration is the result of this process. 

(359)  The following sections will examine the design of the different types of allocation 
processes  employed  and  assess  to  what  extent  they  prevent  excessive  profits 
while sending the right signals for investments.  

5.3.2

  Findings of the sector inquiry on administrative allocation processes 

(360)  As  illustrated  in  Figure  27,  an  administrative  allocation  process  is  employed  in 
price-based  mechanisms,  such  as  (market-wide  and  targeted)  capacity  payment 
schemes,  the  interruptibility  scheme  in  Portugal  and,  since  2016,  in  the 
interruptibility scheme in Sardinia and Sicily. 

(361)  Moreover,  an  administrative  procedure  is  in  practice  employed  also  in  the 
'mandatory part' of the German network reserve. While this reserve is in principle 

112 

 
 
volume-based  and  the  price  of  capacity  is  intended  to  be  competitively 
determined,  the  requested  volume  has  so  far  always  exceeded  the  offers  of 
eligible  capacity  providers.  This  has  resulted  in  all  eligible  providers  located  in 
Germany  receiving  the  capacity  remuneration,  which  is  bilaterally  negotiated 
between  the  TSO  and  the  capacity  providers  on  the  basis  of  a  methodology 
established by the regulator.  

Figure 27: Capacity mechanisms with an administrative allocation process in the 
Member States covered by the sector inquiry

Source: European Commission based on replies to sector inquiry 

(362)  In most of these capacity mechanisms, capacity providers submit an application 
to the competent Member State authority, which limits itself to verifying whether 
the eligibility criteria are met and the application form is complete. The existing 
Irish  market-wide  capacity  payment  mechanism  grants  administrative  payments 
systematically to all capacity providers with no need for an application process. A 
similar  process  is  followed  for  the  operational  reserve  in  Poland  where  during 
peak hours on working days the capacity payment is automatically granted to all 
available centrally dispatchable plants that have not secured power sales contracts 
or are not dispatched by the TSO. 

113 

 
 
 
5.3.2.1

 Capacity price-setting in administrative allocation processes 

(363)  In  an  administrative  allocation  process,  the  level  of  capacity  remuneration  is 
established ex ante by public authorities rather than being determined by market 
forces.  

(364)  In reply to the Commission's survey, the vast majority of market participants have 
argued  that  administratively  set  prices  are  unlikely  to  reveal  the  real  value  of 
capacity.  

(365)  There  is  one  mechanism  in  which  the  allocation  process  has  switched  from 
administrative  to  competitive  that  is  the  Spanish  interruptibility  scheme.  This 
scheme  was  based  on  fixed  payments  until  2014.  For  each  year  from  2008  to 
2014, the TSO disbursed 550 million EUR to procure 2,000 MW of capacity. In 
2015, the TSO decided to allocate the same amount of capacity as in the previous 
six  years  by  means  of  an  auction  rather  than  an  administrative  procedure.  This 
resulted in a decrease in the total annual remuneration under the scheme from 550 
million EUR to 353 million EUR.  

(366)  In  Germany,  the  authorities  plan  to  also  switch  from  an  administrative  to  a 
competitive  allocation  mechanism  for  the  interruptibility  scheme.  In  order  to 
ensure  sufficient  competitive  tension  in  the  bidding  process  the  total  capacity 
volume to be tendered is planned to be reduced from 3 GW to 1.5 GW.  

(367)  While the level of remuneration plays an important role in providing signals for 
investments  and  ensuring  that  the  right  capacity  volume  is  procured  to  meet  a 
certain  reliability  standard,  only  in  some  price-based  mechanisms  the  level  of 
remuneration  (or  the  methodology  for  its  calculation)  is  explicitly  and 
automatically tied to the reliability standard. This is the case in the Irish market-
wide  capacity  payment  mechanism,  the  Polish  operational  reserve  and  the 
investment incentive mechanism in Portugal. 

(368)  In Ireland, the value of the annual capacity payment is determined as the product 
of the required quantity of capacity (necessary to meet an adequacy standard set 
for  Ireland  and  Northern-Ireland  jointly)  and  its  cost-based  price.  Furthermore, 
40%  of  the  payment  is  calculated  year-ahead,  30%  month-ahead  and  the 
remaining  30%  is  determined  and  allocated  ex-post  so  that  it  reflects  the  actual 
value of capacity in any period. 

(369)  Under the Polish operational reserve the hourly cap on capacity payments is tied 
to  a  percentage  (18%  in  2015)  of  the  expected  demand  during  peak  hours  on 
working days. Capacity remuneration is proportionally lowered if the amount of 

114 

 
 
available  operational  reserve  capacity  exceeds  the  TSO's  target  of  18%  of 
expected demand in peak hours.  

(370)  In  Portugal,  the  remuneration  under  the  investment  incentive  mechanism  is 
inversely proportional to the capacity margin. This means that the remuneration 
should decrease and eventually tends to zero when the capacity margin has been 
exceeded so as to avoid that the capacity mechanism sends misleading signals for 
investment.  

(371)  In Spain, according to the law establishing the investment incentive mechanism, 
the remuneration should have been calculated according to a methodology which 
is  almost  identical  to  the  one  used  in  the  Portuguese  investment  incentive 
mechanism. However, that methodology was never applied. Instead, the level of 
remuneration  was  administratively  set  and  the  payment  maintained  (and 
increased for some periods) even in times of overcapacity.  

(372)  Figure  28  below  shows  the  evolution  of  the  capacity  margin  in  Spain  for  the 
period  2007-2014.  During  the  same  period,  the  remuneration  under  the 
investment incentives scheme was set at 20,000 EUR/MW in 2007 and at 26,000 
EUR/MW  in  November  2011.  It  remained  more  or  less  stable  until  July  2013 
when  the  annual  payment  decreased  to  10,000  EUR/MW  (however,  the  aid 
granting period was doubled at the same time). 

Figure 28: Evolution of the capacity margin in Spain 

Source: Report on Electric System - year 2013. REE, System Operator 

(373)  In  Spain  the  capacity  margin  (ratio  between  installed  firm  capacity  and  peak 
demand) is set at 1.1. The figure shows that this reliability standard was exceeded 
since as early as 2007. However, the mechanism continued to provide incentives 
for  investments  in  new  capacity.  For  instance,  the  sector  inquiry  identified  an 
example of  a new gas-fired power plant which was authorised in 2013 and will 
receive the investment incentive payments for 20 years once in operation.  

115 

 
 
 
(374)  The remuneration for interruptibility services in Sardinia and Sicily has been set 
by  law  as  of  2016.  For  the  period  2010-2015  the  service  had  been  tendered. 
However, the poor participation in tenders resulted in the maximum allowed price 
(300,000  EUR/MW/year)  always  being  paid  to  service  providers.  On  the  other 
hand,  in  the  same  period,  the  auction  for  similar  interruptibility  services  in  the 
mainland  cleared  at  a  substantially 
lower  price  (approximately  90,000 
EUR/MW/year in 2015). Italy decided therefore to use this price as benchmark to 
fix the price of the islands' scheme132.  

5.3.3

  Findings of the sector inquiry on competitive allocation processes 

(375)  Two  different  types  of  competitive  allocation  processes  have  been  identified  in 
the capacity mechanisms covered by the sector inquiry: central auctions133 and 
de-central capacity market systems. 

(376)  In central auctions, the Member State's authorities determine (or ask the TSO to 
determine) at the outset the capacity needed to ensure generation adequacy. This 
capacity  is  then  auctioned.  The  sector  inquiry  has  also  identified  a  capacity 
mechanism in which the volume to be procured through the auction is not defined 
ex ante, namely the planned central buyer mechanism in Italy.134 Auctions have 
been employed mainly in strategic reserves including interruptibility schemes and 
for tenders for new capacity. They are also used in central buyer mechanisms.  

(377)  In  the  de-central  obligation  mechanism  which  France  is  implementing,  the 
amount of capacity needed to ensure security of supply is not determined ex ante 
but  is  estimated  by  individual  suppliers  (however,  based  on  projections  by  the 
TSO). The suppliers are under the obligation to procure from capacity providers 
enough  capacity  certificates  to  cover  the  capacity  needs  of  their  customers, 
adjusted  to  simulate  a  cold  spell  occurring  once  every  ten  years.135  Moreover, 
the de-central French mechanism was originally supposed to be based mainly on 
bilateral  trading.  However,  the  French  authorities  have  proposed  to  amend  the 
system  obliging  large  capacity  operators  (>  3  GW)  to  offer  predetermined 
volumes of certificates in different public auctions to be held on the EPEX SPOT 

132   The level of remuneration is adjusted to take into account the specificities of the islands' scheme. For instance, 
the  average  number  of  sheds  over  the  2010  –  2015  period  was  higher  than  in  the  mainland  and  the  average 
duration of the shedding events was longer.  
In  this  report,  the  term  'auction'  is  meant  to  comprise  different  types  of  competitive  bidding  process  including 
also tenders.  

133  

134   Rather  than  determining  a  fixed  amount  of  capacity,  the  planned  Italian  mechanism  uses  a  sloping  demand 

135  

function so that the capacity to be procured depends also on the prices of the offers in the auction.  
It is important to note, however, than under the French market-wide capacity mechanisms the estimation of the 
amount  of  capacity  to  be  procured  is  not  left  entirely  to  suppliers,  since  the  TSO  determines  (ex-post)  the 
correction factor to be applied to the total consumer demand to simulate severe winter conditions. 

116 

 
 
                                                 
exchange.  Finally, France has  also proposed to organise annual tenders for new 
capacity.  

(378)  Figure  29  below  provides  an  overview  of  the  capacity  mechanisms  covered  by 

the sector inquiry that employ a competitive allocation process.  

Figure  29:  Capacity  mechanisms  with  a  competitive  allocation  process  in  the 
Member States covered by the sector inquiry 

Source: European Commission based on replies to sector inquiry 

5.3.3.1

 Capacity price-setting in competitive allocation processes 

(379)  The  sector  inquiry  has  identified  different  pricing  rules  in  the  capacity 

mechanisms that employ a competitive allocation process.  

Pay-as-bid and pay-as-clear rule 

(380)  The  tenders  for  strategic  reserves  in  Belgium,  Denmark,  Germany  ('voluntary 
part'  of  the  network  reserve  and  the  planned  capacity  reserve),  Poland  (cold 
contingency  reserve)  and  Sweden  employ  a  pay-as-bid  rule,  meaning  that 
successful bidders receive the remuneration specified in their individual bids.  

(381)  A  pay-as-bid  rule  was  also  applied  in  the  tender  procedures  carried  out  for  the 
construction and operation of new power plants in Ireland in 2003 and in France 
in  2012. However,  while  in  the Irish tender the contract  was awarded solely  on 

117 

 
 
 
the basis  of price,  in  the tender for new capacity in  Belgium and  Brittany price 
was only one of the award criteria (albeit the most important one). 

(382)  The  French  de-central  obligation  scheme  envisages  both  bilateral  trading  of 
capacity certificates and public trading via a number of auctions organised every 
year by the EPEXSPOT trading platform. 

(383)  A pay-as-clear or  uniform price  rule has  been used  in  the auction in  the  British 
central buyer mechanism and is proposed for the planned Italian and Irish central 
buyer mechanisms, and under the French market-wide mechanism (EPEX SPOT 
auctions).  In  this  type  of  auction,  successful  bidders  all  receive  capacity 
remuneration equal to the marginal price in the auction (i.e. the most expensive 
unit that was successful). This means each MW of capacity will receive the same 
remuneration level at the end of the bidding process.  

Price caps and price floors 

(384)  Existing  and  planned  capacity  mechanisms  covered  by  the  sector  inquiry  often 
include (implicit or explicit) price caps or price floors. For instance price caps are 
used  in  the  German  interruptibility  scheme,  the  German  capacity  reserve,  the 
Italian  auctions  for  the  procurement  of  interruptible  load  and  in  the  planned 
Italian and Irish central buyer mechanism. In the latter two, it is expected that a 
price  cap  will  be  set  at  the  level  of  the  fixed  costs  of  new  entrant  i.e.  the 
generation  technology  with  the  lowest  fixed  costs.  In  the  British  capacity 
mechanism, the price cap was set at 75,000 GBP/MW.  

(385)  The French market-wide mechanism, the Belgian strategic reserve and the Polish 
cold  contingency  reserve  employ  an  'implicit'  price  cap.  In  the  French  capacity 
mechanism,  an  implicit  price  ceiling  applies  through  the  cap  on  capacity 
imbalance settlement prices; the cap is set to increase gradually and is meant to 
eventually  reflect  the  cost  of  new  entry.  In  Belgium,  the  national  regulatory 
authority has the power to review the level of the remuneration if it considers bids 
manifestly  unreasonable.  In  Poland,  the  2013  tender  for  the  cold  contingency 
reserve was not successful in procuring the amount of capacity requested because 
some  of  the  bids  exceeded  the  TSO's  projected  budget.  A  second  tender 
procedure in 2014 managed to procure the remainder of the capacity because the 
bids were substantially lower than in the 2013 procedure.  

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(386)  In  the  interruptibility  scheme  for  Sardinia  and  Sicily,  since  the  tender  was 
undersubscribed136,  all  participants  bade  at  the  price  cap  and  received  the 
maximum  remuneration.  This  has  led  Italy  to  switch  from  a  competitive  to  an 
administrative allocation process for that scheme and to reduce the amounts to be 
procured. These changes will result in considerable savings for the system.  

(387)  In  Spain,  the  first  auction  for  2,000 MW  of  interruptible  load  in  2015  was 
followed by an extraordinary auction for an additional 1,020 MW of interruptible 
load although the service had never been used in the previous six years. The total 
budget  allocated  for  the  services  was  550  million  EUR.  While,  as  mentioned 
above, the first auction had succeeded in substantially reducing the cost, with the 
second auction costs increased to a level close to the total budget available (508 
million EUR). Conversely, competition in the two British capacity auctions held 
to  date  pushed  the  clearing  price  (19.40  GBP/kW/year  in  2014  and  18 
the  price  cap,  set  at  75 
GBP/kW/year 
GBP/kW/year.137  

in  2015)  substantially  below 

(388)  A price floor is only envisaged in the Italian central buyer mechanism. According 
to  the  Italian  authorities,  the  price  floor  will  enable  the  capacity  mechanism  to 
support new investment without the need for long contracts. The premium would 
be  paid  to  all  existing  capacity  that  participates  in  the  auction,  even  if  it  is  in 
excess of the demanded capacity.  

5.3.4

  Issues encountered in relation to allocation processes 

(389)  The  choice  of  the  allocation  process  and  its  design  impact  the  level  of  capacity 
prices  and  their  transparency.  These  are  crucial  to  ensure  that  a  capacity 
mechanism  sends  the  appropriate  and  clear  signals  for  investments.  The 
following sections examine the issues identified in this respect.  

136   For instance, in 2015, interruptible power contracted under the mechanism amounted to 163 MW in Sardinia and 

156 MW in Sicily falling significantly short of the desired target of 500 MW per island.  

137   See National Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at: 
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;  and  National  Grid,  Final  Auction  Results,  T-4 
Capacity Market Auction for 2019/2020, available at:  
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf  

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5.3.4.1

 Competitive allocation processes are better at revealing the real value of 
capacity  

(390)  The sector inquiry revealed that the remuneration granted through a competitive 
allocation process is more likely to correspond to the real value of capacity than 
where an administrative allocation processes is applied.  

(391)  This  conclusion  is  supported  by  a  vast  majority  of  market  participants  from 
Member  States  with  capacity  payment  mechanisms.  For  instance,  none  of  the 
market  participants  in  Spain  believe  that  the  level  of  the  remuneration  is 
appropriate  in  the  various  price-based  schemes.  A  large  majority  of  market 
participants in Italy, Portugal and Spain are of the view that the current level of 
remuneration  under  the  respective  capacity  payment  mechanisms  is  too  low  to 
cover  the  costs  of  availability  or,  in  the  case  of  the  Portuguese  investment 
incentives  mechanism,  to  recoup  the  investments  for  the  construction  or 
refurbishment of hydro power plants that the scheme obliges them to undertake.  

(392)  In capacity payment mechanisms the remuneration is spread over a large number 
of  –  in  some  case  all  –  operators,  whereas  in  an  auction  the  remuneration  is 
granted only to those that are needed to address the estimated capacity shortage. 
For  instance,  a  number  of  Italian  respondents  also  noted  that  although  the 
capacity payment is paid to all eligible capacity providers, the majority of those 
are  never  or  very  rarely  called  upon  to  provide  their  services  in  situation  of 
system  tightness,  either  because  of  their  location  or  because  of  the  type  of 
capacity they could supply. 

(393)  In  case  the  remuneration  is  lower  than  the  real  value  of  capacity  the  capacity 
mechanism will not provide adequate incentives for investments and will thus be 
ineffective. In that case, the capacity mechanism may not deliver value for money 
as it will not meet the security of supply objective. 

(394)  However, an administrative allocation process can also set the price at a level that 
is too high. This was the case for the Spanish interruptibility scheme, where the 
price  per  MW  of  interruptible  capacity  decreased  considerably  when  the 
allocation  process  changed  from  a  fixed  remuneration  determined  ex-ante  to  a 
competitive auction.  

(395)  The risk of administratively determining a level of remuneration that is either too 
high  or  too  low  does  not  normally  occur  in  competitive  allocation  processes 
because the remuneration is based on bids received from market participants that 
indicate  the  value  they  place  on  delivering  the  requested  service.  However,  as 
underlined in the next paragraph, competitive processes need to be well-designed 

120 

 
 
in  order  to  indeed  produce  a  remuneration  that  reflects  the  true  value  of  the 
capacity. 

5.3.4.2

 The  use  of  a  competitive  allocation  process  will  not  always  guarantee 
competition 

(396)  Market power can allow capacity providers to withhold capacity or inflate prices 
in the allocation process. For instance, in the absence of sufficient competition or 
regulatory  oversight,  an  operator  that  owns  a  large  fleet  of  power  plants  could 
withdraw some plants from the process to increase competition and the chances 
of  setting  higher  prices  for  the  plants  that  it  does  include  in  the  process.  Note 
strategic withholding is also a risk in electricity markets – it is not a risk unique to 
capacity mechanisms.  

(397)  In  the  auctions  held  under  the  interruptible  load  scheme  in  Sardinia  and  Sicily 
and  the second auction held under the Spanish interruptibility mechanisms only 
few market participants were able to deliver the requested capacity. Those market 
participants  could  therefore  exercise  market  power  in  the  auction  by  bidding 
close  to  the  price  cap  (or  maximum  available  budget  in  the  case  of  Spain). 
Conversely,  the  two  auctions  held  so  far  in  the  British  mechanism  demonstrate 
that when there is strong competitive tension in the allocation process prices can 
be much lower than the price cap.  

(398)  These  examples  also  show  the  importance  of  the  design  of  the  competitive 
allocation process in ensuring that capacity is procured at the lowest cost for the 
community. This is not the case, for instance, when the amount of capacity to be 
procured has been overestimated or when the price cap is set at a very high level 
and  there  is  insufficient  competition  to  determine  the  right  price  of  capacity. 
However, the history of the interruptibility scheme for Sardinia and Sicily shows 
that  in  some  (exceptional)  circumstances,  it  is  not  possible  to  design  the 
allocation process in a way that maximises competition. In those circumstances, 
an  administrative  allocation  process  may  be  more  effective  at  procuring  the 
service at the lowest cost for the system.  

(399)  The  issue  of  market  power  is  even  more  prominent  in  de-central  allocation 
systems  when  these  are  implemented  in  a  market  with  a  highly  concentrated 
generation  segment.  Those  mechanisms  strongly  rely  on  de-central  capacity 
forecasting  and  trading.  Therefore,  more  established  players  will  normally  have 
an advantage over their competitors as a result of asymmetric market information.  

(400)  These  effects  could  be  partially  mitigated  by  the  introduction  of  mandatory 
exchange  trading  in  the  de-central  mechanism.  However,  only  by  opening 
participation  to  the  mechanism  as  much  as  possible  to  new  entrants,  foreign 

121 

 
 
generation and demand response it can be ensured that competitive pressure is put 
on the incumbent and that the price of capacity would be the result of competitive 
market forces. These considerations are valid also for central buyer mechanisms 
that operate in highly concentrated markets.  

(401)  When  market  power  exists  and  it  is  not  possible  to  extend  participation  in  the 
mechanisms –due for instance to the poor development of the electricity network 
or of demand response– an administrative allocation process can be justified with 
a  view  to  minimise  the  costs  of  the  system.  According  to  market  participant 
respondents,  this  logic  inspired  the  German  authorities  when  designing  the 
allocation of the mandatory part of the network reserve.  

5.3.4.3

 An  allocation  process  that  does  not  identify  the  real  value  of  capacity 
sends misleading signals for market entry and market exit  

(402)  An allocation process that does not reveal the real value of capacity is unlikely to 

send the proper signals for market entry or market exit.  

(403)  On  the  one  hand,  it  can  result  in  artificially  keeping  existing  capacity  in  the 
market or even in developing new capacity in situations of overcapacity. This is 
for  instance  the  case  in  the  Spanish  investment incentive  mechanism  which  has 
incentivised the commissioning of new generation even after the capacity margin 
had  been  substantially  exceeded.  Price  floors  are  in  practice  similar  to 
administratively  set  capacity  prices  and  entail  the  same  risks.  In  the  planned 
Italian  central  buyer  mechanism,  the  price  floor  would  be  paid  to  all  existing 
capacity,  even  if  offered  in  excess  of  the  amount  requested  by  the  TSO.  This 
capacity  is  therefore  artificially  kept  in  the  market.  Moreover,  as  with  capacity 
payments,  price  floors  prevent  the  capacity  price  from  tending  automatically  to 
zero in case of overcapacity.  

(404)  A  low  level  of  capacity  remuneration  set  by  a  competitive  process  should  be  a 
reliable signal that there is excess capacity that should close. However, if a low 
level  of  remuneration  is  set  administratively,  it  may  not  provide  adequate 
incentives  for  keeping  plants  in  the  market  or  for  new  capacity  to  enter  the 
market.  The  vast  majority  of  respondents  in  the  country  where  a  capacity 
payments mechanism has been established are of the view that the remuneration 
provided  under  the  mechanism  is  not  sufficient  to  trigger  investments  in  new 
generation capacity. Moreover, the vast majority of market participants in Spain 
believe that the level of remuneration under the availability incentive scheme is 
not sufficient to recover the costs needed to keep the plants in the market. 

(405)  Linking  the  level  of  remuneration  to  a  reliability  standard,  as  in  the  Portuguese 
investment  incentive  mechanism,  can  avoid  the  capacity  mechanism  sending 

122 

 
 
misleading signals at times of overcapacity, provided that the adequacy standard 
has  been  properly  defined  and  the  remuneration  is  amended  accordingly. 
However,  the  implementation  of  this  solution  does  not  address  the  issues  that 
arise  from  not  having  allowed  the  level  of  capacity  remuneration  to  be 
determined in a competitive manner in the first place. 

5.3.4.4

 Non-transparent  capacity  prices  can  negatively  affect  investment  signals 
and competition  

(406)  A low level of transparency characterises  those capacity  mechanisms where  the 
level of capacity remuneration is mainly bilaterally agreed, such as the French de-
central obligation scheme, as originally designed.138 This lack of transparency can 
affect investment signals. Some French market participants expressed this view.  

(407)  Furthermore,  bilateral  trading  can  lead  to  discriminatory  treatment  of  different 
capacity providers. The bilateral trading of certificates in the initial conception of 
the  French  capacity  mechanism  could  have  favoured  vertically  integrated 
operators, which can rely on intra-group trading to meet the supplier obligation. 
There was in particular a risk that they applied more advantageous conditions to 
their supply branch than to other suppliers. This view was supported by several 
market participants.  

(408)  The  mandatory  auctioning  of  (specified  volumes  of)  certificates  on  a  public 
exchange,  as  proposed  by  the  French  authorities,  can  minimise  this  risk  by  (i) 
creating  more  transparency  on  the  capacity  price,  (ii)  increasing  liquidity  in  the 
capacity market and (iii) avoiding market manipulation by the dominant capacity 
providers. Moreover, the exchange auctions' price will be used to set a cap for the 
tender processes for new capacity. 

(409)  In  Belgium  market  participants  are  concerned  that  the  non-transparent  criteria 
used  by  the  regulator  to  revise  offers  in  the  strategic  reserve  will  create 
uncertainty  for  companies  as  regards  their  expected  revenues,  in  particular  if 
investments are needed. 

5.3.5

  Conclusions on allocation processes 

(410)  In  Member  States  covered  by  the  sector  inquiry,  all  the  new  schemes  that  are 
currently  being  implemented  or  planned  to  be  implemented  with  a  reasonable 

138   This  was  one  of  the  arguments  leading  the  European  Commission  to  open  in-depth  investigations  into  the 

mechanism. 

123 

 
 
                                                 
degree of certainty include a competitive price-setting process139. This is case for 
instance  in  France,  Ireland,  and  Italy.  Moreover,  Ireland  and  Italy  are  moving 
from an administrative to a competitive allocation process. 

(411)  A  properly  designed  competitive  allocation  process  minimises  the  costs  of  the 
capacity  mechanism,  as  long  as  its  design  ensures  competitive  pressure  and 
prevents  the  exercise  of  market  power.  This  can  best  be  achieved  by  allowing 
many  different  existing  and  new  capacity  providers  to  compete.  Besides  the 
allocation process design, eligibility criteria and capacity product features play a 
crucial role in this respect as they explicitly or implicitly influence the number of 
capacity  providers  that  can  take  part  in  the  process  (see  Sections  0  and  0 
respectively).  

(412)  The implementation of a decentralised allocation process in a highly concentrated 
market  with  vertically  integrated  undertakings  is  more  prone  to  the  exercise  of 
market  power  than a  central  buyer mechanism  it  allows  the  dominant  vertically 
integrated  undertakings  to  discriminate  against  their  competitors.  Specific  rules 
may be required to prevent the exercise of market power and abuse of dominance.   

(413)  A  competitive  allocation  process  is  more  likely  to  reveal  the  real  value  of 
capacity and therefore to send adequate signals for market entry and market exit, 
as long as prices are transparently set. 

(414)  In  general,  respondents  to  the  public  consultation  supported  these  conclusions 
and  pointed  to  the  risk  of  over  procurement  and  overcompensation  when 
administrative processes are employed.  

5.4 

The capacity product: obligations and penalties 

5.4.1

  Capacity products 

(415)  Once Member States have selected the capacity providers that could contribute to 
addressing the identified adequacy problem, they need to design the most suitable 
'capacity  product'  to  achieve  that  aim.  In  other  words,  they  need  to  develop  the 
rules  determining  what  exactly  capacity  providers  are  required  to  do  in  the 
capacity  mechanism  in  return  for  receiving  capacity  remuneration  (their 
'obligation'),  and  what  happens  if  they  fail  to  do  what  they  are  required  to  do 
(usually a 'penalty' of some kind). These obligations and penalties are important 
to provide an 'incentive effect' on the capacity providers benefitting from capacity 

139   The  new  Spanish  support  scheme  for  plants  burning  domestic  coal  should  employ an administrative  allocation 

process. However, it is not yet clear whether Spain will implement this mechanism.  

124 

 
 
                                                 
remuneration,  and  ensure  that  they  deliver  secure  and  reliable  supplies  to 
consumers. 

(416)  If Member States fail to design a capacity product to correspond to the specific 
generation adequacy  problem identified, the capacity  mechanism will be unable 
to  attain  its  objective,  or  it  will  only  be  able  to  attain  it  at  unnecessarily  high 
costs.  The  latter  would  for  instance  be  the  case  where  ill-designed  capacity 
products  have  the  effect  of  unnecessarily  restricting  participation  to  the 
mechanism. 

(417)  In  view of the importance of capacity product design for the  appropriateness of 
capacity  mechanisms,  this  section  provides  an  overview  of  the  obligations  and 
penalties found in the capacity mechanisms included in the inquiry and seeks to 
identify the impacts that they have. 

5.4.2

  Findings of the sector inquiry 

(418)  All  of  the  capacity  mechanisms  covered  by  the  inquiry  include  some  kind  of 
obligation  to  ensure  the  recipients  of  capacity  payments  do  something  to 
contribute  to  security  of  electricity  supply.  However,  these  range  from  a  very 
basic obligation to build and operate a power station, through obligations linked 
to  fulfilling  instructions  from  the  TSO  (e.g.  turn  on  and  generate),  to  more 
complex obligations (e.g. reliability options requiring financial paybacks when a 
strike  price  is  exceeded  by  a  reference  price).  There  is  also  a  wide  range  of 
penalties.  Some  mechanisms  simply  exclude  capacity  providers  from  receiving 
future  payments  if  they  fail  to  meet  their  obligations,  but  most  require  capacity 
providers to return the payments earned or even pay an additional penalty on top 
of this. 

5.4.2.1

 Obligations  

(419)  To some extent the design of the capacity product depends on the type of capacity 
mechanism, but there are various common features of the obligations imposed on 
capacity providers. 

Period of obligation  

(420)  Some  capacity  mechanisms  require  capacity  providers  to  fulfil  obligations  all 
year  round  whenever  needed,  as  in  the  German  network  reserve  or  the  British 
capacity mechanism. Others only require capacity to fulfil obligations during the 
winter  when  electricity  demand  is  generally  highest.  In  the  Swedish  strategic 
reserve,  capacity  must  be  available  between  16  November  and  15  March  each 
winter. In Italy the TSO defines the 'critical days' during which capacity providers 
must  be  available  in  advance  of  each  delivery year.  In  France,  the  obligation  is 

125 

 
 
even  more  limited,  since  capacity  providers  are  only  obliged  to  make  their 
capacity  available  in  specific  hours  where  demand  is  highest.  These  hours  can 
take place in a maximum of 25 days a year, and are announced day ahead by the 
TSO. 

Nature of obligation 

(421)  In  strategic  reserves  the  obligation  for  participating  capacity  providers  is 
normally  to  deliver  electricity  when  instructed  by  the  system  operator  by 
generating  electricity  or  reducing  demand.  And  the  initial  trigger  event  for  the 
system operator to do this is often the day-ahead market not clearing. 

(422)  In the proposed French de-central obligation scheme certified capacity providers 
must  ensure  they  make  their  capacity  available  in  peak  demand  hours,  and 
suppliers must ensure their demand in these hours is either reduced or covered by 
capacity certificates. 

(423)  In the schemes proposed for Ireland and Italy, the capacity product is a reliability 
option.  The capacity  provider  will  receive  a  regular  payment  (in  the Italian  and 
Irish sytems, the clearing price set in the relevant capacity auction). In return for 
this regular payment, the capacity provider that has sold a reliability option will 
be  required  to  pay  the  difference  between  a  market  reference  price  and  a  strike 
price whenever the reference price goes above the strike price. 

Figure 30: Overview of reliability option 

Source: Commission for Energy Regulation (Ireland) and Utility Regulator (Northern Ireland) 

(424)  A  reliability  option  does  not  in  itself  create  a  direct  obligation  for  the  capacity 
provider having sold the option to do anything particular in the electricity market. 
However, the potential paybacks under the option mean the capacity provider has 
a strong incentive to make sure he sells electricity at the reference price so that he 
has  revenues  to  make  any  required  contract  paybacks.  The  extent  to  which  a 

126 

 
 
 
reliability  option  product  provides  incentives  for  flexibility  depends  on  the 
reference market chosen for the option contract, and the ability of this market to 
signal scarcity. The reliability option capacity product also allows consumers to 
be  protected  from  potential  high  electricity  prices  at  times  of  scarcity,  since  all 
capacity contracted in a capacity mechanism with a reliability option product will 
have  to  payback  any excess revenues  from  the  sale  of  obligated  capacity  above 
the reliability option strike price.  

(425)  In Italy, the reference market is a basket of the day-ahead and ancillary services 
markets.  In  addition  to  the  payback  requirement  of  the  reliability  option, 
participants will also be obliged to place bids in the day-ahead market for 100% 
of their contracted capacity. Any contracted capacity not taken in the day-ahead 
market  must  then  be  bid  into  the  ancillary  services  market.  This  is  designed  to 
enable  a  reference  to  the  ancillary  services  market  which  should  provide  better 
signals  of  scarcity  than  the  day-ahead  market,  while  ensuring  the  day-ahead 
market remains liquid.140 

(426)  In  the  2003  Irish  tender  capacity  mechanism,  selected  generators  were  granted 
Capacity and Differences Agreements (CADA). These function in a similar way 
to  reliability  options,  since  when  the  market  price  is  superior  to  the  strike  price 
defined in the CADA the beneficiaries must reimburse the difference between the 
market reference price and the strike price.  

(427)  In  the  French  tender  for  new  capacity  in  Brittany,  the  premium  paid  to  the 
beneficiary for being available is  fixed and revenues generated from the sale of 
electricity on the market are not taken into account. 

Notice period 

(428)  The  definition  of  a  capacity  mechanism  obligation  often  features  a  warning  or 
notice  period  so  that  capacity  providers  have  a clear  signal  to  start  warming  up 
ready  to  deliver  electricity  when  they  are  needed.  In  strategic  reserves  (for 
example  in  the  existing  Belgian,  Polish  and  Swedish  schemes  and  the  on  hold 
Danish scheme), participants are obliged to run when instructed to do so by the 
system operator, but receive a varying notice period. In Poland contracted plants 
must  be  able  to  start  generating  their  full  output  within  maximum  17  hours;  in 
Sweden within 16 hours (while demand response receives 30 minutes' notice); in 

140   Without the obligation to bid day ahead, participants may withhold their capacity until closer to real time to try 
and ensure they have sold sufficient electricity at the reference price that they can afford to make any required 
paybacks. 

127 

 
 
                                                 
Denmark  within  10  hours;  and  in  Belgium  normally  within  6.5  hours141  (while 
demand response receives 8 hours' notice).  

(429)  In market wide mechanisms it is not necessary to have a central notice period and 
in  some  designs  participants  are  required  to  react  to  market  forces.  This  is  for 
instance  the  case  in  the  planned  mechanisms  in  Ireland  and  Italy  where 
participants  will  simply  have  to  repay  the  difference  between  the  market 
reference price and the reliability option strike price whenever the reference price 
exceeds the strike price. This means they have to judge for themselves the risk of 
high reference prices and be warmed up and ready to deliver when necessary. By 
contrast, a notice period is included in the French capacity mechanism: the hours 
during which generators and demand response operators should be available are 
communicated by the TSO day-ahead.  

Limitations on use 

(430)  A capacity product could simply oblige all remunerated capacity to be provided 
whenever needed and for as long as needed at any time throughout the period of 
obligation  (e.g.  the  year  or  the  winter).  This  is,  for  instance  the  case  for  the 
Portuguese  availability  incentive  mechanisms.  However,  many  designs  include 
limitations on the number of times a resource can be called, and/or the duration 
for which a resource may have to provide its capacity continuously. In the Polish 
strategic  reserve  for  example,  the  system  operator  can  only  require  capacity 
providers to start from cold a maximum of 5 times per week, and resources are 
only obliged to provide power for a maximum of 8 hours per day. There are also 
maximum  activation  durations  in  the  Belgian  strategic  reserve.  In  the  Italian 
targeted  capacity  payment  mechanism,  capacity  providers  are  required  to  be 
available only during 'critical days' defined in advance by the TSO. There are also 
often different rules specific for demand response (see sub-section 5.4.3.2). 

Testing 

(431)  Most  capacity  mechanisms  include  the  potential  for  testing  by  the  system 
operator to ensure that contracted resources are actually capable of meeting their 
obligations even in years when there are no periods where obligations apply. This 
can be performed as a precondition for participation to the mechanism, and while 
the mechanism is in place, to test that the selected providers remain able to meet 
their obligations. 

141   This is the maximum time allowed by the TSO, but justified deviations may be possible. 

128 

 
 
                                                 
(432)  The  testing  of  capacities  during  the  capacity  mechanism  is  for  instance  done  in 
the French de-central obligation scheme, the Spanish interruptibility scheme and 
the  Portuguese  availability  payments  scheme.  Demand  response  providers 
replying  to  the  sector  inquiry  also  insisted  on  the  barrier  to  entry  that  could  be 
created  by  excessive  testing  of  demand  reduction  capacity.  They  argue  that  the 
impact  of  testing  the  availability  of  power  plants  is  not  comparable  to  that  of 
testing  demand  reduction  services,  since  in  the  latter  case  effective  demand 
curtailment is required. 

New projects  

(433)  Capacity mechanisms can also include penalties and/or require collateral related 
to  the  building  of  new  capacity  on  time.  In  the  French  de-central  obligation 
scheme,  for  example,  new  demand  response  capacity  must  deposit  a  bank 
guarantee in order to be certified. In Brittany, if the beneficiary does not make the 
plant operational on time, penalties apply. In the planned Irish scheme, a range of 
physical and financial requirements for bidders intending to develop new capacity 
are being considered, in view of the risk that they fail to deliver or bid without a 
firm intention to actually make the capacity available. Possible requirements are 
the need to demonstrate that the plant can connect to the grid in time, that it has 
the necessary planning consents, a sound business plan and a sufficient level of 
creditworthiness. 

5.4.2.2

 Penalties 

(434)  Once the capacity obligation has been defined, to ensure capacity providers have 
incentives to meet their obligations it may also be necessary to design penalties 
that will apply if the obligation is not fulfilled. These can be implicit penalties – 
for instance the need to pay back the difference between the strike price and the 
reference  price  in  mechanisms  where  the  product  is  a  reliability  option  –  or 
explicit penalties which can be charged in case the obligation is not met.142 

(435)  Generally,  in  the  Member  States  that  apply  explicit  penalties,  it  is  rare  for 
participants  to  be  able  to  lose  100%  of  the  remuneration  they  receive  from  the 
various schemes. There are however some exceptions. 

(436)  In  the  Spanish  'availability  incentive'  capacity  payments  scheme,  beneficiaries 
can  lose  up  to  75%  of  payments  through  penalties,  and  will  be  ineligible  for 

142   There can even be positive incentives, which allow for an extra payment on top of electricity  revenues and the 
capacity  payment.  This  can  be  a  useful  way  to  correct  for  any  inaccuracy  in  the  intial  'de-rating'  applied  to  a 
capacity  provider,  since  penalties  and  extra  payments  can  adjust  the  overall  level  of  capacity  remuneration  a 
capacity provider receives based on their actual performance. 

129 

 
 
                                                 
future  years  if  less  than  60%  of  remunerated capacity  was  available  on  average 
over the previous year. By contrast, in both of the Portuguese capacity payment 
schemes, plants that are available less than 70% of the time will lose their entire 
remuneration  and  providers  that  consistently  fail  to  meet  their  obligations  can 
eventually be excluded from the mechanism. 

(437)  Also in the on hold Danish strategic reserve capacity providers that consistently 
failed  to  meet  their  obligation  could  have  lost  100%  of  the  remuneration  they 
received from the scheme through penalties. Providers could also have lost more 
than this since they potentially faced imbalance penalties on top of their capacity 
mechanism  penalties  if  they  did  not  deliver  their  contracted  strategic  reserve 
when called by the TSO.  

(438)  In  the French de-central obligation mechanism, a  capacity imbalance settlement 
mechanism  is  used  to  incentivise capacity  providers and  suppliers  to  fulfil  their 
obligations. For the imbalance settlement, the volume of imbalances per capacity 
provider/supplier is multiplied by the reference capacity price, increased (in case 
of  negative  imbalances)  or  decreased  (in  case  of  positive  imbalances)  by  a 
correction  coefficient  meant  to  disincentive  imbalances.  In  case  there  is  a 
structural  negative  imbalance  of  capacities  (exceeding  2  GW  overall),  an 
administrative  reference  price  (in  essence  a  penalty)  is  applied  to  all  negative 
imbalances. This price is intended eventually to reflect the CONE of an OCGT. 

(439)  In the planned Italian central buyer mechanism, capacity providers face a number 
of penalties for failure to make bids in the reference markets corresponding to the 
whole of their contracted capacity. In addition to paying the difference between 
the  reliability  option  reference  price  and  strike  price,  they  will  not  receive  the 
capacity payment for the whole month in which they did not fulfil their bidding 
obligation.  Furthermore,  in  case  of  a  prolonged  failure  to  meet  the  bidding 
obligation,  capacity  providers  will  have  to  pay  back  capacity  premiums  already 
received.  Additional  penalties  apply  if  beneficiaries  fail  to  pay  back  the 
difference  between  the  strike  price  and  the  reference  price.  This  means  that 
capacity providers could face penalties that are potentially much higher than the 
total capacity remuneration received. 

(440)  In  almost  all  of  the  Member  States  included  in  the  sector  inquiry  that  apply 
explicit penalties, these do not appear to be linked to VOLL or CONE. The only 
exceptions are Italy, where the value of lost load has been identified to be 3,000 
EUR/MWh  and  the  reference  price  could  potentially  rise  to  this  level,  and  the 

130 

 
 
new  French  mechanism,  where  the  penalty  for  capacity  certificates  imbalance 
will rise to CONE.143 

Bridging the gap between the auction and delivery period 

(441)  Where auctions are held many years in advance of the delivery period, there is a 
bigger  risk  that  plants  fail  to  remain  in  the  market  to  deliver  their  obligations 
because market circumstances can change. In Britain, wholesale prices and clean 
spark  and  particularly  dark  spreads  deteriorated  to  such  extent  in  the  period 
between  the  first  T-4  auction  and  delivery  year,  that  capacity  having  secured 
contracts  in  the  first  T-4  auction  nevertheless  decided  to  close,  since  their 
expected  losses  (sometimes  greatly)  exceeded  the  non-delivery  penalties  they 
faced. This in turn led the UK authorities to substantially revise its penalty regime 
upwards.  These  closures  risk  higher  costs  for  consumers  where  replacement 
capacity  has  to  be  procured  in  a  tighter  market  with  a  shorter  lead  time. 
Thisexperience illustrates the importance of sufficient deterrents to non-delivery. 

Allowable exceptions  

(442)  Penalties could  be  applied  immediately  and  for any  lack  of delivery  against the 
obligation.  However,  there  are  usually  exceptions  to  the  obligation  that  reduce 
risk for capacity providers.  

(443)  The  on  hold  strategic reserve in  Denmark  would  not  have  imposed  penalties so 
long as at least 85% of the capacity called by the system operator was delivered 
(though  electricity  imbalance  settlement  penalties  would  still  have  applied). 
Under the Spanish 'availability incentive', capacity providers only need to prove 
that  90%  of  the  capacity  receiving  availability  payments  was  available  in  peak 
periods. 

(444)  In  Poland,  capacity  providers  in  the  strategic  reserve  are  allowed  up  to  1440 
hours of planned outages in every two consecutive years, and up to 360 hours of 
unplanned  outages  each  year  before  any  penalties  are  due.  In  the  Swedish 
strategic  reserve,  generation  capacity  providers  in  the  strategic  reserve  must  be 
available for at least 95% of winter hours to avoid penalties. Similarly in Brittany 
the  new  plant  needs  to  be  available  for  95%  of  the  time,  whereas  in  the 
abandoned Belgian tender an 80% availability during winter was required. In the 
on hold  Danish  strategic reserve, capacity providers would have  to  be  available 
for 90% of overall hours in a year. 

143   Note  in  reliability  option  schemes  the  penalty  would  be  linked  to  VOLL  if  the  introduction  of  the  capacity 

mechanism was accompanied by market reforms allowing the reference price to rise to VOLL. 

131 

 
 
                                                 
(445)  Note  in  many  schemes  aspects  of  obligation  design  already  effectively  build  in 
exceptions before penalties apply – for example the notice period and limitations 
on use (see section 5.4.2.1 above). 

5.4.2.3

 Reform of capacity products in the United States 

(446)  The capacity  mechanisms in  PJM and ISO New England,  which each include a 
market wide central buyer capacity mechanism, have both had the design of their 
obligations  and  penalties  overhauled  recently  in  response  to  lessons  learned 
during the 2013-2014 'polar vortex'.  

(447)  During the polar vortex a large proportion of contracted capacity was not actually 
able  to  deliver  when  it  was  needed  because  of  a  lack  of  firm  fuel  supplies  or 
failures  to  operate  due  to  the  cold  weather.  It  was  found  that  in  some  cases 
contracted  resources  preferred  to  pay  non-performance  penalties  than  expensive 
fuel  supplies.144  Since  these  events,  the  capacity  products  in  both  ISO-NE  and 
PJM  have  been  reformed  so  that  there  are  much  stronger  signals  for  delivery 
("pay for performance") of contracted capacity when it is needed. 

5.4.3

  Issues identified 

5.4.3.1

 Strong penalties help ensure security of supply and simplify other aspects 
of mechanism design, and do not necessarily increase the total system cost 

(448)  Capacity product design involves many complex detailed choices, and all of these 
combine to determine the level of security of supply it provides. As respondents 
to  the  consultation  noted,  capacity  providers  failing  to  meet  their  obligations 
should  face  'market-based'  penalties,  or  face  exposure  to  a  market  price. 
Particularly  as  markets  are  reformed  and  market  design  ensures  that  scarcity  is 
reflected  in  electricity  prices,  exposure  to  the  market  price  would  mean  that 
capacity providers 'penalties' would reflect the costs to consumers of the failure to 
meet the capacity obligation. In the absence of reformed market prices, or while 
reforms  are  underway,  penalties  linked  to  VOLL  are  required  to  provide  a 
similarly  strong  incentive.  Respondents  also  noted  that  more  stringent  penalties 
can  reduce  the  administrative  complexity  of  a  mechanism  because  they  reduce 
the importance of pre-qualification and physical checking. 

(449)  However, some consultation respondents also noted the need to ensure penalties 
did  not  reduce  participation  or  inflate  the  costs  of  procuring  capacity.  Capacity 
product design can be tweaked in many ways to adjust the level of risk faced by 

144   See: http://www.ausenergy.com/2014/02/the-illusion-of-reliability-ne-isos-capacity-market/  

132 

 
 
                                                 
capacity providers. Notice periods, caps on use and allowances for maintenance 
can all reduce the risks of participation, but they will tend to reduce the security 
of supply provided by the capacity mechanism.  

(450)  Where  the  problem  the  capacity  mechanism  is  targeting  is  clearly  seasonal  or 
linked to a problem that only occurs in specific hours, a shorter obligation period 
may be appropriate to reduce barriers to and risks of participation, and therefore 
reduce costs145. A more limited obligation period should also reduce the need for 
any exemptions related to the obligation, for example due to maintenance, since 
beneficiaries  should  be  able  to  schedule  planned  maintenance  outside  the 
obligation period. 

(451)  Any reduced security of supply from more lenient capacity product design must 
be considered against the potential risk and cost reduction for capacity providers, 
and potential increased participation and therefore competition in the mechanism 
which could reduce its costs. However, it is also important to bear in mind that 
more  limited  capacity  mechanism  obligations  may  mean  that  more  ancillary 
services or additional measures are needed to ensure security of supply, alongside 
the capacity mechanism. The whole system cost must therefore be considered. 

5.4.3.2

 Capacity products risk to distort electricity prices causing overcapacity 

(452)  Capacity  mechanisms  usually  have  a  close  link  with  electricity  prices,  since 
electricity prices rise to provide a signal that there is scarcity in the market and it 
is at these times that the capacity contracted through the capacity mechanism is 
needed most.  

(453)  Once capacity mechanisms are introduced they will – in most cases – reduce the 
extent to which local electricity prices remunerate capacity. Capacity will be fully 
or partially rewarded separately through capacity remuneration. Most aspects of 
capacity  product  design  will  not  impact  on  cross  border  electricity  market 
functioning,  but  if  a  capacity  product  includes  an  obligation  that:  i)  pays  or 
penalises 
capacity  delivered 
(payments/penalties  per  MWh);  or  ii)  that  introduces  a  price  cap  in  the  market, 
then there is a greater risk of distortions to market functioning.  

capacity  providers  on 

the  basis  of 

145   A particularly time-limited obligation like that chosen in France and Italy can also increase 

participation, particularly by demand response providers which may struggle to provide capacity over 
longer durations. 

133 

 
 
                                                 
(454)  Implicit  market  price  caps  could  for  example  potentially  be  set  by  a 
reliuncloearability option strike price that leaves no incentives for bidding above 
that  level.  However,  any  capacity  able  to  bid  exceed  its  capacity  mechanism 
obligations in a particular period – for example by generating more than the de-
rated  capacity  for  which  it  sold  reliability  options  –  would  still  be  able  to  set 
higher prices than the strike price.  

(455)  Where  capacity  penalties  provide  an  incentive  for  the  delivery  of  required 
electricity  when  needed,  these  penalty  signals  may  be  considered  to  replace  the 
signals  the  electricity  market  would  otherwise  need  to  provide  for  delivery  of 
electricity  at  the  right  times.  However,  if  a  capacity  mechanism  acts  as  a 
replacement  for  high  electricity  prices  at  times  of  scarcity,  there  will  not  be  an 
efficient  signal  for  imports  to  the  Member  State  having  implemented  that 
capacity mechanism at times of need. Nor will there be an efficient incentive for 
demand  response  participation  in  the  electricity  market  outside  the  capacity 
mechanism. 

134 

 
 
Box 3: The 'slippery slope' effect 

A strategic reserve that is dispatched before possibilities for the market to match supply 
and demand have been fully tested can also act as a cap on market prices. This risk can 
be  avoided  by  dispatching  the  reserve  only  when  the  market  has  failed to  clear  despite 
prices  reaching  an  appropriate  wholesale  market  price  cap.  This  should  still  enable 
capacity  providers  outside  the  reserve  to  receive  scarcity  prices  and  therefore  enable 
peaking plants to earn their fixed costs. If the reserve is dispatched more frequently or if 
in  times  when  the  reserve  is  dispatched  the  market  price  is  not  set  to  the  cap,  then  the 
reserve  will  have  created  additional  missing  money  by  reducing  the  possibility  of  high 
market prices.  

Where  missing  money  remains  in  the  electricity  market  and  is  only  corrected  for 
beneficiaries of the reserve, there is the potential for a strategic reserve to become bigger 
and  bigger  as  more  plants  close  or  threaten  to  close  unless  they  are  included  in  the 
strategic reserve (sometimes called the slippery slope effect). This effect seems to have 
occurred in Belgium where for winter 2014-2015 the government initially mandated the 
TSO  to  contract  800 MW  of  strategic  reserve,  which  was  already  four  months  later 
increased  to  1,200 MW146,  while  for  winter  2015-2016  the  government  mandated  the 
TSO  to  contract  a  reserve  totalling  3,500 MW  (i.e.  23.8%  of  total  operational  installed 
capacity  in  Belgium  in  2014)147.  Also  the  German  Network  Reserve  increased  from  an 
initial 1.4 GW in 2012/2013 to 4.8 GW for the winter of 2015/2016. 

In Sweden, the reserve has actually become smaller over time – shrinking from 2 GW to 
1  GW.  However,  it  has  not  so  far  proved  to  be  a  transitional  intervention.  The  reserve 
was introduced in 2003 and is still in place in spite of plans to phase it out. In 2015, the 
public authorities have announced to extend its duration once more from 2020 to 2025.  

A  linked  problem  identified  for tender  mechanisms  is  the  'wait  for tender'  issue, where 
potential  investors  may  prefer  to  wait  for  a  tender  to  be  launched  than  invest  in  the 
market. 
(456)  Given  the  importance  of  electricity  prices  as  a  signal  for  efficient  electricity 
imports  and  exports  within  the  Single  Market,  where  capacity  mechanism 
penalties  replace  electricity  scarcity  prices  fewer  imports  at  times  of  scarcity 
would be expected than would otherwise have been the case. This risks creating 
an  additional  distortion  since  where  fewer  imports  are  expected  additional 
domestic  capacity  will  need  to  be  procured  through  the  capacity  mechanism. 
Ultimately  this  would  mean  capacity  mechanisms  lead  to  too  much  capacity 
being procured and mean the full benefits of the Single Market would be missed. 

146   A  total  of  850 MW,  consisting  of  750 MW  of  generation  reserves  and  100 MW  of  demand  response  reserves, 

147  

was finally contracted. 
In reality only 1535.5 MW, consisting of 1177.1 MW of generation reserves and 358.4 MW of demand response 
reserves, could be contracted. Note that for Winter 2016/2017 the size of the Strategic Reserve was decreased to 
750MW given the improved generation adequacy situation due to the increased availability and the prolongation 
of the lifetime of the nuclear power plants in Belgium.  

135 

 
 
                                                 
 
(457)  The  risk  of  distortions  can  be  reduced  by  ensuring  that  the  electricity  market 
continues to function effectively – including by sending the right signals for short 
term dispatch (and to a large extent therefore also for investment in flexibility) – 
regardless of the introduction of a capacity mechanism. As underlined in Chapter 
2,  it  is  important  to  realize  the  necessary  reforms  to  the  electricity  market  that 
enable these short term signals.  

(458)  The capacity product too will need to be designed carefully to coexist with high 
electricity scarcity prices and avoid taking too much of the scarcity signal out of 
the  electricity  price  (and  yet  also  to  ensure  an  incentive  effect  on  capacity 
providers).  

5.4.3.3

 Benefits of reliability options  

(459)  The reliability option capacity product can be particularly valuable for coexisting 
with  high  electricity  scarcity  prices  because  it  leaves  market  signals  intact  and 
once  scarcity  pricing  is  implemented  does  not  require  an  additional  penalty  for 
non-delivery to be provided through the capacity mechanism. 

(460)  An  additional  benefit  of  the  reliability  option  product  is  the  hedge  it  provides 
consumers.  Because  paybacks  are  required  to  be  made  by  capacity  providers 
whenever electricity prices rise above the reliability option strike price, capacity 
providers cannot earn windfalls from a combination of capacity remuneration and 
electricity  scarcity  prices.  This  can  be  particularly  valuable  where  the  capacity 
mechanism  offeres  long  commitment  periods  –  over  which  it  is  difficult  to 
anticipate electricity revenues. This protection could also help enable a capacity 
mechanism to limit opportunities for the abuse of market power in the electricity 
market because if prices are inflated above the strike price then paybacks will be 
required  from  capacity  providers.  These  features  of  reliability  options  can  help 
give  policy  makers  the  confidence  to  implement  market  reforms  that  enable 
the  capacity 
appropriate  scarcity  pricing  alongside 
mechanism. 

introduction  of 

the 

5.4.3.4

 Specific products for demand response  

(461)  Demand  response  is  often  treated  differently  to  generation  within  the  various 
mechanisms included in the sector inquiry, for example because it is not always 
possible for demand response to bid in the electricity market and earn electricity 
revenues in the same way as a generator, and because of the need to establish a 
consumption baseline from which to measure the amount of energy delivered by 
demand response capacity.  

(462)  There  are  also  often  limitations  on  the  obligations  for  demand  response,  for 
example  a  more  limited  number  of  required  consecutive  hours  of  capacity 

136 

 
 
delivery148.  Some  consultation  respondents  pointed  out  that  such  discrimination 
should  always  be  avoided,  since  preferential  rules  for  demand  response  may 
mean demand response is selected for support in capacity mechanisms ahead of 
more  competitive  generation.  However,  these  differences  may  be  justified  since 
they  help  support  the  development  of  demand  response  and  should  allow  it  to 
play an increasingly significant role in the electricity markets of the future. This 
discrimination  in  favour  of  demand  response  in  particular  may  be  justifiable 
because  it  is  a  lack  of  demand  response  that  contributes  to  the  market  failures 
targeted  by  a  capacity  mechanism.  By  targeting  the  long  term  development  of 
demand response, a capacity mechanism can therefore help to ensure the market 
develops so that the mechanism is not required in the longer term. However, any 
different treatment between capacity providers needs to be carefully considered to 
avoid any unjustifiable discrimination. 

(463)  The  sector  inquiry  has  furthermore  revealed  that  certain  types  of  capacity 
mechanism  may face  very  specific  challenges  to optimise full  demand response 
participation, by reason of their set-up. As such, the supplier obligation developed 
in France required specific design solutions to accommodate two different types 
of demand response participation: implicit and explicit participation. The former 
refers  to  the  reduction  of  the  supplier  obligation  through  "management"  of  – 
mostly residential and SME – demand by electricity suppliers, whereas the latter 
refers  to  the  direct  participation  of  large  industrial  users  and  demand  response 
aggregators  to  the  mechanism,  often  through  the  certification  of  their  capacity. 
Since  the  French  authorities  specifically  wanted  to  encourage  also  implicit 
demand  response  participation,  the  availability  obligation  for  both  types  of 
demand response differed. 

(464)  Finally, in Member States where interruptibility schemes – capacity mechanisms 
that limit participation to DSR only – are in force, these often co-exist alongside 
other,  more  open  capacity  mechanisms,  such  as  market-wide  capacity 
mechanisms  (France,  Italy)  or  strategic  reserves  (Germany).  These  other 
mechanisms may equally be open to DSR, giving demand response operators the 
choice to participate in either one of the schemes. For instance, an interruptibility 
scheme may be dispatched on a regular basis, whereas a strategic reserve is only 
dispatched in exceptional scarcity situations; depending on the business in which 
the consumer is involved it may opt for one or the other mechanism.  Where the 
capacity  product  obligation  in  an  interruptibility  scheme  does  not  overlap  with 

148   Testing rules may also need to differ to ensure that demand response is not disadvantaged (though it 
will be important to ensure that testing is sufficient to deliver confidence that all contracted resources 
will be there in the hours they are needed). 

137 

 
 
                                                 
the capacity product obligation in a market-wide mechanism, operators should be 
able to offer their capacity in both schemes. However, as an integrated approach 
is  generally  better  because  it  increases  competition,  a  proper  assessment  of  the 
impacts  of  the  simultaneous  existence  of  more  than  one  mechanism  should  be 
carried out.  

5.4.4

  Conclusions 

(465)  Capacity  product  design  involves  a  trade  off  between  the  level  of  security  of 
supply achieved and the cost of the capacity mechanism. But whole system costs 
should  be  considered  when  making  this  trade  off  because  lenient  capacity 
mechanism obligations and penalties may increase the cost of ancillary services, 
or mean other interventions are required, to ensure security of supply. 

(466)  Obligations requiring the verifiable availability or delivery of capacity resources 
in  (potential)  scarcity  situations  are  necessary  to  encourage  investment  in 
sufficiently flexible and reliable capacity.  

(467)  Unless these obligations are backed by penalties in which it is possible to lose at 
least  as  much  as  you  gain  from  the  capacity  mechanisms,  there  may  be  an 
insufficient  incentive.  Testing  may  also  be  required  if  the  use  of  the  capacity 
mechanism is expected to be limited to very occasional situations. 

(468)  There is a potential tension between capacity mechanism penalties and electricity 
scarcity prices, since both provide incentives for investment in flexible capacity, 
and  the  overall  incentive  for  flexibility  should  not  be  more  than  VOLL.  The 
design of the capacity product should ensure the majority of signals for flexibility 
remain  in  the  (increasingly  reformed)  electricity  market,  so  that  the  electricity 
market  provides  efficient  signals  for  electricity  imports  and  demand  response 
even once a capacity mechanism has been introduced.  

(469)  The  reliability  option  product  can  be  particularly  useful  in  this  regard  since  it 
leaves  market  signals  intact  and  once  scarcity  pricing  is  implemented  does  not 
require an additional penalty for non-delivery to be provided through the capacity 
mechanism. 

(470)  Reliability option capacity products also protect against the potential for capacity 
providers to be  overcompensated  from a combination of capacity payments and 
electricity market revenues. 

(471)  In  the  mechanisms  that  include  demand  response  there  are  usually  different 
obligations  for  demand  response  than  for  generation.  Because  of  the  long  term 
benefits  of  demand  response,  some  differentiation  in  obligations  and  penalties 

138 

 
 
between generation and demand response is justifiable in the short term to enable 
the development of demand response. 

139 

 
 
 
 
6. 

ASSESSMENT OF THE VARIOUS TYPES OF CAPACITY MECHANISMS 

(472)  Drawing  upon  the  arguments  presented  and  discussed  throughout  this  Report, 
Chapter 6 considers, within the framework of State aid assessment, to what extent 
each of the types of capacity mechanism identified in Chapter 3 may be able to 
address well-defined generation adequacy problems.  

(473)  The designs of capacity mechanisms vary widely, but all provide public support 
for  capacity  providers  and  thus  they  may  fall  within  the  category  of  state  aid 
measures.  They  can  therefore  be  subject  to  the  European  Union's  rules  on  state 
aid  and  their  compatibility  with  these  rules  may  have  to  be  assessed  by  the 
Commission. State aid principles provide an appropriate framework to assess the 
need  for  capacity  mechanisms,  their  ability  to  address  potential  capacity 
shortages, as well as their potential market distortions. 

(474)  First, in assessing the potential compatibility of State aid measures it is necessary 
to  clearly  identify  the  objective  to  be  pursued.  As  explained  in  Chapter  3, 
capacity  mechanisms  have  the  general  objective  of  contributing  to  security  of 
electricity supply. However, in order to prove the necessity of State aid, Member 
States need to provide further justification beyond stating this general objective. 
There should be a detailed adequacy assessment which identifies, among others, 
the amount, type, duration and location of the capacity needs. 

(475)  As discussed in Chapter 4, linking the reliability standard to the value consumers 
place on being supplied with electricity, means that an economic efficient level of 
protection  is  set  and  that  expensive  and  distortive  overprotection  is  avoided. 
Therefore, a reliability standard based on VOLL should be the basis for guiding 
any intervention in the market with the aim of ensuring security of supply.  

(476)  Once  Member  States  clearly  identify  their  adequacy  problem,  State  aid  rules 
provide  a  framework  for  assessing  the  possible  positive  and  negative  effects  of 
the public intervention. Public support should be designed in the most appropriate 
way  to  tackle  the  adequacy  problem  and  to  minimize  potential  distortions  to 
competition and trade in electricity markets.  

(477)  The  remainder  of  this  Chapter  is  structured  as  follows.  Section  6.1  recaps  the 
actions  needed  to  establish  the  necessity  for  a  capacity  mechanism.  Section  6.2 
discusses one by one the various types of capacity mechanisms, considering their 
appropriateness to address particular adequacy concerns and the possible market 
impacts  arising  from  their  implementation.  This  high-level  assessment  draws 
upon  best  and  worst  practices  identified  in  the  sector  inquiry.  Section  6.3 
provides an comparative overview of the types of capacity mechanisms identified 
in the sector inquiry in light of their suitability to different problems. Section 6.4 

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discusses  the  link  between  the  objective  of  ensuring  security  of  supply  and  the 
one of decarbonisation and Section 6.5 concludes this final chapter. 

6.1 

Necessity for intervention through a capacity mechanism  

(478)  As explained in Chapter 2, a number of market and regulatory reforms have been 
proposed and are being implemented to varying degrees in some Member States 
to address concerns about electricity generation adequacy and security of supply. 
Well-functioning markets have the potential to reduce the need for intervention in 
the form of capacity mechanisms. Nonetheless, Member States may still consider 
it necessary to implement capacity mechanisms.  

(479)  While  capacity  mechanisms  can  be  justified  when  a  residual  missing  money 
problem is identified, they cannot replace the reforms pending to make electricity 
markets more efficient. Each of the opportunities for reform identified in Chapter 
2 are at the very heart of the effort, both at national and European level, to bring 
about more efficient markets that provide reliable electricity to consumers at the 
least possible cost. These reforms will allow exploiting as much as possible the 
potential  of  competitive  markets  to  efficiently  deliver  reliable  electricity  to  the 
benefit of final consumers. These reforms can therefore be neither neglected nor 
delayed. 

(480)  Correcting  market  and  regulatory  failures  that,  to  a  large  extent,  contribute  to 
erode  incentives  to  invest  in  capacity  will  reduce  the  concerns  about  the 
reliability  of  EU  electricity  system.  It  will  also  reduce  the  need  for  additional 
interventions  like  capacity  mechanisms,  minimising  potential  market  distortions 
and saving public resources. Finally, with or without a capacity mechanism these 
reforms enable the price signals needed for efficient cross border energy trading, 
and  provide the most  efficient  signal for investment in  the  right  mix  of  flexible 
capacity  to  fulfil  the  needs  of  the  system.  Therefore,  advancing  in  the  market 
reforms discussed above is warranted irrespective of whether the implementation 
of  any  capacity  mechanism  is  planned,  and  irrespective  of  the  type  of  capacity 
mechanism envisaged. 

(481)  As discussed in Chapter 4, the necessity of intervention should be established by 
determining  the  necessary  generation  capacity  that  cannot  be  expected  to  be 
provided by the market, even after alternative measures have been considered.  

(482)  Establishing  the  necessity  for  state  intervention  is  an  essential  step  in  the 
assessment of compatibility of any capacity mechanism with State aid rules. An 
accurate  generation  adequacy  assessment  will  identify  in  detail  the  particular 
circumstances  of  each  electricity  market  and  the  need  for  additional  capacity, 
including  the  amount  and  type  of  capacity  required,  the  timing  of  any  capacity 

141 

 
 
problems  and  any  particular  locational  capacity  needs.  For  example,  a  Member 
State can face a general capacity shortage, i.e. a systemic problem of insufficient 
investment in new capacity possibly resulting from various factors undermining 
price signals, risk aversion of investors, coordination failures or the public good 
nature of reliability. Other Member States have a local capacity shortage due to 
network  constraints  (cross-border  or  national)  that  cannot  be  addressed  in  due 
time  through  alternative  and,  in  the  longer-term,  more  appropriate  means,  for 
example by establishing appropriate bidding zones or investments in transmission 
infrastructure.  

6.2 

Appropriateness and market impacts for each type of mechanism 

(483)  The various capacity mechanisms identified in Chapter 3 can be more appropriate 
in  some  circumstances  than  in  others.  This  can  be  due  to  either  the  ability  of  a 
particular  type  of  capacity  mechanism  to  deal  with  certain  types  of  capacity 
shortage  or  to  other  market  impacts  particular  types  have.  Member  States  face 
different  sitiuations  because  of  the  various  stages  of  development  of  their 
electricity  market,  the  age  and  composition  of  their  generation  fleet.  In  each 
specific  case,  the  appropriateness  of  a  capacity  mechanism  to  address  a  well-
defined capacity need and its likely market impacts will have to be assessed. 

(484)  This  section  presents  some  tentative  conclusions  on  the  ability  of  each  type  of 
capacity  mechanism  to  address  potential  capacity  shortages  depending  on  the 
problem identified, including if it is expected to be temporary or more permanent, 
and location-specific or more general. It also discusses a number of likely market 
impacts  of  capacity  mechanisms,  especially  potential  crowding-out  effects149  on 
investment and impact on market structure. 

6.2.1

  Tenders for new capacity  

(485)  As  described  in  section  3.1.1,  in  a  tender  for  new  capacity  the  beneficiary 
typically receives financing for the construction of a power plant that would bring 
forward the capacity required to fill an identified gap.  

(486)  Tenders  for  new  capacity  have  been  used  in  Belgium,  Croatia,  France  and 
Ireland. In Belgium, the tender was intended to bring on new investment in gas-
fired  capacity.  In  Croatia,  a  tender  was  launched  to  attract  investment  in  a  new 
coal  plant  at  Plomin.  In  France,  the  tender  is  intended  to  bring  forward 
investment specifically in a new CCGT plant in Brittany, where there is a risk of 

149   The  crowding  out  effect  refers  to  the  potential  for  publically-supported  investments  to  reduce  the  potential  for 

independent / private investments that might otherwise have come forward. 

142 

 
 
                                                 
insufficient local capacity. In contrast, the tender launched in Ireland in 2003 was 
open to all types of thermal generation capacity. The Irish tender can be seen as 
designed  to  address  a  temporary  need  while  a  more  long-term  intervention  was 
developed,  namely  the  market  wide  capacity  payment  mechanism  (see  Section 
6.2.4 below) which was introduced in 2007. 

6.2.1.1

 Ability to address capacity shortages 

(487)  While a tender can ensure new generation capacity is built, the security of supply 
benefits it delivers may be offset by the impact the tender has on existing capacity 
in  the  market,  and  on  the  incentives  for  future  investment  not  supported  by  a 
tender.  

(488)  A  tender  can  attract  investment  in  a  particular  location.  This  is  an  attractive 
feature  of  the  model,  because  it  allows  policy  makers  to  implement  a  targeted 
solution  to  a  specific  locational  problem.  For  instance,  in  isolated  regions  the 
need  for  capacity  with  specific  capabilities  –  for  instance  to  maintain  grid 
stability  –  may  not  come  forward  through  market-based  investments  or  market-
wide interventions.  

(489)  A  tender  for  new  capacity  typically  also  has  the  advantage  of  providing  for  a 
relatively  quick  and  targeted  solution  to  add  new  capacity,  especially  when 
envisaged  market  reforms  that  alleviate  the  problem  are  known  to  take  time  to 
implement. In particular, although time will always be needed to construct a new 
power station, a tender is likely to take less time to develop and implement than a 
more  complex  market-wide  capacity  mechanism  and/or  reforms  to  implement 
appropriate bidding zones and scarcity pricing.  

(490)  However,  as  explained  in  sub-section  5.2.3.5,  a  tender  does  not  correct  the 
underlying  causes  of  a  capacity  shortage.  In  the  longer  term,  security  of  supply 
should  be  ensured  through  network  development  or  by  providing  appropriate 
incentives  for  local  investment  through  higher  electricity  and  ancillary  services 
prices  in  deficit  regions.  Where  the  requirement  is  for  a  local  ancillary  service, 
TSOs  should  in  general  seek  to  competitively  procure  the  required  services 
through  an  open,  market-based  competition,  without  the  need  for  Government 
involvement.  Moreover,  the  decision  of  the  location,  the  size  and  the  product 
requirements  of  the  desired  investment  is  taken  by  an  administrative  body  (for 

143 

 
 
instance the NRA or the ministry) instead of the market and therefore there is a 
risk that a suboptimal solution is pursued.150 

(491)  As seen in sub-section 5.4.2.1 (under "New projects"), to ensure timely delivery 
of  the  capacity  some  tenders  include  penalties  for  late  delivery  within  the 
beneficiary's  control.  Despite  the  potential  for  quick  implementation,  the  long 
contracts required to bring forward new investment (see sub-section 5.2.2.4) and 
in  some cases  the characteristics  of the particular technology benefitting from  a 
tender mean that this mechanism is likely to impact the market for many years.  

6.2.1.2

 Possible competition distortions and impact on market structure 

(492)  Tenders for new capacity produce a crowding-out effect, as can also be the case 
with  targeted  capacity  payments  and  strategic  reserves.  As  explained  in  sub-
section  5.2.3.4,  the  appearance  of  new  subsidised  generation  capacity  in  the 
market is likely to depress electricity prices, and so will reduce the profitability of 
other existing or planned capacity. As a consequence, some existing plants close 
sooner than they would otherwise have or some investments that would otherwise 
have taken place do not take place. This crowding-out effect can undermine the 
efficacy  of  tenders  for  new  capacity,  if  on  the  one  hand,  they  incentivise 
investment  by  their  beneficiaries,  but  on  the  other,  disincentivise  investment  by 
other capacity providers.  

(493)  A  tender  may  also  incentivise  opportunistic  behaviour  of  potential  investors. 
Once  the  national  authorities  show  that  they  are  prepared  to  subsidise  new 
investment,  investors  may  prefer  to  wait  for  a  future  tender  rather  than  invest 
purely on the basis of price expectations. As a result, tenders can either crowd out 
new  investment  that  would  otherwise  have  come  forward,  or  support  the 
financing  of  investments  that  might  have  taken  place  anyway,  undermining  the 
incentive  effect  of  the  measure.  A  tender  may  even  prompt  premature 
mothballing  or  closure  decisions  to  access  the  support  available  through  the 
tender – similar to the slippery slope effect identified for the strategic reserve. 

(494)  As  tender  procedures  typically  offer  long-term  contracts  they  provide  for 
relatively  great  investment  certainty  and  give  stronger  incentives  to  market 
entrants. By lowering barriers to entry, they may therefore limit the market power 

150   Some stakeholders have noted that it can be difficult to administratively choose the most efficient option because 
the all-in costs of different types of resources are difficult to compare and non-price terms can vary greatly. For 
example,  alternatives  can  vary  in  their  available  dispatch  duration  (more  limited  for  DSR  than  for  most 
generation sources), some options are more reliable than others, or some resources would be able to operate for 
many  more  years  than  others.  All  these  considerations  may  be  complex  to  be  taken  into  account  in    an 
administrative decision process. 

144 

 
 
                                                 
of  incumbents  and  increase  competition.  In  the  Belgian  tender,  the  authorities 
sought  to  incentivise  new  entry  by  applying  a  10%  award  criterion  to  take 
account  of  the  bidder's  contribution  to  competitive  market  functioning  in 
Belgium. In Brittany, the tender was awarded to a market entrant. In Ireland, the 
incumbent was not allowed to participate in the tender procedure and the capacity 
product was designed to limit the possibility of the tender beneficiaries exercising 
market power for the duration of  their tender contract  – see sub-section 5.4.2.1. 
However, although new entry can increase competition in the electricity market, a 
tender does not provide an enduring response to the potential to exercise market 
power by participants in that market.  

(495)  Although they are usually domestic, tenders typically have cross-border impacts. 
They  will  increase  domestic  capacity  and  therefore  reduce  opportunities  for 
imports. At the same time, they may slow down plans to improve connection with 
other geographic areas. 

6.2.1.3

 Conclusions on tenders for new capacity 

(496)  A  tender  for  new  capacity  may  be  an  appropriate  temporary  measure  to 
incentivise  investment  (including  in  a  specific  location)  and  offer  a  route  to 
market  for  new  entrants.  A  tender  can  be  implemented  relatively  quickly  even 
though it typically takes several years to realise new generation investments and 
it typically requires contract payments for several years.  

(497)  However, a tender does not effectively address longer term adequacy problems, 
and  is  likely  to  exacerbate  underlying  market  and  regulatory  failures  unless 
complementary  reforms  are  also  made.  Hence,  a  tender  can  be  an  appropriate 
instrument  to  bridge  the  time  towards  the  implementation  of  a  market-wide 
capacity mechanism. Once the market-wide capacity mechanism is implemented, 
it is generally more suitable to address local issues and stimulate new investment 
through that mechanism rather than through a tender. 

6.2.2

  Strategic reserves 

(498)  As  described  in  section  3.1.1,  in  a  strategic  reserve  mechanism  the  additional 
capacity  needed  on  top  of  what  the  market  is  expected  to  provide  is  contracted 
and  then  held  in  reserve  outside  the  market.  Capacity  in  strategic  reserves 
generally  does  not  participate  in  the  market  and  is  dispatched  only  in  case  the 
market  does  not  clear,  i.e.  when  there  is  a  danger  that  demand  will  outweigh 
supply. 

(499)  Examples of strategic reserves (excluding interruptibility schemes) exist in five of 
the Member States included in the sector inquiry: Belgium, Denmark, Germany, 
Poland  and  Sweden.  All  of  the  reserves  are  designed  to  keep  existing  power 

145 

 
 
plants  operational,  so  that  they  can  be  deployed  when  needed.  Reserves  are 
generally  only  dispatched  rarely  (at  most  a  few  times  a  year)  ,  but  the  German 
network reserve is dispatched more regularly, namely in times where internal grid 
congestion does not allow for the transmission from generation centres to demand 
centres.  

6.2.2.1

 Ability to address capacity shortages 

(500)  While strategic reserves ensure that back-up capacity is available, the security of 
supply  benefits  they  deliver  may  be  off-set  by  their  impacts  on  capacity  that 
remains in the market.  

(501)  Generally,  strategic  reserves  are  seen  as  an  instrument  to  keep  capacity  from 
exiting  the  market  and  to  develop  a  buffer  for  unforeseen  scarcity  situations. 
During  a  period  of  overcapacity,  as  currently  experienced  in  large  parts  of  the 
EU, market prices should give signals to prompt the closure of plants that are not 
required.  Strategic  reserves  can  be  used  where  there  are  good  reasons  that  the 
market does  not  (yet) deliver appropriate exit signals, to  manage market exit of 
conventional generation in a gradual way and prevent too many closures leading 
to  temporary  local  or  general  shortages.  In  market  areas  where  market  reforms 
are  still  in  the  early  stages  of  their  implementation  and  market  participants  are 
hesitant  to  invest  on  the  basis  of  price  signals  alone,  a  strategic  reserve  can 
provide  an  effective  transitional  measure  on  the  road  to  market-based  new 
investment inspired by market reforms.  

(502)  Strategic  reserves  can  also  be  designed  to  maintain  capacity  in  specific 
geographic  areas.  As  described  in  more  detail  in  sub-section  5.2.2.5,  some 
strategic  reserves  contract  capacity  located  in  specific  regions  within  the 
respective Member States.  

(503)  Whilst  strategic  reserves  are  able  to  address  temporary  shortages,  they  do  not 
address underlying market failures.  As with other targeted capacity mechanisms, 
the strategic reserves correct a missing money problem only for plants selected to 
participate in them. Nor does a strategic reserve used for a local capacity problem 
address  the  underlying  issues  that  originally  prevented  local  investment  and 
appropriate  incentives  need  to  be  provided  by  reformed  electricity  prices  (see 
sub-section 5.2.3.5 of this report). 

(504)  From a timing perspective, strategic reserves must be transitional measures in the 
sense  that  they  delay  the  closure  of  some  generation  capacity  and  accompany 
market reforms. Once the reforms are in place, the reserve should be phased out. 
Hence,  if  longer  term  reforms  require  time  to  implement  a  reserve  can  be 
appropriate  as  it  offers  an  immediate  option  to  prevent  existing  plants  from 

146 

 
 
shutting  down.  Moreover,  it  has  the  advantage  (see  next  sub-section)  that  its 
distortive  effects  can  be  limited  if  it  is  held  outside  the  market.  In  view  of  the 
objective of strategic reserves, generally there is no need for very long contracts 
(see  sub-section  5.2.2.4)  because  a  strategic  reserve  is  a  tool  for  managing  a 
situation of overcapacity and risks of premature exit of existing plants, rather than 
encouraging  new  investment.  In  market-wide  capacity  mechanisms,  long  term 
contracts  are  sometimes  used  to  allow  new  generation  to  compete  on  equal 
footing  with  existing  generation.  The  participation  of  new  capacity  and 
availability of long term contracts are inappropriate for a strategic reserve that is 
intended as a temporary means to manage market exit. Moreover, attracting new 
capacity  to  a  strategic  reserve  would  necessarily  require  the  organisation  of  a 
tender  for  new  capacity,  which  would  reinforce  the  'slippery  slope'  effect 
described  in  sub-section  5.4.3.2  since  it  could  cause  potential  investors  to  each 
time  await  a  tender  for  new  capacity  rather  than  invest  on  the  basis  of  market 
signals.151  

6.2.2.2

 Possible competition distortions and impact on market structure 

(505)  Strategic reserves are often held outside the market, which means that the plants 
in  the  reserve  cannot  run  and  sell  the  power  they  generate  in  the  market.  The 
market distortions that strategic reserves create are therefore in general less direct 
and  smaller  than  that  of  other  types  of  capacity  mechanisms,  such  as  capacity 
payments  or  market-wide  volume-based  mechanisms  that  foresee  payments  to 
plants in the market.  

(506)  Nevertheless, the risk that strategic reserves distorts the market does exist and is 
dependent mostly on the design of the mechanism. Reserves are typically called 
to  supply  electricity  when  market  prices  increase  above  a  certain  threshold, 
indicating  extreme  scarcity.  If  this  threshold  is  set  below  VOLL,  this  limits  the 
ability  of electricity prices  to increase in moments of scarcity and risk reducing 
incentives to invest in capacity which might, in turn, aggravate the initial capacity 
shortage.  Hence,  similarly  to  tenders  for  new  capacity  and  targeted  capacity 
mechanisms,  the  risk  of  a  crowding-out  effect  on  investment  exists,  reducing 
their ability to address a potential capacity shortage. As explained in sub-section 
5.4.3.3,  this  concern  can  be  effectively  addressed  through  a  design  that  ensures 
the reserve is only dispatched when the market fails to clear and setting market 
prices,  in  these  instances,  to  a  VOLL  price  cap.  Such  a  design  leaves  the 

151   These  considerations  do  not  apply  to  demand-side  response.  Where  existing  demand  becomes  flexible  and 
wishes to participate in a strategic reserve it should be allowed to do so. DSR does not require long investment 
lead times nor does it require long term contracts. Hence, the argument of providing the necessary competitive 
pressure  in  the  allocation  process  does  apply  to  DSR.  The  Swedish,  Belgian  and  planned  German  strategic 
reserves all allow for the participation of DSR. 

147 

 
 
                                                 
investment signals provided the electricity price intact. A strategic reserve design 
that  allows  high  electricity  scarcity  prices  to  form  is  also  important  to  avoid 
distortions of cross border markets, because imports will be attracted through the 
price signal.  

(507)  Even  if  the  reserve  is  only  dispatched  when  the  market  fails  to  clear,  investors 
have  expressed  the  concern  that  the  reserve  represents  an  additional  regulatory 
risk  because  the  national  authorities  may  be  tempted  to  change  the  rules  and 
dispatch the reserve more often, for example in response to a prolonged period of 
high electricity prices. Although investors will be best reassured by a track record 
of  non-intervention,  this  distortive  effect  can  be  partially  mitigated  by  clear 
communication  that the reserve is intended to be a small, temporary intervention. 
Only  the  highest  degree  of  regulatory  certainty  will  give  new  entrants  the 
confidence they need to invest. 

(508)  In addition to the crowding-out effect, a strategic reserve affects market structure 
if  it  creates incentives  for  plants  to  announce  closures  that would  not  otherwise 
have taken place, because the expected profitability for a certain plant is higher 
within  the  strategic  reserve  scheme  than  outside  the  scheme.  As  a  result,  the 
strategic  reserve  can  in  this  case  accelerate  exit  from  the  market.  Belgium 
provides a good example of how a strategic reserve can trigger this effect. Many 
troubled  generators  announced  their  closure  (legal  precondition  to  enter  the 
reserve) in order to be able to enter the reserve so that the demand for the reserve 
increased substantially from the first to the second year after its introduction (the 
'slippery slope' effect described in Box 3 in sub-section 5.4.3.3). This reduced the 
scope of the competitive  market. Moreover, in particular gas-fired  power plants 
(which  in  Belgium  are  the  main  production  segment  where  the  smaller 
competitors  to  the  incumbent  are  active)  risk  being  drawn  into  the  growing 
reserve.  This  can  have  additional  impacts  on  the  competitiveness  of  the 
underlying  electricity  market,  where  the  exit  of  plants  into  the  reserve  risks 
increasing market power (see section 5.5). 

(509)  Another  source  of  concern  arises  from  the  potential  ability  and  incentive  of  an 
incumbent  with  presence  in  the  strategic  reserve  to  withhold  capacity  in  the 
market  to  trigger  a  price  increase  and  the  activation  of  the  strategic  reserve, 
provided  that  its  profits  from  activating  the  reserve  outweigh  the  cost  of 
withholding  capacity.  Finally,  an  additional  source  of  concern  can  relate  to  the 
exercise  of  market  power  when  the  candidates  to  be  integrated  into  a  strategic 
reserve are very few. In this case, it can be that the tender for the reserve is not 
sufficiently competitive, which would reduce the ability of a strategic reserve to 
cost effectively address a transitional generation adequacy problem. 

148 

 
 
(510)  These  concerns  related  to  strategic  reserves  have  to  be  balanced  against  their 
potential  merits.  Several  respondents  to  the  Commission's  public  consultation 
following  the  publication  of  the  interim  report  of  this  inquiry,  have  pointed  out 
that  compared  to  a  market-wide  volume  based  capacity  market,  the  relatively 
small,  low  upfront  cost  and  quick-to-implement  strategic  reserve  is  in  certain 
circumstances the most appropriate form of intervention. These respondents point 
in  particular  to  the  limited  degree  of  market  distortions  that  a  well-designed 
strategic reserve should cause if the capacity in the reserve is truly held outside 
the market and only called upon when the market has failed to clear.152  

6.2.2.3

 Conclusions on strategic reserves 

(511)  Based on the information gathered by the Commission during the various stages 
of  this  inquiry,  it  can  be  concluded  that  strategic  reserves,  provided  they  are 
accompanied by market reforms that directly and credibly target missing money 
and provided the capacities are held truly outside the market, can be appropriate 
transitional  measures.  Even  if  the  reserve  alone  does  not  address  underlying 
market  or  regulatory  failures,  if  well  designed  it  has  the  potential  to  be  a 
relatively non-distortive insurance policy while required reforms are made.  

(512)  As a strategic reserve is unlikely to trigger investment in new generation capacity 

it does not appear to be suitable in a market requiring such investment.  

6.2.3

  Interruptibility schemes 

(513)  As explained in subsection 3.2.3, interruptibility schemes are a particular type of 
strategic reserve which only includes demand response capacity. Beneficiaries are 
typically  paid  a  fixed  price  for  the  demand  response  that  they  commit  to  make 
available  when  needed,  as  well  as  a  price  for  demand  reductions  actually 
delivered. 

(514)  The sector inquiry found interruptibility schemes in seven of the Member States 
covered by the inquiry: France, Germany153, Italy, Ireland, Poland, Portugal, and 
Spain.  

152   Though there is still a distortion to the merit order whenever prices in the market are set above the marginal costs 

of plants held in reserve. 

153 The German ABLAV interruptibility scheme (SA.43735) was assessed by the Commission under the 
State aid rules. The Commission did not raise objections and judged the measure to be compliant with the 
internal market. 

149 

 
 
                                                 
6.2.3.1

 Ability to address capacity shortages 

(515)  There  are  various  reasons  why  governments  or  TSOs  develop  interruptibility 
schemes.  Where  used  to  procure  demand  response  capacity  to  cover  a  general 
capacity  shortage  –  as  opposed  to  ancillary  services  to  manage  short  term 
frequency deviations – interruptibility schemes can reduce incentives to invest in 
flexible  generation  capacity,  in  the  same  way  as  strategic  reserves  do.  Whether 
interruptibility schemes actually have this effect depends to a large extent on their 
design.  

(516)  Most of the interruptibility schemes currently in place are used by the TSO as an 
ancillary  service,  i.e.  as  an  instrument  the  TSO  uses  after  intraday  gate closure, 
remotely  and  without  any  prior  notice  to  the  providers  of  the  service.  In  such 
cases, the impact of the schemes on market incentives is limited. Moreover, the 
fact that more demand response potential will be activated thanks to the specific 
support of the scheme is offset part of the need for additional flexible generation 
capacity as underlined in sub-section 2.3.1.  

(517)  Ancillary services can be provided by other, competing sources of flexibility so 
they  do  not  necessarily  have  to  be  provided  solely  by  demand  response.  A 
scheme  limited  to  demand  response  excludes  other  providers  of  flexibility  and 
therefore public authorities choosing to introduce DSR-specific measures should 
ensure  they  can  justify  any  limited  eligibility  criteria.  One  justification  for 
separate  interruptibility  schemes  for  ancillary  services  may  be  their  potential  to 
unlock  new  demand  response  and  thus  create  an  instant  type  of  flexibility  that 
would otherwise not have been at the TSO's disposal. If the objective is indeed to 
unlock  new  demand  response  potential,  then  it  would  be  appropriate  to  limit 
participation  to  the  interruptibility  scheme  to  “immature”  or  “unproven”  DSR 
capacities154  or  to  phase  out  the  measure  once  a  reasonable  amount  of  flexible 
loads  have  been  unlocked.  Although  some  Member  States  have  considered 
limiting  the  time  an  interruptible  load  can  participate  in  their  interruptibility 
scheme, there is no evidence from the sector inquiry that interruptibility schemes 
are  used  mainly  or  solely  as  transitional  mechanisms.  Allowing  the  continued 
in  a  (DSR-only) 
participation  of  “proven”  demand  response  capacities 
interruptibility scheme shields those capacities from competition and may result 
in the type of overcompensation to industry referred to in sub-section 5.2.3.3. 

(518)  Regarding their geographic scope, whilst interruptibility schemes generally apply 
country-wide,  their  use  can  be  local  if  the  TSO  sees  a  purely  local  need  for 

154   More “mature” or “proven” DSR capacities could then either participate in the energy market autonomously or in 

a market-wide capacity mechanism (as in the UK). 

150 

 
 
                                                 
shedding loads, for instance in response to network constraints. This is the case 
for  the  German  interruptible  load  scheme  which,  as  underlined  in  sub-section 
3.2.3 can be used by the TSOs to manage congestions between the North and the 
South while network reinforcements are made. 

(519)  From  a  timing  perspective,  the  implementation  of  interruptibility  schemes  does 
not in principle require long-term investments or commitments and therefore can 
be  seen  as  an  appropriate  measure  if  the  problem  is  of  transitional  nature.  For 
instance,  the  relatively  short  contract  times  applied  in  interruptibility  schemes 
(see  sub-section  5.2.2.4)  have  the  advantage  of  allowing  for  amending  demand 
quickly.  In  view  of  the  fact  that  ultimately  demand  response  should  be  enabled 
and  able  to  compete  with  generation  in  the  electricity  and  ancillary  services 
markets,  and  in  any  longer  term  market  wide  capacity  mechanism,  the  need  to 
foster  their  development  by  means  of  a  targeted  interruptibility  scheme  will  be 
more  difficult  to  demonstrate  as  market  reforms  take  effect.  In  market  areas 
where a market-wide capacity mechanism is in place, this mechanism should in 
principle allow for the participation of DSR and an integrated approach is likely 
to deliver more efficient outcomes155.  

(520)  Interruptibility schemes should therefore be temporary measures that are phased 
out once there is sufficient reason to assume that demand response will become 
active  on  the  basis  of  market  signals  or  as  capacity  provider  in  a  market-wide 
capacity mechanism. 

6.2.3.2

 Possible competition distortions and impact on market structure 

(521)  Most of the interruptibility schemes currently in place are relatively small in size 
and  where  this  is  the  case  their  impact  on  electricity  market  functioning  is 
unlikely  to  be  significant.  Moreover,  as  underlined  in  Chapter  2,  there  is  a 
growing  need  for  a  flexible  demand  side  and  interruptibility  schemes  can  be 
appropriate to kick-start the development of demand response that will in future 
be  able  to  compete  with  other  sources  of  flexibility  in  the  wholesale  and 
balancing markets.  

(522)  However,  despite  their  relatively  small  size,  interruptibility  schemes  can  be 
expensive  and  their  necessity  is  not  always  undisputed.156  The  effects  of 

155 For example because this would ensure maximum competition in the allocation process.  

156  

It  has  for  instance  been  estimated  that  the  Spanish  interruptibility  schemes  costs  around  EUR  500  million  per 
year. Sources:  
es/energ%C3%ADa/energ%C3%ADael%C3%A9ctrica/mercadomayorista.aspx, 
ACER Market monitoring report electricity 2015, page 12: 

https://www.cnmc.es/es-

151 

 
 
                                                 
 
 
interruptibility schemes need to be monitored closely as they have the potential to 
distort industrial markets if the selection criteria (and in particular minimum size 
requirements:  see  sub-section  5.2.2.2)  are  unnecessarily  restrictive.  Where 
schemes are devised by the government rather than independently by the TSO it 
will  be  particularly  important  to  ensure  that  they  truly  serve  the  purpose  of 
providing a service that is needed by the TSO at proportionate cost and without 
disproportionately  affecting  competition  with  other  sources  of  flexibility.  When 
this  is  not  the  case,  these  schemes  risks  becoming  –  as  put  forward  by  various 
respondents  to  the  sector  inquiry  –  aid  to  the  industrial  energy  users  frequently 
selected to provide the contracted demand response. 

6.2.3.3

 Conclusions on interruptibility schemes 

(523)  Whilst the benefits of unlocking additional demand response potential are clear, 
the design of a scheme is essential to ensuring that it truly provides added value 
to  the  TSO  in  ensuring  system  security  in  a  cost-efficient  way.  Interruptibility 
schemes  do  not  appear  to  provide  an  enduring  solution  to  a  capacity  shortage 
problem,  but  in  the  short  term  can  be  appropriate  to  help  develop  demand 
response.  In  the  longer  term,  there  may  be  an  enduring  need  for  particular 
ancillary  services  procured  by  TSOs  from  demand  response,  but  to  reduce  the 
risk of over-compensating the providers of such services, beneficiaries should be 
selected  through  competitions  open  to  all  potential  providers  able  to  meet 
transparent technical requirements. 

6.2.4

  Targeted capacity payments  

(524)  As  explained  in  sub-sections  3.1.1  and  3.1.2,  in  capacity  payments  models  a 
central body sets the price of capacity. In targeted capacity payments the centrally 
set price is paid to a subset of capacity operating in the market, for example only 
to  a  particular  technology,  or  only  to  capacity  providers  that  meet  specific 
criteria. 

(525)  The  sector  inquiry  found  targeted  capacity  payment  schemes  in  Italy,  Poland, 

Portugal, and Spain (see sub-section 3.2.4).  

6.2.4.1

 Ability to address capacity shortages 

(526)  Targeted  capacity  payments  are  designed  to  address  specific  needs,  making 
payments  accessible  only  to  generators  of  certain  types  or  in  certain  locations. 

http://www.acer.europa.eu/Official_documents/Publications/Pages/Publication.aspx.  
However, it appears to not be used frequently. Source: Platts European Power Daily, 15 April 2016  

152 

 
 
                                                                                                                                                 
However,  while  targeted  capacity  payments  can  be  effective  in  keeping  the 
existing plants benefitting from the payment from closing or support investment 
in  eligible  beneficiaries,  as  with  the  tender  and  reserve  models  they  risk 
worsening the situation for those that are not eligible. In Spain, the existence of 
several targeted schemes suggests that no individual targeted capacity payments 
mechanism has been considered sufficient to ensure generation adequacy (see sub 
section  5.2.3.8).  There  are  different  capacity  payments  available  to  investors  in 
new  plants,  and  to  those  operating  existing  capacity.  Portugal  also  has  two 
capacity payments schemes, as well as a separate interruptibility scheme.  

(527)  The targeted capacity mechanisms mechanisms identified in this inquiry all limit 
participation  to  specific  technologies,  but  none  pay  only  for  capacity  in  a 
particular geographic region. Alternative measures are often available to address 
local  shortages  more  efficiently  than  targeted  capacity  payments,  like  creating 
locational  electricity  prices  which  provide  longer  term  incentives  not  only  for 
local  capacity  investment  but  also  investment  in  cross-zonal  transmission  and 
signals for the use of existing transmission infrastructure. 

(528)  In any capacity payments model, the major challenge is the identification of the 
correct  level  for  the  capacity  payments  without  a  competitive  process.  As 
explained in detail in section 5.3, it is difficult to obtain through an administrative 
process  a  level  of  remuneration  that  incentivises  the  right  amount  of  additional 
generation capacity. Setting the wrong level of payments leads to either under- or 
over-investment  in  capacity,  compared  to  the  level  desired.  This  greatly 
compromises  the  ability  of  capacity  payments  to  efficiently  meet  its  objectives. 
The administratively set price level is also impossible to justify in the same way 
as  a  price  emerging  from  a  competitive  process.  That  is  why  –  whether  they 
consider  the  prices  to  be  too  high  or  too  low  –  stakeholders  are  frequently 
unhappy  with  the  administratively  set  prices  in  these  models.  The  lack  of  a 
competitive  process  therefore  makes  these  models  inappropriate  choices, 
regardless of the capacity problem identified.  

6.2.4.2

 Possible competition distortions and impact on market structure 

(529)  As  with  tenders  and  strategic  reserves,  targeted  capacity  payments  produce  a 
crowding-out  effect.  The  appearance  or  maintenance  of  subsidised  generation 
capacity  in  the  market  is  likely  to  be  detrimental  to  the  profitability  of  non-
subsidised  generation  capacity,  by  depressing  electricity  prices  that  remunerate 
all  capacity  providers.  This  crowding-out  effect  can  undermine  the  efficacy  of 
capacity payments if it deters investment by ineligible capacity providers.  

(530)  Moreover targeted capacity payments can distort technology choices of investors. 
They  support  specific  types  of  generation  capacity  as  defined  centrally  by  the 

153 

 
 
authorities, to the detriment of alternative choices that market players could have 
made in response to market signals157.  

(531)  More generally, some investors have raised the concern that even where capacity 
payments schemes are open to new entrants, since there is no competitive process 
in which new projects might come forward and take market share from existing 
capacity providers, capacity payments  contribute to  keep in the market capacity 
that would otherwise exit and therefore constitute a barrier to new investment in 
generation. They therefore preserve the existing market structure and generation 
mix. 

(532)  It is in principle conceivable that targeted capacity payments are paid only to new 
entrants or smaller generators, but there are no examples of such a practice and it 
would  be  difficult  to  justify  on  objective  grounds.  In  Greece,  for  example,  the 
flexibility  mechanism  supports  the  gas-fired  power  plants  of  the  independent 
power  producers  as  well  as  of  the  incumbent  because  both  operate  plants 
fulfilling the technical criteria to ensure the necessary flexibility158.  

6.2.4.3

 Conclusions on targeted capacity payments 

(533)  Targeted capacity payments suffer from many of the drawbacks of the tender and 
strategic  reserve  models,  with  the  additional  drawback  that  there  is  no 
competitive  price  setting  process  which  increases  the  risk  of  failing  to  deliver 
security  of  supply  or  stimulating  overcapacity,  as  well  as  making  the  level  of 
remuneration difficult to justify. They are therefore likely to be the least efficient 
models of capacity mechanism. 

6.2.5

  Central buyer mechanisms 

(534)  As described in sub-section 3.1.2, in a central buyer mechanism the total amount 
of required capacity is set centrally, and then procured by a central buyer through 
a  process  in  which  potential  capacity  providers  compete.  This  competitive 
bidding determines the price paid to capacity providers. 

157 Though the capacity product obligations in a capacity mechanism will always have some impact on 
investors' technology choices.  

158 While in general capacity payments models will not be considered appropriate, the Greek flexibility 
mechanism was approved in 2016 as an exceptional temporary measure for a period of 12 months (see 
SA.38968) while various market reforms where implemented (among other things to increase wholesale 
and ancillary services price caps) and a more appropriate longer term central buyer capacity mechanism 
developed.  

154 

 
 
                                                 
(535)  Sub-section 3.2.5 explains that examples of central buyer schemes were found in 
two of the Member States included in the sector inquiry: Ireland and Italy. Both 
mechanisms  are  still  in  development  and  are  not  yet  operational.  Examples  of 
central buyer  schemes  are also found in  the British capacity  mechanism, and in 
the United States including in the ISO New England and PJM systems on the East 
Coast. 

(536)  These mechanisms are being introduced by Ireland and Italy because of concerns 
that  there  are  systemic  electricity  market  failures  that  cannot  be  addressed  –  at 
least in the medium term – only through reforms to the energy only market. The 
UK presented similar reasons for the introduction of the British mechanism. 

6.2.5.1

 Ability to address capacity shortages 

(537)  A  central  buyer  mechanism  produces  a  competitive  capacity  price  through  an 
auction  for  the  total  required  capacity,  as  established  by  the  central  buyer.  This 
ensures that the desired amount of generation capacity is actually procured and, 
provided the auction is competitive, ensures the cost of procuring such amount of 
generation  capacity  is  minimised.  A  central  buyer  mechanism  can  therefore 
efficiently  attain  the  desired  level  of  generation  capacity,  if  appropriately 
designed. 

(538)  A  number  of  design  features  can  contribute  to  the  competitiveness  of  the 
procurement  procedure  and  the  efficiency  of  the  outcome.  Eligibility  rules  that 
broaden the set of potential participants in the mechanism, for example, are likely 
to contribute to this competitiveness (as explained in Section 5.2).  

(539)  An  important  aspect  in  central  buyer  mechanisms  –  as  in  other  volume-based 
mechanisms – is the need for a central body to estimate the required amount and 
type of generation capacity to attain the desired level of system reliability. While 
this  minimises  risks  of  insufficient  provision  of  generation  capacity,  it  risks 
leading  to  excess  capacity  if  risk-averse  central  authorities  set  the  targets  for 
generation capacity at unnecessary high levels. This risk exists to some extent in 
every capacity mechanism type, however, and should be mitigated by links to a 
thorough  and  transparent  adequacy  assessment,  and  appropriate  oversight  of 
regulators  or  independent  experts  to  verify  the  parameters  set  by  governments 
and TSOs. 

(540)  Regarding the geographic scope of the intervention, with eligibility criteria open 
to all potential capacity providers, a central buyer mechanism is able to address a 
systemic missing money problem. Central buyer mechanisms can also be used to 
address  local  shortages.  For  instance,  to  encourage  sufficient  investment  in 
different locations the central buyer mechanisms in ISO New England and PJM, 

155 

 
 
and the proposed mechanism in Italy, the auctions discover zonal capacity prices 
in different geographical areas covered by the mechanisms.159 

(541)  Regarding  timing  in  the  implementation  of  central  buyer  mechanisms,  the  long 
lead  time  between  the  auction  and  obligation  period  required  to  enable  new 
projects to be built, and the potential for longer contracts for new capacity, limit 
the ability to quickly move from a central buyer model to an alternative market 
design. These  mechanisms  may therefore be less appropriate as very short  term 
transitional  interventions  than  tenders  or  strategic  reserves.  However,  the 
mechanism  can  correct  itself  because  when  more  capacity  is  available  and/or 
investors expect future electricity revenues to fully compensate their investments, 
the  price  of  capacity  will  drop,  in  theory  to  zero  when  there  is  no  longer  any 
missing money.160 

6.2.5.2

 Possible competition distortions and impact on market structure 

(542)  So  long  as  it  is  possible  in  practice  for  new  projects  to  compete  with  the  least 
efficient  existing  capacity  providers,  a  central  buyer  model  can  attract  new 
entrants.  The  possibility  of  competition  from  new  entrants  should  also  help 
ensure  that  the  market  power  of  participants  in  the  capacity  auction  itself  is 
limited. 

(543)  To  assess  the  impact  of  this  model  on  the  market  structure,  the  existence  of 
longer contract lengths  for  new  investments  is  a  key  parameter (as  discussed  in 
sub-section  5.2.2.4).  Unlike  the  de-central  obligation  model,  the  central  buyer 
model  can  be  designed  more  easily  to  accommodate  multiple  contract  lengths. 
This  facilitates  the  participation  of  new  projects  needing  to  commit  upfront  to 
high  initial  investment  costs,  but  needs  to  be  balanced  against  the  potential 
discrimination  between  different  capacity  providers  due  to  different  contract 
lengths.  

(544)  The  possibility  of  effective  participation  from  new  entrants  in  this  type  of 
mechanism means that it can be designed in such a way that no barriers to entry 
are added in electricity generation. The competitive threat from potential entrants 
can be an effective constraint to incumbents with strong market positions, and the 
eventual  participation  of  foreign  capacity  would  constitute  an  additional 

159   Efficient  rules  for  cross-zonal  participation  are  needed  in  such  a  design  to  ensure  appropriate  incentives  for 
investment in additional transmission as well as generation and demand response capacity. In practice, these rules 
may be no different to the rules required for foreign capacity participation (see Annex 2).  

160   This depends on the capacity product. Where the product exposes participnts to particular risks, the price may 
never reach zero. For example, a reliability option requiring paybacks from capacity providers. However, in an 
efficient system consumers should be compensated for the cost of capacity by the paybacks received.  

156 

 
 
                                                 
competitive  constraint.161  Moreover,  the  capacity  product  in  a  central  buyer 
model can also be designed to limit market power in the electricity market. For 
example, the reliability options being developed in Ireland and Italy should still 
allow  high  prices  to  be  set  in  the  electricity  market  (which  in  turn  will  send 
efficient signals for imports and demand response) while also limiting the extent 
to  which  capacity  providers  that  have  benefitted  from  the  capacity  mechanism 
can access these high prices at consumers' expense. 

6.2.5.3

 Conclusions on central buyer mechanisms 

(545)  A  central  buyer  mechanism  has  the  potential  to  solve  a  general  shortage  of 
capacity  efficiently,  but  its  success  depends  greatly  on  appropriate  eligibility 
criteria and a design of the capacity product that ensures achieving a well-defined 
objective with minimal distortions to the functioning of the electricity market. It 
may be particularly useful where concerns about potential market power prevent 
a  more  decentralised  approach  and/or  longer  contracts  are  required  to  bring 
forward new entry. 

(546)  Some inefficiency may be unavoidable in any central buyer design, for example 
due  to  the  complexity  of  carefully  assessing  all  the  design  features,  the 
dependence on central judgements by risk averse decision makers  – though this 
can be reduced by including a role for the regulator or independent experts in the 
process  –  and  the  need  to  centrally  determine  the  required  flexibility 
characteristics of capacity providers through the design of the capacity product.  

6.2.6

  De-central obligation  

(547)  As  explained  in  sub-section  3.1.2,  in  a  de-central  obligation  mechanism  an 
obligation  is  placed  on  electricity  suppliers/retailers  to  contract  with  capacity 
providers to secure the total capacity they need to meet their consumers' demand. 
The  difference  compared  to  the  central  buyer  model  is  that  there  is  no  central 
bidding process, but market forces should still establish the price for the required 
capacity volume.  

(548)  As  explained  in  sub-section  3.2.6,  the  only  de-central  obligation  mechanism 
found in the sector inquiry is the capacity certificates market being introduced in 
France. 

161   Although a solution appears possible that would allow cross-border participation in central buyer and de-central 
obligation  capacity  mechanisms  (see  Annex  2)  until  this  is  enabled  there  will  be  long  term  distortions  to 
locational  investment  signals,  with  stronger  incentives  for  investment  in  capacity  mechanism  areas  than  in 
neighbouring  areas  without  capacity  mechanisms  or  in  new  transmission  linking  the  two  (see  sub-section 
5.2.3.7).  

157 

 
 
                                                 
6.2.6.1

 Ability to address capacity shortages 

(549)  Like  the  central  buyer  model,  a  supplier  obligation  is  in  principle  suitable  to 
address a systemic, market-wide missing money problem, subject to appropriate 
eligibility criteria and a suitable capacity product.  

(550)  It is less likely to be appropriate when generation capacity required is of a certain 
type  or  in  a  certain  geographic  location.  While  in  principle  it  is  conceivable  to 
enable  locational  investment  signals  in  a  de-central  obligation  mechanism,  for 
example  by  obliging  suppliers  to  purchase  a  proportion  of  their  capacity 
certificates  from  providers  located  in  a  particular  geographical  location,  this 
would result in significant added complexity and there are so far no precedents of 
such type of mechanism. 

(551)  From  a  timing  perspective,  the  complexity  of  designing  and  implementing  de-
central obligation mechanisms seems to suggest they are unlikely to be seen as a 
transitional intervention. However, compared to the central buyer mechanism the 
absence of long contracts reduces the future costs of exit from the mechanism. In 
a  well-designed  and  competitive  de-central  obligation  mechanism,  once  the 
required  level  of  generation  capacity  is  attained,  capacity  prices  should 
theoretically fall to zero in the same way as in the central buyer mechanism. 

(552)  Contrary to the central buyer mechanism, a de-central obligation does not require 
a central determination of the generation capacity required to ensure the targeted 
level  of  system  reliability.  In  a  de-central  obligation  mechanism  the  central 
authority  establishes  only  the  coverage  rate  of  expected  demand  that  market 
participants need to attain through bilateral contracting, leaving the estimation of 
expected demand to each supplier.  

(553)  This  does  not  mean  that  the  risk  of  over  or  under-procurement  is  absent.  It  can 
materialize  for  instance  if  the  design  of  penalties  that  apply  for  insufficient 
procurement allow suppliers to strategically underestimate their expected demand 
to reduce procurement costs, or are so high that suppliers overinsure themselves 
by purchasing extra capacity. There can also be other administrative elements that 
influence  the  overall  level  of  security  that  will  be  achieved  by  such  a 
mechanism.162 Other causes for over or under procurement are not specific to de-
central obligation mechanisms, like a genuine over or underestimation of medium 
to long term capacity needs or the lack of visibility of suppliers about their future 

162   The French mechanism includes an additional administrative element since suppliers' obligations are inflated by 
a 'thermosensitivity factor' to ensure suppliers buy enough capacity to meet demand in a particularly cold winter. 

158 

 
 
                                                 
customers' demand, which can also occur when the required generation capacity 
is determined centrally. 

6.2.6.2

 Possible competition distortions and impact on market structure 

(554)  While  de-central  obligation  mechanisms  are  open  to  the  participation  of  new 
entrants,  their  effective  participation  depends  on  the  possibility  and  appetite  of 
market players for engaging in longer duration capacity contracts, which in turn 
is  influenced  by  capacity  price  uncertainties.  Almost  two-thirds  of  market 
participants responding on the French de-central obligation mechanism (including 
mainly  generators  but  also  demand  response  aggregators)  considered  that  it  did 
not provide sufficient incentives for new investment. For that reason, eventually 
the  French  authorities  agreed  to  include  in  the  mechanism  a  central  buyer 
element,  through  which  the  TSO  would  contract  competitive  new  capacities 
longer term (see sub-section 5.2.2.4). 

(555)  The  dependence  on  bilateral  trading  in  a  de-central  obligation  model  without 
mandatory  exchange  trading  risks  giving  an  advantage  to  vertically  integrated 
companies that can trade certificates internally between their generation and retail 
businesses. This is likely to increase incentives for vertical integration and reduce 
incentives  for  new  independent  market  entry  on  the  generation  or  retail  side.  A 
de-central  obligation  mechanism  may  therefore  not  be  appropriate  if  there  is  a 
perceived risk that an incumbent with some degree of market power will abuse its 
position  in  the  trade  of  the  obligations.  Alternatively,  the  inclusion  of  specific 
safeguards in the capacity mechanism may be envisaged to limit this risk. This is 
particularly  relevant  in  electricity  markets  with  a  significant  degree  of  market 
concentration.  

(556)  Cross-border  participation  is  necessary  to  correct  distortions  to  locational 
investment  signals  that  would  otherwise  be  caused  by  the  introduction  of  a  de-
central  obligation  mechanism  and  ensure  longer-term  competition  between  the 
domestic  and  foreign  capacity  that  can  both  contribute  to  domestic  security  of 
supply.  The  only  de-central  mechanism  covered  by  the  inquiry,  in  France,  will 
eventually  include  direct  participation  of  foreign  capacities  following  the 
proposal described in Annex 2. 

6.2.6.3

 Conclusions on de-central obligations 

(557)  A de-central obligation mechanism has the potential to solve a general shortage 
of  capacity  efficiently,  subject  to  appropriate  eligibility  criteria  and  a  suitable 
capacity  product.  It  does  not  require  the  amount  of  capacity  needed  to  be 
centrally determined, which is an advantage if market players are better suited to 
identify  the  needs  for  capacity.  However,  risk  of  over-  or  under-procurement 

159 

 
 
exists,  especially  if  penalties  and  other  administratively-set  parameters  are  not 
carefully designed. 

(558)  If possibilities to contract on longer-term basis are limited, this hinders the entry 
of new generators to the benefit of incumbent capacity providers. This is however 
not different to the situation in a market without any capacity mechanism where 
longer-term contracting is uncommon. Even where new entry is not immediately 
needed,  mechanism  designs  that  facilitate  new  entry  can  be  useful  to  limit 
potential  market  power  of  existing  capacity  providers.  A  pure  de-central 
obligation  mechanism,  without  any  specific  provisions  for  new  capacities,  are 
therefore not the most suitable in cases where there are concerns about barriers to 
entry and exercise of market power by incumbents. 

6.2.7

  Market-wide capacity payments  

(559)  As  in  targeted  capacity  payments  models,  in  market-wide  capacity  payments 
model a centrally determined price is paid to capacity providers. The difference is 
that while in targeted models only a subset of capacity receives the payments, in 
market-wide  mechanism  all  capacity  expected  to  be  needed  to  meet  demand  in 
the market receives the payments. 

(560)  The  sector  inquiry  found  one  market-wide  capacity  payment  scheme  in  Ireland 

(see sub-section 3.2.7).  

6.2.7.1

 Ability to address capacity shortages 

(561)  Market-wide capacity mechanisms avoid some of the drawbacks identified above 
for the targeted capacity payments model, since they seem to avoid the need for 
multiple mechanisms (since introducing a market wide capacity payment scheme 
in 2007, Ireland does not appear to have needed additional interventions to ensure 
generation adequacy).  

(562)  However,  like  targeted  capacity  payments  models,  market-wide  capacity 
payments suffer from the critical flaw that the administrative price-setting process 
brings high risks that the measure will fail to efficiently meet its objectives. 

6.2.7.2

 Possible competition distortions and impact on market structure 

(563)  A  market-wide  capacity  payment  model  does  not  appear  to  have  the  same 
negative crowding out effects as targeted capacity payments, nor – so long as it is 
open to all technologies capable of providing capacity – does it distort investors' 
technology choices in the same way as a targeted mechanism.  

160 

 
 
(564)  However,  the  lack  of  competitive  process  serves  as  a  barrier  to  entry  and 

therefore preserve the existing market structure and generation mix.  

(565)  In Ireland, to counter concerns that generators would receive a capacity payment 
based  on  their  fixed  costs  and  then  earn  windfalls  from  high  electricity  prices, 
market  participants  are  required  to  bid  at  the  level  of  their  short  run  marginal 
costs into the electricity market. This accompanying market rule risks causing the 
capacity  mechanism  to  become  a  permanent  feature  of  the  market  (unless  other 
reforms are made) and risks undermining the efficiency of electricity prices as a 
signal for imports at the right times.  

6.2.7.3

 Conclusions on market-wide capacity payments 

(566)  Although  they  have  suffer  from  fewer  drawbacks  than  the  targeted  capacity 
payments  mechanisms,  market  wide  capacity  payments  do  not  competitively 
reveal the value of capacity and come with high risks of failing to cost effectively 
meet their objectives. 

6.3 

Choosing the right type of capacity mechanism 

(567)  The assessment of the effects of the various types of capacity mechanisms can be 
used  to  draw  conclusions  as  to  which  mechanism  fits  best  in  which  situation. 
Combined  with  a  detailed  adequacy  assessment  that  precisely  defines  the 
problem,  the  pros  and  cons  of  each  mechanism  type  can  help  guide  Member 
States to choose the most suitable intervention and avoid the development of an 
inappropriate mechanism, as well as the Commission in its State aid assessment 
of the measure,.  

(568)  Note  that  the  assessment  framework  presented  in  this  section  is  of  illustratory 
nature  only;  the  suitability  of  a  capacity  mechanism  will  always  need  to  be 
assessed  against  the  specific  background  of  the  market  area  in  which  it  is 
introduced. The electricity market is rapidly evolving and many interventions are 
new or still in development. The Commission will therefore need to remain agile 
to respond as further lessons are learned and markets further developed. 

(569)  It  is  also  critical,  as  highlighted  by  respondents  to  the  consultation,  that  the 
process  to  implement  a  capacity  mechanism  is  transparent  and  consultative  so 
that  market  participants  and  consumers  understand  the  rationale  for  the 
intervention  and  its  implications,  and  can  contribute  to  ensuring  an  appropriate 
design. 

161 

 
 
6.3.1

  The main adequacy problems 

(570)  The  main  adequacy  problems  identified  so  far  in  the  sector  inquiry  and  case 

practice can be categorised in four groups:  

1.  concerns  about  the  long  term  ability  of  the  market  to  trigger  sufficient 

investments; 

2.  concerns of a temporary nature where the current  market design fails to provide 
adequate  investment  signals  or  risks  producing  uncontrolled  market  exit,  but 
where the market is expected to be effective in the longer term;  

3.  concerns of a local nature (i.e. in a specific location within a Member State) that 
cannot be resolved quickly enough by investing in transmission or implementing 
a better configuration of electricity bidding zones; and  

4.  concerns  that  without  additional  support,  energy  consumers  (the  demand  side) 
will  not  play  a  sufficient  role  in  managing  electricity  demand  and  security  of 
supply.  

(571)  Before assessing the most appropriate response in each of these four situations, it 
is  useful  to  distinguish  why  certain  Member  States  might  conclude  they  face  a 
long term adequacy concern whereas others are convinced their concerns are of a 
temporary  nature  only.  Case  practice  demonstrates  that  the  question  whether  a 
reformed  market  will  be  able  to  trigger  investments  without  any  additional 
support  is  often  answered  on  the  basis  of  policy  considerations  and  the  state  of 
the  current  market  rather  than  pure  economic  analysis.  Economic  analysis 
indicates  that,  under  certain  assumptions,  prices  reflecting  VOLL  in  periods  of 
scarcity  could  trigger  investment  at  the  optimum  level  to  achieve  levels  of 
reliability that consumers are willing to pay for. However, none of the countries 
in  this  inquiry  have  chosen  to  rely  on  an  energy-only  electricity  market,  and 
examples  of  liberalised  'energy-only'  markets  outside  the  enquiry  are  relatively 
rare. It may well be that a government is not, or not immediately, prepared to take 
the  risk  of  relying  on  a  market  without  a  capacity  mechanism  to  deliver  secure 
supplies.  

(572)  As  a  government  considers  what  approach  to  take,  uncertainty  is  inevitably 
transferred to market participants who will be hesitant to invest in the knowledge 
that  the  government  may  choose  to  intervene  in  some  way.  For  expectations  of 
high scarcity prices to have a true chance of triggering investments, it is essential 
that  the  government  not  only  ensures  the  required  reforms  make  such  prices 
possible,  but  also  clearly  communicates  its  commitment  to  abstain  from 
intervening  by  capping  prices  in  the  future.  As  this  stance  is  maintained, 
confidence will be further increased. 

(573)  In  some  markets  it  is  easier  to  take  such  a  stance  than  in  others.  In  particular, 
where there is currently more installed capacity than required and there is no risk 

162 

 
 
 
of large amounts of capacity closing suddently because it is nearing the end of its 
technical  lifetime,  governments  have  a  chance  to  upgrade  and  then  rely  on  the 
market  in  a  way  that  a  government  in  a  country  with  an  urgent  need  for  new 
investment cannot. Fortunately, in most of Europe there is currently overcapacity, 
affording Member States to make the most of the opportunity to make the market 
work.  

(574)  Adequacy assessments are able to quantify the extent of any current overcapacity 
and  the  risks  of  plant  closures  to  a  large  extent,  but  a  degree  of  uncertainty 
remains  that  may  lead  policy  makers  to  opt  for  the  insurance  of  a  market-wide 
capacity  mechanism  to  support  market  reforms.  Where  policy  makers  on  the 
other  hand  are  convinced  that  no  intervention  in  the  market  is  necessary  or 
appropriate,  it  should  communicate  this  clearly  because  investors  need  the 
confidence  that  the regulatory  framework  will  not  be  adapted  to  their  detriment 
after they have made an investment.  

6.3.2

  Long term concerns 

(575)  In  the  first  of  the  four  cases,  i.e.  where  a  general  missing  money  problem  is 
identified  and  confirmed  by  way  of  an  adequacy  assessment,  the  appropriate 
response  consists  of  a  longer  term  intervention  in  the  market  that  ensures  new 
investments and maintains existing capacity providers in the market to the extent 
they are necessary to ensure security of supply. Strategic reserves and individual 
tenders  do  not  fundamentally  change  the  investment  climate  of  an  electricity 
market and so are not suitable to address a general missing money problem.  

(576)  In contrast, market-wide mechanisms can, if well-designed, create the confidence 
existing  and  aspirant  market  participants  need.  For  instance,  the  design  of  the 
future  Irish  reliability  options  mechanisms  (a  central  buyer  mechanism)  creates 
certainty  about  future  returns  for  generators  by  ensuring  them  a  fixed  payment 
throughout the year for being available in exchange for uncertain scarcity rents. 
As  described  in  Chapter  2.2  there  are  multiple  market  reforms  that  should 
mitigate  concerns  around  a  general missing  money  problem  and  the  assessment 
of  their  added  value  as  well  as  their  implementation  are  prerequisites  for  the 
implementation  of  any  form  of  market-wide  mechanism.  These  reforms  are 
required to help ensure the State aid required through the capacity mechanism is 
kept to the minimum. 

6.3.3

 Temporary concerns 

(577)  For a temporary adequacy concern, where policy makers are convinced that in the 
long run the market can be reformed to ensure a healthy investment climate exists 
that  will  trigger  the  right  type  of  investment,  long  term  interventions  are  not 
necessary. In such instances, intervention should be temporary, does not have to 

163 

 
 
trigger new investment because there is confidence that the market will do that, 
and should ensure that the developing market is distorted as little as possible.  

(578)  A  strategic  reserve  is  likely  to  be  the  most  appropriate  response  in  such 
circumstances because it can prevent too much capacity leaving the market while 
necessary  reforms  are  made.  Market  distortions  will  not  not  absent  but  can  be 
reduced if the reserve is well designed to keep it as small as possible. This is best 
achieved  by  ensuring  the  reserve  is  held  completely  outside  the  market  and 
allows appropriately high prices to emerge in the electricity price when electricity 
capacity  is  scarce.  Such  a  design  maintains  incentives  to  remain  in  the  market, 
and  therefore  reduces  the  risk  of  a  slipperly  slope.  Moreover,  strategic  reserves 
should  be  accompanied  by  a  clear  end  date  which  helps  to  preserve  future 
investment  signals.  Clearly,  the  optimism  about  the  market's  ability  to  ensure 
appropriate investment signals needs to be based on a solid assessment including 
implementation  of  the  reforms  necessary  to  ensure  future  electricity  prices 
support future investment in the market area concerned.  

(579)  A strategic reserve can also be used as a tool to fill a looming capacity gap while 
a  volume-based  market  wide  capacity  mechanism  is  being  introduced.  In  this 
way,  it  can  be  valuable  to  avoid  short  auction  lead  times  for  the  market-wide 
mechanism.  At  the  same  time,  there  may  be  a  benefit  in  introducing  a  market-
wide mechanism straight away to avoid devising and implementing a transitional 
mechanism of a different type. 

6.3.4

  Locational concerns 

(580)  The third concern – temporary or long term worries about generation adequacy in 
a  specific  location  in  the  market  area  –  sometimes  arises  in  relatively  isolated 
areas  such  as  islands  or  peninsulas  (e.g.  Brittany),  but  is  also  a  concern  in 
relatively well-connected mainland areas (e.g. south Germany, or south Sweden). 

(581)  In  the  long  run,  a  durable  solution  needs  to  be  found  through  investments  in 
transmission and a better connection of the region. Where that is not possible or 
feasible, for the reasons set out in Section 2.2.2 the creation of additional bidding 
zones should be the solution. Whatever the most appropriate longer term solution 
is, the situation in the short to medium term needs to be remedied. 

(582)  Where  longer  term  adequacy  concerns  have  been  identified  and  a  market-wide 
mechanism  is  being  introduced,  a  market-wide  mechanism  can  sometimes  be 
tailored  also  to  solve  a  local  adequacy  problem:  Italy  is  planning,  to  create 
capacity price zones within a market-wide capacity mechanism to provide signals 
for local investment. 

164 

 
 
(583)  A more targeted measure can also be suitable to address a local adequacy concern 
– including the inability to bring forward required local ancillary services without 
Government intervention. A strategic reserve can be limited to a specific region 
only, as can a tender for new capacity. These targeted mechanisms can be sized to 
the  identified  local  capacity  gap.  Because  of  the  long  contracts  required  to 
stimulate investments in new capacity through a tender, and the additional market 
distortions  that  arise  because  benefitting  capacity  participates  in  the  electricity 
market, tenders must be limited  to circumstances in which there is a proven need 
for new investment.  

(584)  To avoid an unacceptable distortion where local capacity value is extracted from 
electricity prices and moved into the capacity mechanism, whichever mechanism 
is  used  the  local  problem  needs  to  be  solved  in  the  longer  term  through 
transmission investment or by reconfiguring electricity bidding zones. 

6.3.5

  Concerns related to the responsive of the demand side 

(585)  Finally,  the  fourth  concern  is  about  the  insufficient  development  of  a  flexible 
demand  side,  which  may  lead  a  Member  State  to  introduce  an  interruptibility 
scheme  (or  to  introduce  specific  rules  to  stimulate  demand  response  within  a 
volume  based  market  wide  scheme  where  one  is  introduced).  Based  on  the 
assessment of the eight schemes in operation in 7 of the 11 Member States, these 
schemes  can  be  justified  in  view  of  their  modest  but  nevertheless  significant 
contribution  to  both  short  term  and  long  term  security  of  supply.163  Demand 
response can prove useful for balancing the system in the short run, while a fully 
responsive  demand  side  has  the  potential  to  entirely  eliminate  the  need  for 
capacity mechanisms in the long run since it would enable consumers to pay for 
different  levels  of  reliability  and  therefore  reduce  the  political  justification  for 
intervening to ensure security of supply on consumers' behalf. 

(586)  However,  the  appropriateness  of  interruptibility  schemes  –  and  therefore  their 
compliance with EU State aid rules – depends crucially on how they are designed 
and  how  they  function.  Where  a  demand  response  scheme  allows  for  broad 
participation  from  large  and  small  industries  and  from  demand  response 
aggregators,  does  not  procure  excessive  capacity,  is  based  on  competitive 
procurement,  and  is  designed  not  to  influence  the  formation  of  appropriate 
electricity  scarcity  prices,  it  may  be  acceptable  for  a  limited  period  of  time  to 
kick-start  demand  response,  although  it  can  create  some  market  distortions  and 

163   Note  that  such  assessment  within  the  sector  inquiry  cannot  replace  the  need  for  individual  assessment  of  any 
State  aid  measures,  and  this  statement  should  not  be  interpreted  to  mean  that  schemes  that  have  not  yet  been 
assessed and subject to a Decision of the Commission will be found compatible. 

165 

 
 
                                                 
although State aid rules normally require capacity mechanisms to be open to all 
technologies. It should however  be shown that such schemes  provide  additional 
value  compared  to  existing  ancillary  services  schemes.  On  the  other  hand, 
demand  response  schemes  in  which  too  much  capacity  is  procured  from  only  a 
subset of large industrial beneficiaries are unlikely to be approved under State aid 
rules.  They  risk  subsidising  energy  intensive  industries  without  providing 
corresponding value in terms of increased security of supply to  other electricity 
consumers. 

6.3.6

  Capacity payments are unlikely to be the most appropriate option 

(587)  Finally,  with  respect  to  'capacity  payments',  the  sector  inquiry  shows  that  these 
mechanisms are unlikely to set the right price for capacity since they do not allow 
the  market  to  competitively  set  the  right  price,  but  rather  depend  on  an 
administratively  set  price.  They  are  therefore  unlikely  to  correctly  reflect  the 
actual scarcity situation. They imply a high risk of under- or over-procurement of 
capacity  –  especially  as  such  schemes  tend  to  react  slowly  to  changing  market 
circumstances. And the level of remuneration is often challenged by stakeholders 
since it is impossible to justify in the same was as a remuneration level emerging 
from a competitive process. The general presumption is therefore that price-based 
mechanisms are unlikely to be an appropriate measure regardless of the specific 
concern identified.  

6.4  Minimising the cost of capacity mechanisms 

(588)  The support given through capacity mechanisms is typically financed from public 
resources  and therefore ultimately borne by final  consumers.  Assessing the cost 
of capacity mechanisms is an important but challenging exercise.  

(589)  Capacity  mechanisms  involve  the  transfer  of  financial  resources  from  public 
budgets  to  investors  in  capacity,  either  directly  or  indirectly  (like  in  de-central 
obligation mechanisms). In all cases, taxpayers or final consumers are the source 
of these financial resources. 

(590)  Assessing  the  net  cost  of  capacity  mechanisms  is  not  easy,  because  it  requires 
examination not only of the budgetary payments made by public authorities, but 
also  of  any  potential  savings  stemming  from  the  capacity  mechanism.  This 
includes  the  avoidance  of  load  losses  for  consumers  due  to  electricity  supply 
disruptions,  and  the  reduction  in  electricity  wholesale  costs  arising  from  the 
existence of the capacity mechanism and the transfer of revenues from electricity 
scarcity  prices  to  capacity  payments.  Differences  in  the  necessity,  design  and 
market  impact  must  be  taken  into  account  comparing  costs  across  mechanisms. 

166 

 
 
 
For  instance,  a  small  but  unnecessary  capacity  mechanism  with  relatively  low 
expenses can be more costly overall than a larger but necessary mechanism. 

(591)  Despite the complexity of assessing the true costs of a capacity mechanism, it is 
important  that  Member  States  do  their  best  to  properly  estimate  the  expected 
costs and savings of any capacity mechanism they implement, both  ex-ante and 
ex-post,  to  ensure  the  cost-effectiveness  of  their  public  intervention.  Member 
States must also be as transparent as possible about this assessment to allow for 
democratic  scrutiny  of  their  policy  choices.  The  information  received  by  the 
Commission  in  the  context  of  the  sector  inquiry  demonstrated  that  cost  benefit 
assessments and evaluation of capacity mechanisms are the exception rather than 
the rule.  

(592)  The  sector  inquiry  has  also  identified  a  number  of  ways  to  limit  the  cost  of 
thorough  and  comprehensive  adequacy 

capacity  mechanisms 
assessment and an appropriate design: 

through  a 

 

  The adequacy assessment should exclude capacity mechanisms whenever there is 
overcapacity or no real need. An adequacy assessment that compares the existing 
and future capacity to a reliability standard based on VOLL will help keep costs 
on check and procure capacity volumes reflecting consumers willingness to pay.  
 The adequacy assessment should identify alternative solutions and measures for 
achieving  the objective. By looking at the adequacy problems in a holistic way a 
comprehensive adequacy assessment can minimise costs by identifying the least 
costly  measure  or  combination  of  measures  and  avoid  ending  up  with  multiple 
capacity  mechanisms  and  reduce  the  risk  of  continuous  reforms.  Targeted 
mechanisms for instance appear cheaper than market-based capacity mechanisms, 
but if the adequacy problem is general it might be less costly to establish a single 
market-based  capacity  mechanism  than  bearing  the  cost  of  a  multiplicity  of 
targeted mechanisms. 
 In  terms  of  design,  open  and  broad  elegibility  criteria  that  allow  all  capacity 
providers  to  participate  in  the  market  and  a  competitive  allocation  process  are 
crucial for ensuring that costs are justificable and kept to the minimum necessary. 

 

6.5 

Capacity mechanisms and the decarbonisation objective 

(593)  The  various  types  of  capacity  mechanisms  have  been  assessed  in  this  Staff 
Working  Document  mainly  against  their  ability  to  cost  effectively  address 
problems  of  generation  adequacy  and  their  potential  to  create  distortions  to  the 
functioning of the Single Market in energy.  

(594)  However,  as  already  explained  in  Chapter  2,  current  EU  energy  policy  also 
encompasses  the  objective  of  decarbonisation.  Significant  private  and  public 
efforts  have  been  made  to  advance  in  this  area.  By  having  an  impact  on 

167 

 
 
generation capacity and on the generation technology mix, capacity mechanisms 
interact  with  policy  instruments164  designed  to  foster  decarbonisation  and  may 
impact  the  achievement  of  their  objectives.  It  is  important  that  Member  States, 
when  they  design  capacity  mechanisms  are  aware  of  these  interactions,  in  line 
with the EEAG.165 Chapter 5 of this Staff Working Document identified instances 
where  eligibility  or  allocation  criteria  already  take  into  account  decarbonisation 
objectives,  and  in  future  Member  States  may  wish  to  develop  capacity-based 
remuneration for renewables, allowing them to compete alongside other capacity 
in  a  competitive  process  for  delivering  decarbonisation  and  resource  adequacy 
objectives. When demand side management measures are being considered, such 
as  interruptibility  schemes,  the  Member  States  should  take  into  account  their 
potential  environment and climate policy benefits in their overall assessment. 

6.6 

Conclusions 

(595)  Given  the on-going  developments in  and reforms of  EU  electricity  markets,  the 
Commission  will  continue  to  carefully  monitor  the  evolution  of  capacity 
mechanisms  and  to  refine  the  guidance  set  out  in  this  Communication  and  the 
annexed report in the light of its evolving case practice. But based on the sector 
inquiry, the Commission draws eight overall conclusions.  

(596)  First, it has become clear that despite current overcapacity in the EU as a whole, 
there are widespread concerns that insufficient generation capacity will remain in 
the market or come forward in time to ensure adequate security of supply.  

(597)  Second,  electricity  market  reforms  are  indispensable  since  they  help  to  address 
concerns  about  inadequate  security  of  supply.  However,  most  Member  States 
have  yet  to  implement  appropriate  reforms.  The  Commission's  Market  Design 
Initiative therefore  proposes  a number of reforms to  improve the functioning of 
EU  electricity  markets  and  the  Commission  will  require  Member  States  to 
implement  reforms  to  accompany  the  planned  introduction  of  any  capacity 
mechanism. 

(598)  Third, even if a reformed market in principle has the potential to deliver secure 
supplies,  significant  uncertainty  persists  about  whether  an  increasingly  volatile 

164   For example the EU ETS. 
165   See  para.  233(e)  EEAG:  "The  measure  should  […]  give  preference  to  low-carbon  generators  in  case  of 
equivalent technical and economic parameters" and para. (220) "Aid for generation adequacy may contradict the 
objective  of  phasing  out  environmentally  harmful  subsidies  including  for  fossil  fuels.  Member  States  should 
therefore  primarily  consider  alternative  ways  of  achieving  generation  adequacy  which  do  not  have  a  negative 
impact on the objective of phasing out environmentally or economically  harmful subsidies, such as facilitating 
demand side management and increasing interconnection capacity." 

168 

 
 
                                                 
market  price  and  rare  scarcity  situations  can  drive  long-term  investment 
decisions.  Some  Member  States  have  therefore  decided  to  introduce  capacity 
mechanisms  to  ensure  security  of  electricity  supply.  These  mechanisms  involve 
State aid and must be notified to the European Commission under State aid rules. 
These mechanisms will be approved if Member States demonstrate their necessity 
and if the distortions of competition that they generate are minimised in line with 
State aid rules, taking account the outcome of the sector enquiry as summarised 
in this Communication.  

(599)  Fourth,  a  rigorous  adequacy  assessment  against  a  well-defined  economic 
reliability standard is crucial for identifying risks to the security of supply and for 
determining  the  necessary  size  of  any  capacity  mechanism.  Such  a  rigorous 
assessment  will  significantly  reduce  the  risk  of  over-procurement  and  help  to 
limit the distortions of competition that capacity mechanisms create. Further EU 
harmonisation  of  adequacy  assessments  will  help  to  increase  transparency  and 
build  confidence  in  the  results  of  these  assessments.  The  Commission's  Market 
Design  Initiative  therefore  proposes  to  develop  an  enhanced  EU-wide  adequacy 
assessment  methodology,  and  annual  adequacy  assessments  to  be  conducted  by 
the European Network of Transmission System Operators for Electricity.  

(600)  Fifth, the type of capacity mechanism chosen should suit the problem identified: 

(i)  Where  a  Member  State  identifies  a  long-term  risk  that  there  will  be 
insufficient  investment,  market-wide  capacity  mechanisms  (like  those 
introduced  in  the  UK  and  France,  and  planned  in  Ireland  and  Italy)  are 
likely  to  be  the  most  appropriate  form  of  intervention.  Market  reforms 
should  also  be  made  to  limit  the  State  aid  needed  through  the  capacity 
mechanism. 

(ii) Where  a  Member  State  identifies  a  temporary  risk,  a  strategic  reserve  is 
likely to be the most appropriate form of intervention, as it is designed to 
deal with situations where the market will deliver security of supply in the 
longer  term,  but  concerns  exist  about  capacity  in  the  short  to  medium 
term. Strategic reserves should only be deployed in emergency situations. 
They should be held outside the market to minimise distortions to its day 
to  day  functioning.  Strategic  reserves  must  be  transitional  measures, 
which  accompany  market  reforms  and  are  phased  out  as  soon  as  the 
reforms take effect. 

(iii)Where  a  Member  State  identifies  a  local  generation  adequacy  issue,  the 
choice of mechanism will depend on the specific market conditions. In the 
long  run  however,  the  local  problem  should  be  solved  by  better  grid 
connections  or  by  more  appropriate  bidding  zones  that  introduce  local 
electricity prices reflecting the balance of local supply and demand .   

169 

 
 
(iv) Where a Member State is concerned about insufficient development of a 
flexible  demand  side,  an  interruptibility  scheme  can  be  an  appropriate 
solution,  though  attention  must  be  paid  to  avoid  the  scheme  developing 
into a subsidy for energy-intensive industries. 

(v) Administrative  capacity  payments  are  unlikely 

to  be  appropriate, 
regardless of the specific issues facing a Member State, because the lack 
of  a  competitive  process  means  a  high  risk  of  failing  to  achieve  the 
capacity objective or of over-compensating.  

(601)  Sixth,  capacity  mechanisms  should  be  open  to  all  types  of  potential  capacity 
providers. This,  combined with  a competitive price-setting process, ensures  that 
competition  minimises  the  price  paid  for  capacity.  The  only  exceptions  are 
mechanisms  for  demand  response,  given  their  particular  ability  to  address 
underlying  market  failures,  and  strategic  reserves,  which  should  not  be  open  to 
new generation capacity to minimise market distortions. 

(602)  Seventh, market wide capacity mechanisms must be open to explicit cross-border 
participation  in  order  to  minimise  distortions  to  cross-border  competition  and 
trade,  ensure  incentives  for  continued  investment  in  interconnection  and  reduce 
the long-term costs of European security of supply. 

(603)  Finally,  the  sector  inquiry  has  shown  that  a  number  of  capacity  mechanisms 
already  exist  and  that  they  do  not  all  comply  with  State  aid  rules.  The 
Commission  will  work  with  Member  States  to  bring  all  existing  capacity 
mechanisms  gradually  into  line  with  State  aid  rules,  bearing  in  mind  the 
conclusions  of  the  sector  inquiry.  This  will  help  to  give  certainty  to  capacity 
providers  and  other  economic  actors,  and  ensure  that  the  right  signals  are 
provided to investors. 

170 

 
 
 
 
 
ANNEX 1: OVERVIEW OF RESPONDENTS 

1.  Replies to first round of eQuestionnaires (21 May - 24 June 2015) 

1.1. Overview of respondents to the first round of eQuestionnaires 

4 

7 

15 

9 

11 

12 

12 

12 

12 

15 

15 

France

Poland

Spain

Belgium

Germany

Ireland

Italy

Sweden

Denmark

Portugal

Croatia

1.2. Breakdown – type of respondents per Member State 

Replies in BE 

6 
30% 

1 
5% 

1 
5% 

4 
20% 

4 
20% 

4 
20% 

Generation

Demand response

Supply

Trading

Power exchange

Storage

171 

 
 
 
 
Replies in DE 

1 
3% 

1 
3% 

1 
3% 

4 
13% 

3 
9% 

4 
12% 

6 
19% 

6 
19% 

6 
19% 

Replies in DK 

1 
6% 

3 
20% 

1 
7% 

4 
27% 

2 
13% 

4 
27% 

Generation

Supply

Trading

Demand response

Association

Storage

Distribution

Interconnector

Power exchange

Generation

Supply

Demand response

Trading

Association

Power exchange

Replies in ES 

10 
29% 

1 
3% 

2 
6% 

3 
8% 

4 
11% 

7 
20% 

8 
23% 

Generation

Supply

Trading

Association

Distribution

Storage

Demand response

172 

 
 
 
 
 
1 
3% 

1 
3% 

2 
7% 

2 
7% 

6 
19% 

Replies in FR 

7 
23% 

6 
19% 

6 
19% 

Demand response

Generation

Supply

Trading

Association

Storage

Interconnector

Power exchange

Replies in HR 

1 
20% 

1 
20% 

1 
20% 

1 
20% 

1 
20% 

Generation

Interconnector

Supply

Trading

Other

Replies in IE 

1 
6% 

2 
12% 

3 
19% 

3 
19% 

4 
25% 

3 
19% 

Generation

Association

Demand response

Trading

Supply

Storage

173 

 
 
 
 
 
1 
3% 

2 
6% 

3 
9% 

3 
10% 

1 

3% Replies in IT 

8 
25% 

7 
22% 

Generation

Supply

Trading

Demand response

Interconnector

Storage

Association

Distribution

Replies in PO 

8 
31% 

6 
23% 

Generation

Trading

Supply

Demand response

Association

Power exchange

7 
22% 

1 
4% 

2 
8% 

4 
15% 

5 
19% 

Replies in PT 

1 
8% 

1 
8% 

4 
34% 

3 
25% 

3 
25% 

Generation

Supply

Trading

Demand response

Storage

174 

 
 
 
 
 
1 
4% 

2 
9% 

2 
9% 

Replies in SE 

1 
4% 

1 
4% 

6 
26% 

5 
22% 

5 
22% 

Supply

Generation

Trading

Distribution

Demand response

Association

Power exchange

Storage

2.  Replies to public consultation of Interim Report (13 April – 6 July 2016) 

Individual replies: 

1 

2 

3 

3 

2 

3 

18 

Energy companies*

RES producers

Large consumers

Power exchange

Private persons

Manufacturers

Academics

* involved in generation, supply, trade, DSR and/or storage 

175 

 
 
 
 
 
 
Associations/Interest organisations: 

1  1 

2  2 

2 

14 

21 

19 

EU**

Energy industry associations***

Consumer/EIU associations

RES/cogen + green/climate

DSR

Manufacturers

Raw materials (coal, gas)

other°

** ACER/CEER (joint reply) and ENTSO-E 
*** Associations of generators, suppliers, traders, DSR and/or storage providers, incl. 
public utilities 
° Friends of the Supergrid & Regulatory Assistance Project 

Public bodies: 

1 

6 

Government

TSO/IC

Regulator/NCAs

13 

3.  Replies to second round of eQuestionnaires (29 June - 19 August 2016) 

Public  bodies  (Government,  TSO,  NCA  and/or  regulator)  from  all  11  Member  States 
covered by the inquiry replied to the follow-up eQuestionnaire. No breakdown is given 
since many public bodies provided joint replies. 

176 

 
 
 
 
 
 
 
 
 
ANNEX  2:  THE  PARTICIPATION  OF  INTERCONNECTORS  AND  FOREIGN  CAPACITY 
PROVIDERS IN CAPACITY MECHANISMS  

1. 

Introduction 

This annex examines and aims to establish a potential design for effective cross-border 
participation  in  capacity  mechanisms.  The  analysis  presented  here  was  originally 
discussed with Member States in June 2015, and was publically consulted as part of the 
sector inquiry.  

The  sector  inquiry  has  found  that  cross-border  participation  is  not  yet  enabled  in  the 
majority of capacity mechanisms, and with different Member States developing different 
solutions  for  their  already  different  national  capacity  mechanisms  there  is  an  emerging 
risk of increasing fragmentation in the market.166 The outcome of the working group with 
Member  States  is  therefore  presented  below  to  stimulate  discussion  and  support  the 
development of solutions that can mitigate this risk.  

This  annex compiles  the requirements  in the Guidelines on State aid for environmental 
protection  and  energy  (EEAG)  related  to  the  participation  of  interconnectors  and/or 
operators in other Member States in capacity mechanisms, and recaps the importance of 
this  aspect  of  capacity  mechanism  design  (sections  1  and  2).  Section  3  describes  the 
challenges to accessing reliable capacity across borders, and section 4 identifies some of 
the main design questions that must be addressed by a Member State seeking a solution.  

Section 5 considers the possible benefits of a more harmonised approach to this issue and 
presents  the  potential  high  level  form  that  common  rules  could  take  and  some  of  the 
questions that would need to be addressed to further develop such an approach. Given the 
number  of  Member  States  currently  seeking  to  develop  solutions  for  cross-border 
participation in volume based market wide mechanisms (France, Ireland, Italy and UK) 
the  discussion  in  the  working  group  and  this  paper  focus  primarily  on the  challenge  of 
enabling cross-border participation in the central buyer and de-central obligation capacity 
mechanism  types167.  However,  the  other  capacity  mechanism  models  are  also  briefly 
discussed in section 6.  

2. 

What do the guidelines require? 

The EEAG include the following requirements related to cross-border participation in a 
generation adequacy measure: 

(226)   The  measure  should…take  into  account  to  what  extent  interconnection  capacity 

could remedy any possible problem of generation adequacy. 

166   See sections 5.2.2.6, 5.2.3.6, 5.2.3.7 and 5.2.3.8 of the Staff Working Document.  
167   For a description of different capacity mechanism types, see Chapter 3 of the detailed sector inquiry report. 

177 

 
 
                                                 
(232)   The  measure  should  be  designed  in  a  way  so  as  to  make  it  possible  for  any 
capacity  which  can  effectively  contribute  to  addressing  the  generation adequacy 
problem to participate in the measure, in particular… 

(a)   the  participation  of…operators  offering  measures  with  equivalent  technical 

performance, for example…interconnectors. 

(b)  the  participation  of  operators  from  other  Member  States  where  such 
participation is physically possible in particular in the regional context, that is 
to  say,  where  the  capacity  can  be  physically  provided  to  the  Member  State 
implementing the measure and the obligations set out in the measure can be 
enforced  (footnote:  schemes  should  be  adjusted  in  the  event  that  common 
arrangements  are  adopted  to  facilitate  cross-border  participation  in  such 
schemes).  

(233)  The measure should: 

(a)  not reduce incentives to invest in interconnection capacity; 

(b)  not undermine market coupling, including balancing markets. 

Figure  A2.1:  Summary  of  EEAG  requirements  related  to  the  cross-border 
participation  
Summary 

EEAG requirement  Objective 

(226) 

(232) 

1.  Should  take  the  contribution  of  interconnection  into 

account. 

2.  Should be open to interconnectors if they offer equivalent 

technical performance to other capacity providers. 

3.  Where  physically  possible,  operators  located  in  other 

member states should be eligible to participate. 

(233) 

4.  Should not reduce incentives to invest in interconnection, 

nor undermine market coupling.  

Source: European Commission 

3.  Aim of these requirements 

The more participation in a capacity mechanism, the more competitive it should be and 
therefore  the  higher  the  chance  that  the  mechanism  provides  value  for  money  for 
consumers. This is why the EEAG include a general requirement for all types of capacity 
provider to be able to participate in capacity mechanisms.  

178 

 
 
If  the  contribution  of  imported  electricity  is  not  taken  into  account  when  capacity  is 
procured  through  national  capacity  mechanisms,  this  would  result  in  significant 
overcapacity.  Note  overcapacity  will  also  result  if  the  participation  of  cross-border 
capacity is not fully enabled168.  

If cross-border participation in capacity mechanisms is not enabled, there will be greater 
distortion  of  the  signals  for  where  new  capacity  should  be  built,  and  an  increase  in 
overall system costs. And capacity mechanisms will fail to adequately reward investment 
in the interconnection that allows access to capacity located in neighbouring markets.  

If cross-border participation is enabled by requiring physical delivery of electricity into a 
particular market, or capacity payments are made (or penalties related to non-delivery are 
levied) per MWh to generators participating in a capacity mechanism, there is a risk that 
the  market  coupling  rules  (which  ensure  the  most  efficient  use  of  interconnection)  are 
undermined. There is also a risk of distorting the merit order in neighbouring markets.  

Therefore  the  aim  of  these  requirements  is  to  maximise  competition  in  capacity 
mechanisms, ensure efficient signals for investment in the right overall level of capacity 
in the Single Market, and in the right types of capacity and network infrastructure where 
they  are  most  needed,  and  enable  market  coupling  to  continue  to  deliver  the  most 
efficient use of existing resources in real time. 

For the findings of the sector inquiry on the importance of cross-border participation in 
capacity mechanisms, please see section 5.2.3.6. 

4.  Background 

4.1. Where does electricity flow at times of scarcity169? 

In  synchronous  electricity  networks,  such  as  that  in  continental  Europe170,  electricity 
flows to where it is demanded as long as the underlying network is strong enough. EU 
wholesale electricity markets are arranged into bidding zones, within which supply and 
demand  is  matched  to  create  a  single  bidding  zone  price.  These  bidding  zones  should 
reflect  the  capacity  of  the  underlying  network  to  transport  electricity.  Within  each 

168   The net benefits of avoiding self-sufficiency and making efficient use of the Single Market for security of 

supply have been estimated at up to EUR 7.5bn per year in the period 2015-2030. See Booz & Co, 2013, 'Study 
on the benefits of an integrated European energy market': 
https://ec.europa.eu/energy/sites/ener/files/documents/20130902_energy_integration_benefits.pdf 

169   Throughout this annex the term 'scarcity' is used to indicate a situation in which a bidding zone has insufficient 
supply to meet demand. In a bidding zone where a capacity mechanism is in operation, the term also implies a 
situation in which contracted/certified capacity resources are required to meet their capacity obligations and there 
is the potential for penalties to apply.  

170   Alongside the continental European synchronous system, Norway, Sweden, Finland and part of Denmark operate 
a synchronous system, Great Britain operates as a synchronous system, as does the island of Ireland (Ireland and 
Northern  Ireland).  Latvia,  Lithuania  and  Estonia  are  currently  part  of  the  same  synchronous system  as  Russia, 
Ukraine and Belarus.  

179 

 
 
                                                 
bidding  zone  market  participants  are  allowed  to  contract  power  with  any  capacity 
provider  without  limitations  –  i.e.  without  accounting  for  any  network  constraints  that 
might impact the ability to transfer power between sellers and buyers within the bidding 
zone. 

Bidding zones in the European Union are being 'coupled', in line with the target model. 
Market coupling aims to ensure the interconnectors that link bidding zones are used most 
efficiently to send power between markets to where demand is greatest.  

Most  of  Europe  is  now  coupled  day  ahead  with  implicit  allocation  of  cross-border 
transmission  capacity.  This  means  that  prices  and  interconnector  flows  are  jointly 
determined  in  a  single  step,  for  each  hour  of  the  following  day.  This  is  established 
through  the  matching  of  bids  and  offers  across  the  power  exchange/s  operating  in 
Europe. Roughly characterised, the prices for each hour in neighbouring markets are then 
compared, and the capacity of interconnectors is used to allow power offered in the lower 
priced zone to be matched with bids in the higher priced zone until either the prices in the 
two zones converge, or all available interconnection capacity is exhausted.  

The Commission Guideline on Capacity Allocation and Congestion Management, which 
came  into  force  in  mid-August  2015,  obliges  each  Member  State  to  develop  market 
coupling rules for day-ahead markets as well as intraday markets171. 

This price-matching process creates flow schedules for the interconnectors in real time. 
As  intraday market  coupling  is  introduced  this will adjust  any day ahead scheduling to 
reflect any differences in prices that emerge in intraday trading.  

171   http://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1445614788889&uri=CELEX:32015R1222 

180 

 
 
                                                 
Figure A2.2 – Day ahead market coupling status in November 2015 

Participants in coupled markets will continue to be able to buy hedging products: called 
'physical transmission rights' (PTRs) and financial transmission rights (FTRs)172.  

Physical  transmission  rights  will  enable  the  holder  to  nominate  a  flow  on  the  relevant 
interconnector at the day ahead stage. However, if this nomination is for a flow from a 
higher priced zone to a low priced zone and the price difference is sufficient, the market 
coupling  algorithm  will  reallocate  the  full  interconnector  capacity  (including  the 
nominated amount) to flow power from the low to the high priced zone.  

Financial transmission rights allow the holder to be paid the difference in price between 
two  coupled  markets,  but  do  not  give  any  nomination  right  or  allow  the  holder  to 
influence the flow of energy between coupled markets.  

Although  EU  rules  require  TSOs  to  resolve  network  congestions  without  limiting 
commercial  transactions  (including  across  borders),  TSOs  can  under  certain  conditions 
curtail  nominations  to  preserve  system  stability173.  Also  relevant  is  Article  4(3)  of  the 
Security  of  Electricity  Supply  Directive174,  which  states  that  'Member  States  shall  not 
discriminate  between  cross-border  contracts  and  national  contracts'.  This  rule  requires 

172   These will be defined in the guideline network code on Forward Capacity Allocation. 
173   See  Article  16(3)  of  the  Regulation  (EC)  No  714/2009  of  the  European  Parliament  and  of  the  Council  on 

conditions for access to the network for cross-border exchanges in electricity of 13.7.2009. 
174   Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006.  

181 

 
 
 
 
                                                 
TSOs to allow market coupling to determine flows, even if this means that in a situation 
where two coupled markets are both facing scarcity, the result of market coupling could 
be more severe scarcity in one country or zone because the price of electricity is higher in 
the neighbouring zone175. 

Market coupling is an effective way of ensuring the most efficient use of interconnection, 
but creates a certain challenge for enabling foreign participation in capacity mechanisms 
in Europe, because interconnectors have no influence over which direction power flows 
between markets, and individual capacity providers in a coupled market have very little 
influence on which direction power flows. With market coupling, it is not possible for a 
generator  or  demand  response  provider  in  a  neighbouring  zone  to  guarantee  that  its 
power  will  flow  to  consumers  in  another  bidding  zone.  Under  market  conditions176, 
power will flow to the bidding zone which offers the highest electricity price177.  

4.2. Which resources provide capacity across borders? 

As  explained  in  section  5.2.2.6  of  the  detailed  sector  inquiry  report,  the  contribution 
foreign  capacity  makes  to  a  neighbour's  security  of  supply  is  provided  partly  by  the 
foreign generators or demand response providers that deliver electricity, and partly by the 
transmission (interconnection) allowing power to flow across borders. Depending on the 
border, there can be a relative scarcity of either interconnection or foreign capacity.  

This  further  complicates  the  design  of  an  efficient  solution  for  enabling  cross-border 
participation  in  capacity  mechanisms  since  it  requires  the  chosen  design  to  enable  an 
appropriate split of capacity remuneration between interconnector and foreign capacity to 
reflect the relative scarcity of each. It also ideally requires this split to adapt over time – 
for example through a design that increases the reward for foreign capacity and reduces 
the reward for interconnection if over time the proportion of interconnection increases. 

175   Curtailments  of  cross-border  flows  are  nevertheless  frequent,  see  ACER  Monitoring  Report  2014,  page  162 
(observing limitations of cross-border interconnection to solve internal congestion at 56% of all interconnectors). 
In  its  market  design  initiative  and  when  developing  network  codes  the  Commission  will  further  specify  the 
framework  for  when  Member  States  or  TSOs  can  intervene  in  market  transactions  in  response  to  emergency 
situations.  
In emergency situations, Member States may intervene in the market-based coupling process and curtail cross-
border flows; solutions for this situation are being developed in the framework of the  
design 
initiative.  

market 

176  

177   Once capacity mechanisms are introduced they will reduce the extent to which local electricity prices remunerate 

capacity. Capacity will be fully or partially rewarded separately through capacity payments.    
The extent of this impact depends on how the capacity mechanism is designed. If a capacity mechanism acts as a 
replacement for high electricity prices at times of scarcity, there will not be an efficient signal for imports to the 
capacity mechanism zone at times they are needed. Nor will there be an efficient incentive for demand response 
participation  in  the  electricity  market  outside  the  capacity  mechanism.  Distortions  can  be  reduced  by  ensuring 
that the electricity market continues to function effectively even if a capacity mechanism is introduced.  

182 

 
 
                                                 
5.  Main design options – overview 

5.1. Consideration of imports in the generation adequacy assessment 

When  the  demand  requirement  is  set  in  a  capacity  mechanism,  the  total  capacity 
demanded can be adjusted to account for expected imports (at times of scarcity). This is 
sometimes  called  'implicit  participation'.  This  reduces  the  risk  of  domestic  over-
procurement  and  recognises  the  value  to  security  of  supply  of  connections  with  the 
Single  Market  for  energy.  However  EEAG  232  requires  explicit  cross-border 
participation (see 4.2 below). Implicit participation does not remunerate foreign capacity 
for  the  contribution  it  makes  to  security  of  supply  in  the  capacity  mechanism  zone.  If 
only domestic capacity receives capacity payments, there will be a greater incentive for 
domestic investment  than  investment  in  foreign  capacity  or  interconnectors  resulting  in 
less than optimal investment in foreign capacity and in interconnector capacity.  

For the GB Capacity Market (SA.35980), the UK used implicit participation for the first 
year of operating the mechanism, but the approval of the scheme included a commitment 
that  from  the  second  (2015)  auction  interconnected  capacity  would  be  able  to  directly 
participate  in  the  Capacity  Market.  In  the  second  auction  that  took  place  in  December 
2015  interconnectors  were  admitted  and  were  secured  1.8  GW  of  capacity  agreements, 
corresponding to approximately 4% of the total auctioned capacity178.  

5.2. Explicit cross-border participation 

If the locational investment signals are to be corrected, the contribution of imports to the 
capacity  mechanism  zone  must  not  only  be  identified,  but  the  providers  of  this  foreign 
capacity need to be remunerated for the security of supply benefits that they deliver to the 
capacity mechanism zone. This requires the 'explicit participation' of foreign capacity in 
the capacity mechanism. 

This  section  considers  four  aspects  of  design  that  need  to  be  considered  in  an  explicit 
participation solution: 

 

Identifying  the  amount  of  foreign  capacity  that  can  participate  /  receive 
remuneration,  through  establishing  the  contribution  of  potential  interconnector 
and foreign capacity participants. 

  Designing  the  obligations  and  penalties  that  will  apply  to  interconnector  and 

foreign capacity participants. 

 

the  counterparty  for  a  cross-border  capacity  contract  – 

Identifying 
ie. 
interconnectors, foreign capacity providers, or both could be signed up to capacity 
contracts. 

178   National Grid, 'Provisional Auction Results: T-4 Capacity Market Auction for 2019/20', Figure 4.  

183 

 
 
                                                 
 

If foreign capacity providers are to participate, which foreign capacity providers 
should be eligible? 

5.2.1   Establishing the contribution of interconnectors and foreign capacity  

The EEAG require the inclusion of foreign capacity 'where the capacity can be physically 
provided to the Member State implementing the measure'. It may therefore be justifiable 
to  exclude  providers  if  it  can  be  shown  that  their  location  means  they  could  never  be 
expected to deliver the required service. Effective cross-border participation requires an 
evaluation of the expected actual contribution of a capacity provider at times when it is 
required. This evaluation is often referred to as 'de-rating'. 

 

If  cross  border  capacity  is  the  counterparty,  unlike  for  domestic  capacity179  the 
required  evaluation  would  include  assessing  not  just  the  capacity  provider's 
ability to provide electricity when needed, but also their access to interconnection 
capacity. 

 

If  interconnectors  participate  directly  as  a  counterparty  then  their  available 
capacity needs to be calculated.  

Calculation  of  the  availability  of  interconnection  capacity  is  critical  as  conservative 
assumptions  will  lead  to  overcapacity,  and  overly  generous  assumptions  could  lead  to 
adequacy standards not being met.  

The  technical  capacity  of  interconnectors  represents  the  maximum  amount  of  power 
which  can  flow  through  the  interconnector  at  any  one  time.  There  is  always  some 
probability that this will not be available – either because of the technical availability of 
the  interconnector,  and/or  because  the  technical  capacity  of  the  interconnector  can  be 
used  to  flow  electricity  both  as  imports  to  the  capacity  mechanism  zone,  but  also  as 
exports  from  the  capacity  mechanism  zone,  depending  on  the  balance  of  supply  and 
demand in the zones connected by the interconnector. Therefore it may be necessary to 
de-rate the interconnectors according to expected contribution to the capacity mechanism 
zone at times when imports are needed to avoid scarcity180.  

However, interconnectors can flow power in two directions, and the same generation (or 
demand  response)  assets  can  contribute  to  security  of  supply  in  two  regions  if  peak 
demand  occurs  at  different  times.  In  fact  this  is  one  of  the  chief  security  of  supply 
benefits of the Single Market. Conversely, if peak demand occurs at the same time, the 

179   Though domestic capacity also requires domestic network access. 
180   Note an alternative capacity mechanism design might enable participants to 'self de-rate' rather than relying on 
central  de-rating.  Such  a  design  may  require  high  penalties  with  no  or  very  limited  exceptions  and  a  robust 
testing regime to avoid participants selling more capacity than they could reliably provide, but could avoid the 
difficulty of centrally establishing appropriate de-rating. 

184 

 
 
                                                 
generation (or demand response) assets can only benefit one of the regions (see Box A2.1 
for a more detailed explanation).  

It  is  in  consumers'  interest  to  ensure  the  full  value  of  interconnection  is  taken  into 
account, otherwise excess capacity will be built across Europe at unnecessary cost. De-
rating  of  resources  across  borders  will  likely  require  good  cooperation  between  TSOs, 
and common rules or guidance on de-rating of interconnectors may be required. It may 
be necessary to task ENTSO-E with establishing common principles for de-rating and the 
appropriate methodology for calculating suitable capacity figures for each border.  

It may also be necessary to task ENTSO-E with coordinating work to establish common 
rules  for  the  de-rating  of  foreign  capacity  resources  for  the  purpose  of  participation  in 
capacity mechanisms, so that a MW of capacity in each country/zone is comparable. 

In addition, to ensure judgements about the level of imports that can be expected are not 
overly conservative, it may be necessary to define common rules for all TSOs to apply in 
scarcity and emergency situations, and for example exactly what procedures are followed 
when there is concurrent scarcity in two neighbouring markets. This work also appears 
essential to prevent any contradiction between TSOs' rules and the requirements of EU 
law in relation to cross-border electricity trading. 

185 

 
 
 Box A2.1: How much do interconnectors contribute to security of supply? 

The interconnector's technical availability is one important consideration (ie. is the line 
itself  operational  or  not?).  The  long  term  average  technically  available  capacity  of  the 
interconnector could be identified and offered to participants seeking to sell capacity into 
a cross-border capacity mechanism181. This  de-rating should reflect the extent to  which 
the interconnector is expected to be unavailable for maintenance or otherwise technically 
unavailable at times of scarcity.  

However,  the  extent  to  which  an  interconnector  can  reliably  provide  imports  to  the 
countries it connects depends not just on the line's technical availability but also on the 
potential for concurrent scarcity in the connected markets. 

If  zone  A  only  has  a  winter  peak  demand  problem  and  connected  zone  B  only  has  a 
summer peak demand problem, each may expect 100% imports from the other at times of 
local  scarcity.  However,  if  countries  A  and  B  are  neighbours  with  similar  demand 
profiles  and  some  similar  generation  types  there  may  be  some  periods  of  concurrent 
scarcity where neither can expect imports from the other.  

Where  two  connected  markets  both  operate  capacity  mechanisms,  one  approach  would 
be  to  take  the  full  capacity  of  the  interconnector  and  allocate  it  between  the  two 
connected capacity mechanisms. This would enable capacity providers to make a choice 
between participation in either their domestic capacity mechanism or a neighbouring one. 
For example, if there was a 2 GW link between zone A and zone B, 1.5 GW of capacity 
could end up being sold to providers located in B wishing to participate in the capacity 
mechanism of zone A, and 500 MW to providers located in A wishing to participate in 
the mechanism of zone B.  

The  problem  with  this  approach  is  that,  with  the  two  markets  considered  together  as  a 
system,  the  interconnector  is  assumed  to  make  a  net  zero  contribution  to  security  of 
supply.  In  this  situation,  the  domestic  capacity  demanded  in  the  national  capacity 
procurement process in zone B would be increased by 1 GW to compensate for the net 
capacity  contracted  to  deliver  cross-border  to  zone  A.  This  would  only  be  an  efficient 
outcome for the system if zone A and zone B always experienced coincident scarcity and 
the interconnector indeed delivered no net security of supply benefit. 

In  practice,  however,  it  is  extremely  unlikely  that  scarcity  events  will  be  perfectly 
correlated  between  two  neighbouring  countries.  So,  to  avoid  a  situation  where  overall 
less  value  contribution  by  imports  to  security  of  supply  is  assumed  for  imports  than  is 
truly the case, a statistical judgement – de-rating of the interconnector/s on each border to 
reflect  expected  maximum  long-run  average  import  capacity  at  times  of  scarcity  –  is 

181   The interconnector's technical availability must already be assessed in the context the CACM Regulation, where 

tradeable capacities for the different market timeframes are determined in a comprehensive way. 

186 

 
 
                                                 
needed for each capacity mechanism about the value of imports at times of scarcity. The 
amount of capacity demanded domestically should be reduced by this amount, and this 
capacity is then available for allocation to foreign capacity providers. 

5.2.2  Obligations and penalties for interconnector / foreign capacity 

As discussed in section 5.4 of the detailed sector inquiry report, there are various ways of 
designing obligations and penalties in a capacity mechanism.  

Capacity  providers  may  be  required  to  either  be  available  by  declaring  that  they  are 
available to the TSO, or by placing a bid to deliver electricity, or they may be required to 
verify their availability by actually delivering electricity regardless of whether the market 
price  is  sufficient  to  cover  their  running  costs.  For  cross-border  capacity,  a  delivery 
requirement could require a foreign capacity provider to deliver electricity into its local 
market, or it could require that capacity provider to deliver electricity in its local market 
and  require  the  interconnection  between  the  two  markets  to  be  sending  electricity 
towards the market where the capacity mechanism is operating. With market coupling in 
operation,  however,  it  is  clear  that an  individual  foreign  capacity  provider  will  in  most 
cases have a very minor influence on the direction of flows across an interconnector (and 
the interconnector operator would have no influence over the flow direction).  

Different  capacity  mechanisms  also  apply  different  penalties  when  obligations  are  not 
met. They could apply a flat rate financial penalty, for example, or a penalty linked to the 
value of lost load. Over delivery payments may also apply – as is increasingly seen in US 
markets operating the 'pay for performance' principle.  

In  principle,  if  the  allocation  process  for  capacity  contracts  allows  interconnector  or 
foreign capacity to compete directly with domestic capacity, the obligation and penalties 
faced  by  the  interconnector  or  foreign  capacity  providers  should  be  the  same  as  the 
obligations and penalties faced by the domestic capacity providers.  

However, there are issues with imposing obligations and penalties on interconnectors or 
foreign  capacity  providers.  In  particular,  in  coupled  markets  even  if  foreign  capacity 
providers face additional incentives from a capacity mechanism to deliver capacity into 
their  local  market,  in  most  cases  this  will  not  significantly  increase  the  chances  of 
delivery in a particular direction across a constrained interconnector.  

Any  obligations,  penalties  or  over  delivery  payments  that  result  in  the  delivery  of 
capacity  that  would  not  otherwise  have  delivered  may  impact  on  market  coupling.  For 
example,  if  a  generator  in  zone  B  is  penalised  if  not  delivering  energy  into  zone  B 
whenever  there  is  scarcity  in  zone  A,  this  means  that  generator's  decision  to  run  is  no 
longer based only on its marginal costs and the price of electricity in zone B. It is also 
based on the cost of the penalty that will be levied by the zone A capacity mechanism if 
it does not produce. This could create additional distortions since it may mean this plant 
runs out of merit, displacing other plants in the local merit order.  

187 

 
 
In practice, in a situation where there is scarcity in zone A and the possibility of penalties 
for  capacity  providers  located  in  zone  B  participating  in  zone  A's  capacity  mechanism, 
the price in zone A should rise high enough to ensure the interconnector flows 100% in 
the direction of zone A. In this situation a delivery obligation on the capacity providers in 
zone B would have no impact.  

Some  obligations,  testing  and  penalties  may  still  be  required  to  ensure  that  foreign 
capacity  is  at  least  a  verifiable  and  reliable  source  of  capacity  in  its  local  market.  But 
because  of  the  potential  for  delivery  obligations  to  create  distortions  and  the  fact  that 
anyway  such  obligations  can  only  incentivise  actions  which  are  likely  to  have  a  very 
limited  effect  on  cross-border  flows,  delivery  obligations  may  not  be  appropriate  for 
interconnectors or foreign capacity. Establishing a relatively simple availability product 
instead  makes  cross-border  participation  much  more  readily  implementable  and  avoids 
creating  distortions  to  merit  order  dispatch  that  might  be  created  with  delivery 
obligations.  

Another issue that will arise with cross-border participation is the need to levy penalties 
on foreign resources. There appear to be various ways in which this could be enabled, for 
example through an appropriate governance regime tied to the agreement to participate in 
the capacity mechanism. 

5.2.3  Counterparty for a cross-border capacity contract 

The  Third  Energy  Package  and  EU  Network  Codes  require  that  interconnectors  are 
treated as transmission capacity, and fully unbundled, and that the flow of energy across 
borders is determined solely by electricity price differences. Member States are however 
considering  explicit  participation  designs  that  enable  the  direct  participation  of 
interconnector operators, foreign capacity, or a combination of the two.  

As identified in the sector inquiry and explained in section 3.2 of this annex, an efficient 
design  for  cross-border  participation  should  ensures  the  revenues  from  the  capacity 
mechanism that end up being paid to the interconnector and the foreign capacity reflect 
the  relative  contribution  each  makes  to  security  of  supply  in  the  zone  operating  the 
capacity mechanism.  

Including  foreign  capacity  providers  directly  in  a  capacity  mechanism  can  reveal  the 
value  (from  a  generation  adequacy  perspective)  of  additional  interconnection  capacity. 
For  example,  if  a  zonal  auction  for  capacity  in  a  neighbouring  zone  cleared  at  a  lower 
level  than  the  main  capacity  auction,  the  difference  between  the  two  clearing  prices 
would  reflect  the  value  of  increased  interconnection  capacity  between  the  two  zones. 
Member States should ensure that interconnection investment reflects these signals. This 
could be achieved by rules ensuring that the interconnector could receive the difference 

188 

 
 
between the zonal capacity prices182. This would mean that the principle of separation of 
generation and supply from network operation could be maintained. Competition should 
ensure  that  if  there  is  plentiful  supply  of  cheap  capacity  in  the  neighbouring  market 
relative  to  the  amount  of  interconnection,  then  the  interconnector  receives  most  of  the 
capacity revenue – sending signals for investment in more interconnection.183  

If  capacity  contracts  are  awarded  directly  to  an  interconnector  operator,  the  extent  to 
which  foreign  capacity  is  appropriately  rewarded  may  depend  on  the  obligations  and 
penalties associated with the capacity contract. With a delivery obligation (obligation for 
power  to  flow  to  the  capacity  mechanism  zone  at  times  of  scarcity)  and  high  enough 
penalties,  the  interconnector  may  seek  to  contract  with  capacity  providers  in  the 
connected market to pass on the delivery risk to counterparties better able to manage this 
risk (since the interconnector operator has no control of the direction in which electricity 
flows)  and  capacity  providers  in  the  connected  market  at  least  have  some  influence 
(though  this  may  also  be  marginal)184.  However,  in  a  model  with  interconnectors  as  a 
counterparty  with  a  capacity  payment  for  availability  and  no  delivery  obligation  (or 
obligation to 'subcontract' with foreign capacity providers) it is not clear how appropriate 
revenues would be awarded to foreign capacity providers. In this model, it seems likely 
that all the capacity revenue would accrue to the interconnector itself, regardless of the 
relative scarcity of interconnection and foreign capacity.  

In  some  situations  there  may  be  a  justification  for  including  interconnectors  as  a 
counterparty – for example, where there is a very large supply of foreign capacity and the 
interconnector is clearly the scarce resource. Some respondents to the public consultation 
–  particularly  TSOs  that  control  transmission  capacity  –  felt  that  an  interconnector-led 
participation model would in practice tend to deliver the same outcome as a model where 
foreign  capacity  participates  and  would  offer  benefits  in  terms  of  increased  simplicity. 
But  the  concern  in  the  previous  paragraph,  combined  with  the  potential  distortions  of 
imposing delivery obligations across borders (see section 4.2.2 of this annex), probably 
means  that  the  most  efficient  solution  would  require  foreign  capacity  to  participate 
directly across borders, rather than the interconnector participating. 

182  

183  

184  

Just  as  for  congestion  rents  earned  where  electricity  prices  differ  in  neighbouring  interconnected  markets.  For 
regulated  interconnectors,  any  capacity  congestion  rents  earned  would  need  to  be  appropriately  regulated  (eg. 
refunded  to  consumers  in  the  connected  markets  if  the  interconnector's  revenues  –  including  the  capacity 
revenues – are above its regulated cap). See Regulation 714/2009 Articles 16 and 17. 
If there is abundant interconnection capacity and not much foreign capacity available, the foreign capacity would 
receive  the  bulk  of  the  capacity  revenues  –  sending  signals  for  increased  investment  in  foreign  capacity. 
Likewise,  if  capacity  can  be  most  efficiently  provided  by  building  more  domestic  capacity  this  should  be  the 
outcome  –  signalled  by  the  foreign  capacity  bidding  too  high  to  be  competitive  in  the  neighbouring  capacity 
mechanism. 
In addition, any such hedging by interconnector operators may be challenging to enable in compliance with the 
restrictions  on  trading  activity  by  interconnector  operators  under  the  rules  of  the  third  package.  See  Directive 
2009/72/EC Chapter IV. 

189 

 
 
                                                 
5.2.4 Which foreign capacity providers should be eligible? 

In  principle  the  same  eligibility  rules  as  apply  in  the  domestic  market  should  apply  to 
foreign  capacity  –  with  foreign  demand  response  and  storage  eligible  to  compete 
alongside generation185. 

A  major  question  to  address  is  whether  capacity  providers  should  be  able  to  offer 
capacity  into  more  than  one  capacity  mechanism  for  the  same  time  period.  Limiting 
participation to a single mechanism might at first sight appear to be necessary, and some 
respondents to the public consultation – particularly generation companies – argued that 
capacity  resources  should  only  be  allowed  to  participate  in  a  single  mechanism.  This 
approach  would  however  lead  to  system-wide  over  procurement  if  every  zone  in  the 
system  operates  a  capacity  mechanism  (assuming  the  capacity  mechanisms  require 
people to fulfil a capacity obligation at any time for eg. the winter, or for the whole year). 

This example illustrates the problem: 

  Zone A wants to buy 10 GW of capacity. It wants it to be available all year.  

  Zone B wants to buy 10 GW of capacity. It wants it to be available all year. 

  There is 5 GW interconnection between these two zones. 

  Zone  A  identifies  that  it  can  count  on  4  GW  of  imports  from  B  at  times  of 

scarcity in A. 

  Zone  B  identifies  that  it  can  count  on  2  GW  of  imports  from  A  at  times  of 

scarcity in B. 

  Zone  A  procures  10GW  of  capacity.  It  might  procure  up  to  4  GW  of  this  from 

zone B if the capacity there is cheaper.  

  A  month  later,  Zone  B  procures  10  GW  of  capacity.  If  participation  was  only 
allowed in one capacity mechanism, Zone B could only procure the 10 GW from 
resources that have not contracted to provide capacity to zone A. 

  The  total  capacity  procured  by  A+B  would  be  20  GW.  So  unless  there  was 
perfectly correlated scarcity between A and B there would be over procurement. 
Also,  if  both  countries  had  an  equally  attractive  capacity  mechanism  then  in 
practice there would probably be no cross-border participation. 

185   Harmonised rules for de-rating, baselining, testing and verifying demand response may need to be developed to 
enable this although we recognise that this is difficult even at national level as individual DNOs often have their 
own procedures.  

190 

 
 
                                                 
Therefore,  to  avoid  system-wide  over  procurement,  the  participation  of  capacity 
providers  in  more  than  one  capacity  mechanism  for  the  same  time  period  must  be 
enabled. 

Concerns  about  the  potential  for  a  lack  of  reliability  stemming  from  multiple 
participation  should  be  mitigated  by  the  initial  de-rating  that  sets  a  maximum  level  of 
participation on each border, and also by the need for multiple penalties to also apply to 
encourage participants to make a rational judgement about whether they want to take on 
overlapping capacity obligations.  

5.3. Conclusions 

 

 

 

 

Although  it  mitigates  some  negative  effects,  simply  accounting  for  imports  when 
establishing  demand  for  capacity  does  not  actually  enable  cross-border 
participation in a capacity mechanism. 

Cooperation  between  TSOs  may  be  needed  to  establish  common  rules  for 
adequately  de-rating  cross-border  resources  and  calculate  transmission  capacities 
for cross-border participation in CRMs.  

Common and transparent rules for Member State and TSO actions in scarcity and 
emergency  situations  are  required  to  avoid  the  current  lack  of  trust  about  the 
potential for imports at times of concurrent scarcity.  

Availability obligation models probably do not distort market coupling, nor distort 
foreign markets (except possibly for some distortions due to any required testing). 

  With  the  interconnector  as  counterparty,  it  is  not  clear  that  an  availability  model 

delivers appropriate revenues to foreign capacity providers. 

 

 

The most appropriate design choices may therefore be to enable foreign capacity to 
participate  directly,  with  availability  rather  than  delivery  obligations  imposed  on 
the foreign capacity providers and the interconnector operator.  

To  avoid  system-wide  over  procurement,  capacity  providers  must  be  able  to 
participate in more than one capacity mechanism for the same time period.  

6.  Towards a  common  approach to  integrate volume based market  wide capacity 

mechanisms  

Designing  appropriate  rules  for  cross-border  participation  in  capacity  mechanisms  is 
challenging.  Given  the  different  capacity  mechanism  designs  already  emerging  across 
Europe,  there  may  be  value  in  developing  common  rules  at  least  for  cross-border 
participation  in  these  different  mechanisms.  Building  on  the  design  options  presented 
above, this section presents, a potential high level approach to cross-border participation 
in capacity mechanisms.  

191 

 
 
Although  a  harmonised  capacity  product  used  in  each  national  capacity  mechanism 
would no doubt simplify the design challenge and potentially increase overall efficiency 
by  simplifying  the  range  of  rules  investors,  market  participants,  regulators  and  system 
operators  across  Europe  have  to  understand,  a  harmonised  product  is  not  necessarily  a 
pre-requisite  for  cross-border  participation  in  capacity  mechanisms.  However,  a 
harmonised set of principles or rules specifically for cross-border participation, including 
defining a common product to account for the capacity to be supplied from neighbouring 
markets may be required to facilitate cross-border participation186.  

Although  there  would  be  a  cost  to  the  time  spent  developing  and  implementing  such  a 
proposal, it could deliver a number of benefits, for example: 

i)   reducing complexity and the administrative burden for market participants operating 

in more than one zone. 

ii)   removing  the  need  for  each  MS  to  design  a  separate  individual  solution  –  and 

potentially reducing the need for bilateral negotiations between TSOs. 

iii)  enabling  the  link  with  market  coupling  to  be  addressed  jointly  –  and  ensuring  the 

rights of MS with and without CMs are protected.  

iv)  leaving market coupling and all the work on the target model intact and ensuring that 
the  distortions  of  uncoordinated  national  mechanisms  are  corrected  and  the  Single 
Market able to deliver the anticipated benefits to consumers.  

6.1. High level approach 

One way to achieve the above benefits could be to: 

a)  Define the way in which the amount of imports that can be relied upon at times of 
scarcity  in  each  zone  operating  a  capacity  mechanism  should  be  calculated 
(interconnector de-rating); 

b)  Identify  the  capacity  providers  that  could  be  eligible  to  provide  capacity  into  a 

capacity mechanism in a neighbouring market; 

c)  Define the obligations and penalties that would apply to those who hold capacity 

contracts in relation to a capacity mechanism in a neighbouring market; 

d)  Define a competitive process for offering this import capacity to eligible capacity 

providers; 

e)  Define rules for the trading of this import capacity once allocated; 

186   Note such a product would not necessarily match the product contracted in the different capacity mechanism/s 

connected by these common rules.  

192 

 
 
                                                 
f)  Define  any  obligations  and  penalties  applicable  to  the  interconnector  operator, 

including rules on the enforcement of penalties across borders; 

g)  Influence  flows  in  the  direction  of  the  capacity  mechanism  if  market  coupling 

cannot deliver sufficient certainty; 

h)  Allocate the costs of foreign capacity to consumers; 

i)  Appropriately  remunerate  the  interconnectors  that  enable  the  participation  of 

cross-border capacity; and 

j)  Ensure compliance of TSOs. 

Market-based  rules  for  participation  in  capacity  mechanisms  should  complement 
European  rules  for  effective  coordinated  management  of  actual  simultaneous  physical 
scarcity situations in the grid. 

Following  the  analysis  in  the  first  half  of  this  annex,  the  presented  model  is  based  on 
foreign capacity providers participating directly across borders, rather than involving the 
direct  participation  of  interconnection.  In  addition,  the  capacity  product  is  based  on 
availability rather than delivery.  

a) Interconnector de-rating 

As  explained  in  section  4.2.1  of  this  annex,  a  statistical  judgement  –  de-rating  of  the 
transmission capacity across each border to reflect expected maximum import capacity at 
times  of  scarcity  –  is  needed  for  each  capacity  mechanism.  The  amount  of  capacity 
demanded  domestically  would  be  reduced  by  this  amount,  and  this  capacity  is  then 
available for allocation to foreign capacity providers. 

b) Eligible foreign capacity providers 

The eligibility of foreign capacity, and any de-rating applied, could be decided based on 
the criteria in the capacity mechanism for which capacity is being procured, or common 
rules could be established. The determined eligibility in either case would need to meet 
the  requirements  in  the  EEAG  requiring  all  potential  capacity  providers  to  be  able  to 
participate187. 

As  explained  in  section  4.2.4  of  this  annex,  to  avoid  overcapacity  in  the  system, 
individual capacity providers could be eligible to offer their capacity into more than one 
capacity mechanism for the same obligation period. 

187   See http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_working_group_4.pdf. 

193 

 
 
                                                 
Common rules and methodology requiring TSO cooperation in the de-rating of capacity 
in neighbouring markets are likely to be beneficial to ensure that a MW of capacity has 
comparable value regardless of its location.  

A  common  registry  may  be  helpful  to  facilitate  de-rating  and  any  certification,  pre-
qualification and testing of foreign resources, and could also facilitate secondary trading 
of capacity contracts. 

c) Obligations and penalties on foreign capacity providers 

Given the potential distortions that could arise with a delivery obligation, the obligation 
on capacity providers would likely need to be a relatively simple availability obligation. 
Ideally,  this  would  be  developed  in  cooperation  with  the  neighbouring  TSO,  however, 
even  without  such  cooperation  suitable  a  suitable  product  definition  might  be  found 
enabling  the  verification  of  availability  without  requiring  any  obligations  that  might 
introduce distortions to neighbouring markets. A local market bidding requirement might 
be one way of enabling a foreign capacity provider to demonstrate that they have made 
capacity available – though further consideration would be needed to determine exactly 
how an individual plant bid  might be  distinguished from the bids  of all generators in  a 
portfolio. Careful design of the availability obligation and no or very limited exceptions 
to  it,  along  with  a  clear  set  of  procedures  for  cooperation  (and  any  appropriate 
remuneration) between TSOs for testing capacity resources would be required to ensure 
the  reliability  of  contracted  resources  (and  avoid  the  problems  encountered  in  US 
markets with resources paid for availability and benefitting from various exceptions)188.. 

Following  the  de-rating  rules  described  above,  each  participant  would  be  required  to 
make  available  its  full  de-rated  capacity  in  periods  in  which  there  was  scarcity  in  the 
foreign capacity mechanism. 

In  a  model  where  capacity  providers  could  choose  to  sell  into  more  than  one  capacity 
mechanism,  the  penalties  that  apply  when  they  do  not  provide  the  contracted  service 
would  serve  an  important  function  in  ensuring  participants  have  the  right  incentives  to 
participate – or not – in more than one mechanism.  

A capacity provider that has sold capacity into the domestic capacity mechanism and a 
foreign  capacity  mechanism  would  need  to  meet  its  obligation  to  both  mechanisms  to 
avoid paying a penalty. Assuming the capacity provider is reliable, this could be possible 
if scarcity events in the connected markets are not correlated, since the obligations would 
not  overlap.  However,  if  a  capacity  provider  has  chosen  to  sell  into  two  capacity 
mechanisms and there is an hour of concurrent scarcity: 

188   See section 5.4.2.3 of the Staff Working Document for more on this. 

194 

 
 
                                                 
 

 

If  they  meet  their  domestic  obligation,  unless  they  also  make  available  enough 
capacity to the local market to meet their foreign obligation, they would need to 
pay a penalty to the foreign capacity mechanism zone. 

If they fail to meet their domestic and foreign obligations, they would need to pay 
two  penalties  –  one  to  the  domestic  capacity  mechanism  and  one  to  the  foreign 
capacity mechanism. 

The participation in more than one capacity mechanism, even if two penalties could be 
applicable, raises a question about potential overcompensation. If there is no concurrent 
scarcity,  there  is  no  overcompensation  to  these  providers  because  they  help  resolve 
scarcity  in  both  /  all  markets.  However,  if  there  is  concurrent  scarcity,  then  with 
insufficient penalties there is a risk of overcompensation to generators that sell into more 
than  one  mechanism.  And  the  general  direction  in  capacity  mechanism  development 
seems  to  favour  verifiable  physical  capacity  and  relatively  low  penalties  supported  by 
testing189, rather than high penalties.  

However,  any  potential  overcompensation  should  be  eroded  by  competition  –  ie. 
participants  should  be  willing  to  commit  to  an  additional  capacity  obligation  at  a  low 
price  if  the  reward  exceeds  the  risks.  This  should  mean  the  price  for  foreign  capacity 
would  be  competed  down  to  a  low  level  and  most  of  the  revenue  would  go  to  the 
interconnectors rather than the foreign capacity. If in fact the risk of concurrent scarcity 
turned out to be higher than expected, the price in future should adjust so that a higher 
share goes to the capacity providers. This should help ensure the allocation of capacity 
value  between  interconnectors  and  foreign  capacity  providers  would  remain  a  reliable 
signal of the relative contribution each makes to security of supply190.  

Allowing capacity providers to participate in more than one mechanism would also act as 
a  way  to  reveal  any  overly  conservative  central  assumptions  that  were  made  about  the 
chance of concurrent scarcity and therefore the level of imports that should be expected 
across  each  border.  However,  the  central  determination  of  the  maximum  amount  of 
foreign capacity that can participate in a capacity mechanism plays an important role in 
ensuring that the overall level of system security required by Member States is reached. 
In  other  words,  the  level  of  security  provided  by  the  foreign  capacity  should  not  be 

189   This seems to be for two reasons: i) political reasons, where there are suggestions that politicians responsible for 
security  of  supply  wish  to  have  a  verified  /  proven  source  of  capacity  contracted,  rather  than  a  capacity 
mechanism potentially being open to financial market participants; and ii) to enable financing, since the potential 
for high penalties may mean capacity contracts are less suitable as a basis for seeking financing. 
There may also be an added benefit of relatively low capacity mechanism penalties in that they leave space for 
the underlying electricity market to provide the main signal for flexibility (through high prices when electricity is 
scarce).  This  enables  the  electricity  market  to  continue  to  provide  the  import  signals  required  for  the  efficient 
operation of the Single Market. 
In a system where capacity providers were only able to participate in a single capacity mechanism, competition 
in this price setting process would be artificially constrained and the allocation of costs would be less reliable. 

190  

195 

 
 
                                                 
 
affected  by  the  possibility  of  capacity  selling  into  multiple  mechanisms  because  each 
zone has in any case limited the amount of foreign capacity that can participate. The level 
of security in a model with the potential for explicit participation of capacity providers in 
more than one capacity mechanism is in fact the same as the level of security provided by 
a statistical (implicit) approach to interconnector participation. 

Any capacity obligation should be complemented by robust penalties for non-availability. 
At a minimum, parties that consistently fail to meet their obligation should be able to lose 
100% of any revenue earned through capacity contract payments (though this may not be 
sufficient and higher penalties may be required, particularly to ensure participants make a 
sensible judgement about the possibility of participating in more than one mechanism). 
As a starting point for discussion, the penalty applicable to foreign capacity that fails to 
meet  its  cross-border  obligation  could  be  set  at  the  imbalance  settlement  price  in  the 
capacity  mechanism  zone  applying  the  penalty  for  each  MWh  not  made  available. 
Capacity providers could reduce any penalty due by trading with other capacity providers 
that are available and not delivering into the local capacity mechanism.  

With  different  capacity  mechanisms  in  Europe  already  applying  different  contract 
lengths, it may not for the time being be possible to choose a single rule for cross-border 
capacity  that  matches  each  current  national  model.  However,  short  contracts  for  cross-
border  participation  would  avoid  fixing  the  remuneration  between  interconnectors  and 
foreign  providers  for  long  durations,  and  allow  more  easily  for  future  adaptation  or 
removal of the cross-border participation model if required. It would also ensure that the 
de-rating of an interconnector or the ‘expected imports’ from a particular market could be 
updated annually to account for changing dynamics within that market and more closely 
reflect the real contribution of imports. 

More  granular  time-bound  products  may  also  be  appropriate  –  for  example  to  allow 
capacity providers to deliver capacity for one period (eg. during summer but potentially 
even  for  specific  balancing  periods)  in  one  mechanism,  and  another  period  in  another 
mechanism. These more granular products could emerge through secondary trading.  

d) Trading of cross-border capacity 

Under  the  present  approach,  foreign  capacity  providers  would  be  able  to  trade  their 
capacity  contracts  within  the  same  bidding  zone  to  allow  them  to  manage  risks  of 
changing  circumstances  (for  example  required  maintenance  or  unplanned  outages). 
Foreign  capacity  providers  would  therefore  be  free  to  trade  their  contracts  to  other 
eligible  providers  that  have  not  already  sold  all  of  their  (de-rated)  capacity  into  the 
relevant capacity mechanism (ie. the mechanism for which the contract is being traded). 
Some kind of registry and/or notification procedure is likely to be required to enable this.  

e) Obligations and penalties on interconnector operators 

Under the present approach, interconnectors would have an obligation to be operational 
in  either  connected  zone. 
times  of  system  scarcity 
(technically  available)  at 

196 

 
 
Interconnectors  have  no  control  over  the  direction  of  flows  on  the  interconnector  so  it 
would  not  seem  justified  to  penalise  them  if  the  flows  over  the  interconnector  are  not 
what  was  expected  when  the  de-rating  based  on  expected  flows  was  carried  out. 
However, the risk of interconnector operational availability is mainly within the control 
of the interconnector operator. If not technically available, they should therefore face the 
same penalty as foreign capacity providers (and foreign capacity providers should not be 
penalised in periods when the interconnector is unavailable).  

Since  interconnector  operators  would  potentially  be  'involuntary'  participants  in  each 
measure and would have no direct control over the capacity price they receive (since the 
price  left  for  interconnection  would  be  determined  by  the  voluntary  bids  of  foreign 
capacity providers to participate) it would be appropriate to cap the maximum penalties 
that could be levied on interconnectors for lack of availability. 

f) Competitive cross-border bidding process 

The import capacity established for each interconnector (into each capacity mechanism) 
could be competitively allocated in various ways: 

  explicit auction: where TSOs (or exchanges, or even the interconnector operators) 
auction the available cross-border capacity in advance of any capacity allocation 
process  within  a  national  capacity  mechanism.  Effectively,  they  would  be 
auctioning  a  ticket  allowing  entry  into  the  related  capacity  mechanism,  in  the 
same way as interconnector capacity can be auctioned explicitly – separately from 
electricity. Those successful in the ticket auction would then be able to bid into 
the capacity auction in the related capacity mechanism (if a central buyer model) 
or offer their capacity in the market to suppliers needing to fulfil their obligations 
(if a de-central obligation model).  

 

 

implicit auction (central auction model): where foreign capacity bids directly into 
a  national  capacity  auction,  which  establishes  a  price  for  each  cross-border 
capacity  zone.  This  is  similar  to  the  way  interconnector  capacity  is  implicitly 
auctioned along with electricity in coupled markets.   

implicit auction (de-central obligation model): where an auction is held in which 
foreign capacity providers offer their capacity and domestic suppliers offer to buy 
it. This could for example be hosted on an exchange.  

  direct selling to suppliers (only in a de-central obligation model): where foreign 
capacity  providers  offer  their  capacity  directly  to  suppliers  in  a  capacity 
mechanism seeking to fulfil their obligation. Exchanges may be able to help limit 
trade to the maximum import capacity – for example if foreign capacity providers 
were  required  to  trade  only  on  exchanges.  Ensuring  the  interconnector  operator 
also receives remuneration for its service could be challenging in such a system. 
It might be possible for the interconnector to offer a 'capacity rights' product on 
an  exchange,  and  for  capacity  providers  to  be  required  to  simultaneously  buy 

197 

 
 
these capacity rights at the same time as an offer to provide capacity is accepted. 
If  the  transactions  cannot  be  concluded  simultaneously  some  basis  risk  (see 
below) will remain.  

With  an  explicit  auction,  the  gap  between  the  entry  ticket  auction  and  the  domestic 
auction  would  create  an  additional  risk  ('basis  risk')  for  participants,  since  when 
competing in the ticket auction they would be uncertain about the value of capacity in the 
system  for  which  they  were  bidding  to  participate.  This  could  result  in  a  lower  price 
being  bid  for  the  entry  tickets  to  compensate  for  this  risk  and/or  reduced  competitive 
pressure, as this risk presents a barrier to entry.  

An implicit auction appears likely to be the most efficient solution since it eliminates any 
basis risk.  

g) Influencing interconnector flows (without distorting market coupling) 

Market  coupling  combined  with  more  integrated  balancing  markets  should  ensure 
electricity flows where it is needed in times of scarcity. Member States should take the 
necessary steps to ensure market rules function in this regard by implementing the third 
package,  including  applying  network  codes  and  ensuring  balancing  markets  work 
properly and electricity prices can rise to reflect scarcity. 

In the event of a scarcity event in two Member States at the same time that brings prices 
to in both markets to the market coupling price caps (currently 3000 EUR/MWh for the 
purposes of day ahead market coupling and below most estimations of the value of lost 
load)  rules could  be  developed  to  enable  electricity  flows  in  proportion  to  cross-border 
capacity  contracts  held  rather  than  the  current  default  of  equal  sharing  of  curtailment. 
However  this  would  only  be  appropriate  as  long  as  the  market  coupling  price  cap  is 
significantly  lower  than  the  value  of  lost  load,  as  otherwise  such  a  system  would 
discriminate against energy only markets.  

h) Paying for foreign capacity 

It would seem appropriate to pay foreign capacity in the same way as domestic capacity. 
If foreign capacity participates through an implicit auction or directly through contracts 
with  obligated  suppliers,  this  approach  would  appear  straightforward.  If  it  participates 
through  an  explicit  auction,  financing  arrangements  would  have  to  be  designed  to 
allocate  the  costs  to  the  suppliers  (ultimately  consumers)  benefitting  from  the  capacity 
mechanism. 

Any penalties paid by foreign capacity providers could be refunded to the suppliers that 
paid for the capacity.  

198 

 
 
i) Appropriately remunerate interconnectors 

In a central buyer model where foreign capacity participates directly through an implicit 
auction,  interconnectors  could  be  rewarded  with  the  difference  between  the  zonal 
(foreign) capacity price and the overall (domestic) capacity clearing price.  

In  a  de-central  obligation  model,  the  difference  between  an  implicit  auction  clearing  / 
average price and a reference price for capacity in the domestic market would need to be 
paid  to  the  interconnector  operators  by  the  beneficiaries  of  the  capacity  mechanism. 
Additional  design  questions  arise  from  this  since  it  would  be  necessary  to  collect  this 
money  from  consumers  in  the  capacity  mechanism  zone  and  transfer  it  to  the 
interconnector  operators.  Alternatively,  an  explicit  auction of  entry  tickets  would  allow 
the  interconnector  to  access  revenues  directly  from  the  foreign  capacity  providers,  but 
would  create  inefficiency  in  the  form  of  basis  risk  (as  described  in  section  5.7  of  this 
annex).  

Any penalties paid by interconnectors could be refunded to the suppliers that paid for the 
capacity.  

j) Ensuring compliance with the common rules 

Despite  existing  legislation  preventing  interference  to  stop  exports  at  times  of  scarcity 
except in specific situations (see section 3.1 of this annex) some fear potential action by 
Member  States  or  TSOs  to  limit  exports  if  necessary  to  prevent  local  unmet  demand. 
Irrespective of the validity of the argument, this is an issue that would need to be tackled 
with or without capacity mechanisms. More harmonised, transparent protocols for TSOs 
and clear rules for Member States to limit their interventions in cross-border flows could 
avoid  this  problem  along  with  appropriate  sanctions  for  any  infringement,  to  ensure 
everyone has confidence that market coupling delivers electricity to higher priced zones.

199 

 
 
7.  Cross-border participation in other capacity mechanism types 

7.1. Cross-border participation in strategic reserves 

Unlike  other  capacity  mechanisms  that  allow  beneficiaries  of  capacity  remuneration  to 
continue to  compete in  the electricity  market, if strategic reserves are designed to truly 
keep their capacity outside the market there may not be the same need to enable explicit 
cross-border participation.  

To  avoid  a  distortion  to  cross-border  flows  (and  the  creation  of  missing  money  and 
distortions to investment signals locally and in neighbouring markets) a strategic reserve 
should in principle only be dispatched once all  possibility for the market to deliver has 
been fully tested and exhausted, the market price cap has been reached because there is 
still  unmet  demand,  and  there  is  no  more  potential  for  imports.  To  avoid  cross-border 
distortions  once  intraday  markets  are  coupled,  this  would  mean  that  a  strategic  reserve 
could only be dispatched after gate closure when all possibility for intraday imports had 
been tested and there was still scarcity. In this situation the use of the reserve should also 
presumably be priced into the imbalance settlement calculation at the value of lost load to 
avoid creating missing money191.  

If a reserve is not designed in this way, however, and does impact on investment signals, 
for  example  by  acting  as  a  replacement  for  scarcity  prices  when  dispatched  before  the 
market has had a full opportunity to solve a supply shortage and/or at a price that does 
not reflect the value of lost load, there is a distortion to correct. 

Strategic reserve capacity could be procured in a neighbouring bidding zone. However, 
this  would only  appear  to  help  security  of  supply  in  the  zone  paying  for  the  reserve  in 
certain circumstances. 

Figure A2.3 shows a scarcity event in zone A, which has contracted a strategic reserve in 
zone B. Zone B either has less scarcity than zone A, or has a lower price cap. The reserve 
is dispatched because A is experiencing scarcity. However, if the interconnector between 
A and B was already sending power from B to A, the dispatch of the reserve will make 
no difference to security of supply in A.  

In  discussion  on  the  interim  report,  some  stakeholders  identified  the  following  distortion  where  a  strategic 
reserve  is  employed,  which  would  be  an  issue  even  when  the  reserve  is  only  dispatched  after  intraday  gate 
closure. Since reserves hold capacity outside the market the merit order is always distorted when the market price 
is  set  by  capacity  with  higher  running  costs  that  the  capacity  held  in  reserve  (since  if  the  reserve  capacity 
participated in the merit order then in some hours it would have set a lower price). Although some will argue that 
capacity in reserve would have closed if the reserve contract had not been made available, this may mean that 
electricity  prices  in  a  market  with  a  strategic  reserve  are  generally  higher  than  they  would  have  been  had  the 
reserve not been introduced. Unlike the distortions created by market wide capacity mechanisms, however, this 
potential distortion would not reduce incentives for investments in capacity in neighbouring bidding zones, nor in 
transmission between the strategic reserve zone and its neighbours.  

191  

200 

 
 
 
                                                 
Figure A2.3: Cross-border strategic reserve – no benefit to A 

Source: European Commission 

In general, it is to be expected that the dispatch of the strategic reserve would push prices 
in the market to the price cap, because this should reflect the value of electricity at a time 
when  delivery  of  the  reserve  capacity  is  required  (and  because  if  it  is  dispatched  at  a 
lower price it may create missing money in the market where it is located). However, if 
the dispatch of A's strategic reserve into B would set market prices in B to the price cap 
in A then the establishment of a cross-border reserve may have to be limited to situations 
in which two countries share the same price cap.  

The  dispatch  of  such  a  reserve  may  also  need  to  be  limited  to  situations  in  which  the 
price caps were reached in both A and B to avoid distortions in B. Similar rules to those 
proposed in section 5.8 of this annex could however be used to ensure that, in a situation 
of concurrent scarcity in two Member States which have the same price cap, the power 
contracted in the reserve could be used to send power from zone B to zone A (see Figure 
A2.4).  

Figure A2.4: Cross-border strategic reserve – forced flow to A 

Source: European Commission 

201 

 
 
 
 
 
If  zone  B  also  had  a  capacity  mechanism,  however,  any  capacity  contracted  from 
capacity providers in zone A would presumably also have to be taken into account before 
interconnector flows were adjusted in favour of A by the dispatch of the strategic reserve.  

It  therefore  appears  that  the  situations  in  which  cross-border  reserve  capacity  could 
actually  be  useful  to  a  capacity  mechanism  zone  are  limited  unless  interconnector 
capacity  was  reserved  specifically  to  allow  the  reserve  to  be  dispatched  across  border. 
This  however  would be inefficient because it would permanently reduce  the amount  of 
interconnection capacity available commercially for market coupling.  

Some respondents to the public consultation agreed that there may be a limited need for 
cross border participation in strategic reserves, and agreed that in practice it may not be 
readily  possible  to  implement.  However,  other  respondents  felt  that  if  cross  border 
participation in market wide volume based capacity mechanisms was required then cross 
border participation should also be required in all other capacity mechanisms. However, 
they do not explain how in practice such participation might be enabled. 

In the future, the design of strategic reserves may adapt, and as energy markets become 
more  regional  it  would  also  be  possible  to  design  more  regional  strategic  reserves  that 
might overcome the limitations of current designs. Even where designs remain basically 
national,  where  neighbouring  Member  States  are  open  to  the  participation  of  their 
capacity  resources  in  a  neighbour's  strategic  reserve  (ie.  where  they  would  accept 
capacity being removed from the local market for use only in a concurrent stress event to 
the  benefit  of  the  neighbour),  the  Member  State  creating  the  reserve  could  make 
arrangements  to  include  this  cross  border  capacity  in  the  competitive  process  for 
establishing the reserve. Where a foreign resource would only be expected to be useful 
25%  as  often as  a  domestic resource because  of the conditions described earlier  in this 
section,  the  strategic  reserve  may  however  only  choose  the  foreign  capacity  above 
domestic capacity where the foreign capacity is for example at least four times cheaper 
than the domestic capacity (depending on its risk aversion). 

7.2. Cross-border participation in tenders for new capacity 

A  tender  could  be  opened  to  cross-border  capacity.  The  sector  inquiry  found  that  the 
2003  tender  in  Ireland,  and  the  2014  tender  in  Belgium,  were  both  open  to  foreign 
capacity  providers  that  were  prepared,  if  successful,  to  connect  permanently  to  the 
capacity  mechanism  bidding  zone.  In  the  Irish  example,  the  successful  beneficiaries  of 
the tender were located in the Irish bidding zone, and the Belgian tender was abandoned, 
so there are no examples we are aware of in which a tender for new capacity has actually 
been used to pay for foreign capacity.  

Although  opening  a  tender  across  borders  would  remove  the  immediately  distortive 
impact on locational investment signals of a tender only for domestic capacity, it would 
not remove the longer term distortive effects of the tender but potentially increase them 
(since  now  potentially  not  only  domestic  capacity  providers  but  also  foreign  capacity 
providers may be prompted to close earlier than otherwise because of competition from a 

202 

 
 
new,  efficient  competitor  subsidised  by  the  tender.  These  potential  impacts  of  a  tender 
are discussed in more detail in section 6.2.1 of the detailed sector inquiry report. 

7.3. Cross-border participation in price based capacity mechanisms 

Although  in  the  existing  Irish  capacity  payments  scheme,  remuneration  is  available  to 
foreign capacity providers, the mechanism for enabling this (effectively an addition paid 
for  imports  and  levy  on  exports)  may  not  be  compatible  with  market  coupling  since 
market  coupling  requires  electricity  flows  to  be  determined  on  the  basis  of  electricity 
prices,  not  capacity  prices.  Ireland  is  in  any  case  adapting  its  market  arrangements, 
including transitioning from the existing capacity payments model to a new central buyer 
capacity mechanism. 

Given the downsides of a capacity payments approach in which capacity remuneration is 
set  without  a  competitive  process,  which  are  described  in  section  6.2.4  of  the  detailed 
sector inquiry report, and the trend away from these approaches in Europe, the potential 
for including foreign capacity in these models is not considered further here. 

203 

 
 
Appendix  2.1:  Summary  of  a  possible  approach  for  cross-border  participation  in 
central buyer and de-central obligation capacity mechanisms 

Design area 

Proposal 

1) Amount of 

foreign capacity 
to include 

2) Identifying 

eligible capacity 
providers across 
border 

3) Allocating 
capacity 
certificates / 
contracts to 
foreign capacity 

4) Obligations and 
penalties for 
foreign capacity 
providers 

204 

  For  each  neighbouring  bidding  zone,  the  TSO  would 
calculate  the  expected  average  long  run  amount  of 
imports  expected  into  the  capacity  mechanism  zone  at 
times of scarcity in the capacity mechanism zone. 

  All  potential  capacity  providers  in  the  neighbouring 
system  would  be  eligible,  except  possibly  some 
exceptions if necessary to avoid overcompensation. 

  Foreign  capacity  providers  would  be  de-rated  in  the 
same  way  as  domestic  capacity  providers,  taking  into 
account their technical long run reliability.  

  Capacity providers would be able to participate in more 
than one capacity mechanism to avoid system-wide over 
procurement. 

  Zonal auctions on each border in which foreign capacity 
providers  would  offer  their  capacity  and  the  amount 
determined in 1) be selected based solely on the EUR / 
kW  price  bid.  If  there  is  not  enough  capacity  offered 
below  the  capacity  mechanism  zone  price  then  less 
foreign  capacity  would  be  accepted  (ie.  the  maximum 
price  paid  for  foreign  capacity  would  =  the  national 
price).  

  The foreign capacity would be paid the clearing price. 

  The interconnector operator would be paid the difference 
between  the  zonal  clearing  price  and  the  capacity  price 
in  the  capacity  mechanism  zone  –  with  revenues 
regulated appropriately. 

  All  cross-border  certificates 
allocated for only one year. 

/  contracts  would  be 

  Foreign capacity providers would need to be available in 
the foreign zone for any period in which there is scarcity 
in  the  capacity  mechanism  zone.  They  would  need  to 
demonstrate  their  availability  by  placing  a  bid  in  their 
local  market.  There  would  be  no  (or  very  limited) 
exceptions to this obligation (eg. related to maintenance, 

 
 
fuel supplies etc). 

  For  any  period  in  which  foreign  capacity  providers  are 
not  available,  they  would  pay  a  penalty,  eg.  the 
imbalance price in the capacity mechanism zone. 

 

If  a  capacity  provider  has  chosen  to  sell  into  two 
capacity mechanisms and there is an hour of concurrent 
scarcity: 

o  If  they  meet  their  domestic  obligation,  unless  they 
also make available enough capacity to the market to 
meet their foreign obligation, they would need to pay 
a penalty to the foreign capacity mechanism zone. 

o  If  they  fail  to  meet  their  domestic  and  foreign 
obligations, they would need to pay two penalties – to 
both  the  domestic  capacity  mechanism  and  to  the 
foreign capacity mechanism zone. 

  Foreign capacity providers would be tested by the local 
TSO  if  they  did  not  deliver  during  the  capacity 
certificate  /  contract  period  to  ensure  they  are  actually 
able  to  deliver  electricity.  Fines  would  apply  for  failed 
tests.  

 

Interconnectors  would  have  an  obligation 
to  be 
operational (technically available) at times of scarcity in 
either connected zone. 

  Since 

interconnector  operators  will  potentially  be 
'involuntary'  participants  in  each  mechanism  and  would 
have  no  direct  control  over  the  capacity  price  they 
receive (since the price left for interconnection would be 
determined  by  the  voluntary  bids  of  foreign  capacity 
providers  to  participate)  it  would  be  appropriate  to  cap 
the  maximum  penalties 
levied  on 
interconnectors for lack of availability. 

that  could  be 

5) Obligations and 
penalties on 
interconnector 
operators 

6) Influencing 

interconnector 
flows (without 
distorting market 
coupling) 

205 

  There  would  be  no  possibility  for  interconnector  flows 
to  be  influenced  by  capacity  contracts  until  market 
coupling price caps are reached. 

  Rules  could  be  developed  to  ensure  electricity  flows  in 
proportion to the cross-border capacity contracts held in 
an episode of concurrent scarcity where market coupling 
price  caps  are  reached  in  two  interconnected  countries 

 
 
and these price caps do not reflect the value of lost load. 

7) Trading of 
capacity 
certificates / 
contracts 

  Foreign  capacity  providers  would  be  able  to  trade  their 
capacity contracts within the same bidding zone to allow 
them  to  manage  risks  of  changing  circumstances  (for 
example required maintenance or unplanned outages).  

8) Financing 

  Trading would be limited to other eligible providers that 
have  not  already  sold  all  of  their  de-rated  capacity  into 
the relevant capacity mechanism (ie. the mechanism for 
which the contract is being traded).  

  A registry is likely to be required to enable this. 

  The  consumers  in  the  capacity  mechanism  zone  would 
cover  the  costs  of  capacity  contracted  in  that  capacity 
mechanism (including foreign capacity).  

  Any penalties paid by foreign capacity providers would 

accrue to the consumers that paid for the capacity. 

206 

 
 
 
 
 
Appendix 2.2: Pre-requisites to enable the possible approach described in section 5 

Requirement 

Are harmonised rules a pre-requisite? 

National TSO to 
identify the amount of 
foreign capacity that 
contributes on each 
border 

  No,  TSOs  are  already  doing  this  in  existing  national 

mechanisms. 

  Harmonised  rules  would  however  be  beneficial  to  avoid 
overly conservative assumptions and ensure transparency.  

  In  the  absence  of  harmonised  rules  to  determine  how  this 
calculation should be  made,  the methodology  used should 
be scrutinised and agreed by the regulators in the capacity 
mechanism zone and the neighbouring zone. 

  In addition, harmonised rules on TSO protocols for dealing 
with  concurrent  scarcity  situations  would  help  reduce 
uncertainty (and therefore conservative judgments) related 
to the establishment of the expected contribution of cross-
border capacity. 

Identifying eligible 
cross-border capacity 

No, a declaration could be required that the provider is not 
in  receipt  of  support  designed  to  remunerate  its  full 
investment costs.  

De-rating cross-
border capacity 

Including cross-
border demand 
response capacity 

Testing foreign 
capacity providers 

Trading of capacity 

207 

No, but harmonised rules would be helpful to increase the 
accuracy of de-rating and ensure the way resources are de-
rated is consistent and transparent across the EU.  

Potentially,  though  it  may  also  be  possible  in  the  interim 
with  bilateral  arrangements  between  TSOs  (and  maybe 
DSOs). Arranging for appropriate meter data is likely to be 
challenging.  Harmonised  rules  in  this  area  may  be  a  pre-
requisite. 

No, but cooperation with the neighbouring TSO would be 
required  to  ensure  periodic  testing  of  capacity  providers 
and  avoid  paying  for  capacity  that  can  never  actually 
deliver. Harmonised rules may be helpful to make it easier 
for TSOs to agree on testing requirements and procedures. 

in  cooperation  with 

No, a registry  for trading could be established unilaterally 
the  neighbouring  TSO.  A 
or 
harmonised  registry  may  have  advantages  in  the  longer 
term as  more market wide  mechanisms are  introduced but 
the costs and benefits would need further consideration. 

 
 
 
 
ANNEX  3:  SUMMARY  OF  REPLIES  OF  THE  PUBLIC  CONSULTATION  AND 
QUESTIONNAIRES  TO  PUBLIC  BODIES  FOLLOWING  THE  PUBLICATION  OF  THE 
INTERIM REPORT 

1.  Approach  

The Commission published its interim report of this sector inquiry on 16 April 2016 for 
public consultation until 6 July 2016. As summarised in Annex 1, 114 stakeholders from 
19 Member States plus Norway and Switzerland have submitted observations.  

This  Annex  summarises  the  feedback  received  through  the  public  consultation  and 
indicates how the Commission has taken into consideration the main messages received 
in this final report. This summary refrains from tallying the replies, mainly because the 
responses  cannot  be  given  the  same  weight  and  providing  scores  would  not  be  a  fair 
representation of the opinions expressed. 

2. 

Feedback received during the public consultation (13 April – 6 July 2016) 

2.1. 

The role of the market and the need for capacity mechanisms 

The  interim  report  argued  that  capacity  mechanisms  may  be  appropriate  instruments  to 
tackle persistent  market failures. At the same  time, it made clear that important market 
reforms  and  regulatory  improvements  could  reduce  the  need  for  capacity  mechanisms. 
With respect to this proposition, a large number of respondents expressed the view that 
the  Commission  was  too  sceptical  about  the  ability  of  the  market  to  deliver  the  right 
investment  signals,  and  too  quick  to  conclude  that  capacity  mechanisms  might  be 
required.  

The Staff Working Document accompanying the final report has been amended by giving 
more attention to the necessary market reforms especially in Chapter 2.3. Furthermore, in 
Chapter  4,  related  to  the  necessity  assessment,  the  'last  resort'  nature  that  capacity 
mechanisms must have – as underlined by many market participants  – has been further 
emphasised.  

2.2.  Adequacy assessments must improve 

The responses to the public consultation show particularly strong support for the tentative 
conclusion  that  adequacy  assessments  should  be  improved  so  as  to  provide  a  more 
objective and transparent picture of the adequacy situation to justify the introduction of a 
capacity mechanism. Metrics such as LOLE, VOLL and CONE should be used and based 
on common definitions. While there is recognition that security of supply may be valued 
differently across the EU, the need for more transparency and objectivity in assessing the 
security of supply situation can avoid expensive and unnecessary overprotection. Various 
respondents  raised  the  fact  that  current  adequacy  assessments  do  not  contain  an 
assessment  of  the  future  economic  viability  of  their  generation  fleet  which  may 
compromise the usefulness of an adequacy assessment for identifying the future need for 
a  capacity  mechanism.  The  Commission  has  included  these  observations  in  Chapter  4 

208 

 
 
and  proposes  to  strengthen  and  harmonise  adequacy  assessments  as  part  of  the  Market 
Design Initiative.  

2.3. 

Preferred design types 

As regards the design and types of capacity mechanisms, the consultation replies echoed 
support  for  the  Commission's  observations  related  to  the  benefits  of  open,  technology-
neutral,  volume-based  and  market-wide  capacity  market  schemes.  The  large  majority 
also shared the Commission's critical assessment of price-based capacity payments.  

However, an important part of respondents indicated that the interim report had not given 
sufficient  weight  to  the  benefits  of  the  strategic  reserve  model.  Respondents  especially 
from Nordic countries argued that the distortive effects of strategic reserves are small if 
such reserves are well-designed. These respondents generally agree with the Commission 
that strategic reserves may not be useful in terms of addressing a missing money problem 
or incentivising new investment. However, they underline that that may not be the main 
goal of the measure, which should rather be seen as an insurance that backs up market 
reforms.  

The Commission agrees that where strategic reserves are dispatched only after the market 
has failed to clear and where a sufficiently high price cap has been reached (and this sum 
is  payable  by  market  participants  that  were  not  in  balance  at  the  scarcity  moment)  the 
strategic reserve should not significantly undermine investment signals. The Commission 
has reflected these observations in an updated Chapter 6 of the Staff Working Document.  

2.4.  Common European Framework for CMs? 

Several  respondents  were  in  favour  of  establishing  a  European  capacity  mechanism 
framework. However, they diverge on the degree of harmonisation needed. A majority of 
the respondent in favour of a common framework believe that rules should be established 
at EU level setting the minimum requirements to be met by capacity mechanisms. These 
include  technology  neutrality,  procurement  through  a  competitive  process  and  the 
participation of cross-border capacities. Those respondents also pointed out that in case a 
common  framework  is  not  established,  the  EU  should  at  least  ensure  that  cross-border 
participation in capacity mechanism is always made possible. Other respondents went so 
far  as  to  propose  that  all  Member  states  should  implement  the  same  type  of  capacity 
mechanism,  while  others  proposed  a  staged  approach  with  the  implementation  of 
regional solutions in a first phase and of EU-wide capacity mechanism once the Single 
Market for energy has been completed.  

In  contrast,  some  market  participants  defended  Member  States'  discretion  to  tailor 
capacity mechanisms to their specific needs although some were more open to move to 
regional and EU-wide solutions in the long run. 

In  the  interim  report,  the  Commission  proposed  a  possible  approach  to  cross-border 
participation in capacity mechanisms. The large majority of respondents were in favour 
of such an approach. As part of the market design initiative, the Commission proposes to 

209 

 
 
require  Member  States  to  implement  cross-border  participation  along  these  lines,  and 
proposed  the  development  of  a  harmonised  capacity  product  for  cross  border  trade. 
National capacity mechanisms and domestic capacity products may still be varied to suit 
the individual circumstances in different Member States.  

2.5.  Bidding zones  

In  relation  to  bidding  zones,  some  respondents  mentioned  problems  caused  by  lack  of 
infrastructure and price zone configuration in large price zone areas. Respondents from 
the  Member  States  that  already  operate  multiple  price  zones  said  the  smaller  zones  in 
their  markets  were  a  good  thing  but  that  even  these  zones  too  often  followed  national 
borders  rather  than  transmission  constraints.  Other  respondents  downplayed  the 
importance  of  bidding  zone  configuration,  arguing  that  bidding  zones  were  only  one 
issue guiding investment choices.  

As part of an expanded discussion of the market reforms needed to ensure markets can 
deliver  to  the  fullest  possible  extent,  the  Commission  has  included  additional 
considerations  on  bidding  zones  in  Chapter  2  of  this  Staff  Working  Document, 
emphasising the dependence of reliable electricity price formation on bidding zones that 
reflect transmission constraints.   

2.6.  Demand response participation  

Roughly a quarter of the respondents to the consultation raised specific remarks related to 
demand  response.  The  most  frequent  message  was  that  demand  response  should  be 
included  in  market-wide  capacity  mechanisms.  Some  respondents  also  pointed  out  that 
the function of demand response in an interruptibility scheme is different from that in a 
market-wide capacity mechanism and more similar to an ancillary service than to a long 
term generation adequacy service. Whether an interruptibility scheme can be regarded as 
a  capacity  mechanism  and  when  ancillary  services  may  be  capacity  mechanisms  are 
assessed in Chapter 3 of this Staff Working Document.  

A  small  number  of  respondents  pointed  out  that  regardless  of  the  question  of  its 
eligibility participation in the capacity mechanism, the participation of demand response 
on the wholesale market should be further enabled and encouraged.  

Most  respondents  were  supportive  of  the  proposed  approach  in  the  interim  report  to 
accept interruptibility schemes specific for demand response given the long term benefits 
of demand response. However, some respondents felt that this could not be justified and 
a level playing field between all technologies should always be maintained. 

2.7.  Cross-border participation 

Many  respondents  were  supportive  of 
to  cross-border 
participation  and  the  proposal  to  harmonise  this  aspect  of  capacity  mechanism  design. 
However, some respondents felt that interconnectors should be paid directly, not receive 
a  'congestion  rent',  some  felt  that  cross  border  capacity  agreements  should  be  firm  (ie. 

the  proposed  approach 

210 

 
 
potentially  overrule  market  coupling),  and  some  respondents  felt  that  participation  in 
more than one CM for the same time period should not be allowed . 

The  Commission  has  considered  all  of  these  arguments,  but  firm  capacity  cross  border 
agreements  are  not  appropriate  as  they  would  undermine  the  signals  for  cross  border 
trade  that  make  the  Single  Market  for  energy  work.  Although  interconnector-only 
participation can reduce complexity, such a model would fail to reward the resources that 
actually provide security of supply on some borders, so would not be appropriate. These 
issues  are  discussed  in  more  detail  in  Chapter  5  and  Annex  2  of  this  Staff  Working 
Document. 

211 

 
 
 
 
ANNEX 4: REFERENCES 

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Journal 14(7), 31-33. 

Besser J. G., Farr J. G. and Tierney S. F. (2002): 'The Political Economy of Long-Term 
Generation Adequacy: Why an ICAP Mechanism is Needed as Part of Standard Market 
Design', Electricity Journal 15(7), 53-62. 

Cervigni  G.  and  Perekhodtsev  D.  (2013):  'Wholesale  electricity  markets';  chapter  2  in 
'The Economics of Electricity Markets: Theory and Practice', edited by Cervigni G. and 
Ranci P., Edward Elgar. 

Cramton P. and Ockenfels A. (2012): ' Economics and design of capacity markets for the 
power sector', Zeitschrift für Energiewirtschaft 36(2), 113-134. 

Cramton  P.,  Ockenfels  A.  and  Stoft  S.  (2013):  'Capacity  Markets  Fundamentals', 
Economics of Energy and Environmental Policy 2(2), 27-46. 

De  Vries  L.  J.  (2007):  'Generation  adequacy:  Helping  the  market  do  its  job',  Utilities 
Policy 15, 20-35. 

European  Commission:  Energy  Economic  Developments  -  Investment  perspectives  in 
electricity markets, Institutional Paper 003, July 2015 

Joskow  P.  L.  (2008):  'Capacity  Payments  in  Imperfect  Electricity  Markets:  Need  and 
Design', Utilities Policy 16, 159-170. 

Joskow P. L. (2013): 'Editorial: Symposium on Capacity Markets', Economics of Energy 
and Environmental Policy 2(2), v-vi. 

Pfeifenberger J., Spees K. and DeLucia M. (2013): 'Evaluation of Market Fundamentals 
and  Challenges  to  Long-Term  System  Adequacy  in  Alberta's  Electricity  Market:  2013 
Update', The Brattle Group. 

Spees K. and Lave L. B. (2007): 'Demand Response and Electricity Market Efficiency', 
The Electricity Journal 20(3), 69-85. 

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