Interactions between electricity market reforms and climate policies : final report
Date: 2017-01-13
Institutions: Directorate-General for Climate Action
Subjects: EU Member State, climate change policy, electrical energy, energy grid, energy policy, energy storage, environmental law, reduction of gas emissions, report

Study on Interactions between 
electricity market reforms and 
climate policies 

Final report 

September 2016 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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Luxembourg: Publications Office of the European Union, 2017 

ISBN 978-92-79-65246-2 
doi:10.2834/28107 

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Reproduction is authorised provided the source is acknowledged. 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interactions between electricity market 
reforms and climate policies 

- FINAL REPORT  

Prepared by 

SQ Consult: Monique Voogt, Mirjam Harmelink and Sergio Ugarte 

Cambridge Econometrics: Phil Summerton and Hector Pollitt 

Element Energy: Joris Besseling 

September 2016 (based on empirical analysis concluded in May 2015) 

Commissioned by: European Commission, Directorate-General for Climate Action 

Directorate C — Climate Strategy, governance and emissions from non-trading sectors 

Unit C.1 — Strategy and Economic Assessment 

Contract number: 07.1207/2013/666010/ETU/CLIMA.A.4 

Responsible officer: Jan Nill 

Registered under project number CC/2013/VMO/0047 

Interactions between electricity market reforms and climate policies 

 1 

 
 
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LEGAL NOTICE 

The information and views set out in this report are those of the authors and do not necessarily reflect the official 

opinion of the Commission. The Commission does not guarantee the accuracy of the data included in this study. 

Neither the Commission nor any person acting on the Commission’s behalf may be held responsible for the use which 

may be made of the information contained therein. 

More information on the European Union is available on the Internet (http://www.europa.eu). 

Contact data 

SQ Consult B.V. 

Monique Voogt 

P.O. Box 8239 

3503 RE Utrecht, the Netherlands 

+31 617500196 (direct) 

m.voogt@SQConsult.com  

Interactions between electricity market reforms and climate policies 

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Table of contents 

Terminology and abbreviations 

1 » 

Executive Summary 

1.1  European policy environment 

1.2  The issues at stake 

1.3  Approach and methodology 

1.4  Analysis and results 

1 »   Synthèse du rapport  

1.1.  Environnement réglementaire européen 

1.2.  Les enjeux 

1.3.  Approche et méthodologie 

1.4.  Analyses et résultats 

2 »  Policy and market context 

2.1  The energy and climate objectives 

2.2  The role of the electricity sector 

2.3  More renewables as challenge for today’s electricity market 

2.3.1 

Increased fluctuation of supply 

2.3.2  Lower revenues for fossil-fuelled producers 

2.4  System adequacy and capacity adequacy 

2.4.1  The various electricity markets 

2.4.2  Ancillary services 
2.4.3  Capacity remuneration mechanisms 

2.5  Flexibility options 

2.5.1  Flexibility options in the organization of electricity markets 

2.5.2  Network flexibility options 

2.5.3  Supply-side flexibility options 

2.5.4  Demand-side flexibility options (demand response) 

2.5.5  Electricity storage 

2.6  Identifying the main research questions 

3 » 

Tomorrow’s electricity market 

Interactions between electricity market reforms and climate policies 

vi 

1 

1 

2 

3 

4 

              8 

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17 

17 

18 

19 

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25 

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 ii 

 
 
 
 
 
 
 
 
3.1  Ending regulated prices? 

3.2  Coupling of electricity market and balancing market 

3.3  International market coupling 

3.4  Introducing balancing markets at local level 

3.5  Expanding market access opportunities 

3.6  Changing conditions to the integration of renewables 

3.7  Which role for (redesigned) capacity markets? 

3.8  A fine balance between supply and demand flexibility options 

4 » 

Interaction between electricity market reforms and EU policy 

objectives 

4.1  Selection of flexibility options 

4.2  Selection of market influencing factors 

4.3  Analysing the influence of each factor and their interactions 

4.4  Direct and indirect interactions 

4.5  The potential impact of network flexibility options 

4.6  The potential impact of supply-side flexibility options 

4.7  The potential impact of demand-side flexibility options 

4.8  The potential impact of electricity storage flexibility options 

4.9  Summary on the impact analysis for the four flexibility options 

5 »  Quantifying the impact of market reforms 

5.1  Profitability assessment 

5.2  Step 1: The wholesale market 

5.2.1  Main model assumptions 

5.2.2  Model results  61 

5.3  Step 2: The value and impact of ancillary services 

5.4  Step 3: The impact of further changes 

6 »  Analysing the UK electricity market 

6.1  Main drivers of the electricity market reform 

6.2  The market reform 

6.3  Capacity mix and the impact of decarbonisation and further renewable growth 

36 

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Illustrating the impact of increased renewable generation on load hours and operating 

6.3.1 
profit  67 

6.3.2 

Impact on plant profitability, excluding RES incentives 

Interactions between electricity market reforms and climate policies 

68 

 iii 

 
 
6.3.3  Analysing future UK market developments 

6.4  Further sensitivity analysis 

6.4.1  Lower amounts of investment and divestment 

6.4.2  Sensitivity to fuel price variations 

6.4.3  Sensitivity to variation in demand 

6.5  Ancillary services 

6.6  Impacts from the market reform 

6.7  Increasing CO2 prices 

6.8  Expanding interconnection capacity 

6.9  Electricity storage and demand response 

6.10  Concluding remarks 

7 »  Analysing the German electricity market 

7.1  The current market situation 

7.1.1  System adequacy on the German market 

7.1.2  Capacity mix and the changes in load hours 

7.2  Sensitivity Analysis 

7.2.1  Sensitivity to fuel price variations 

7.2.2  Sensitivity to demand variation 

7.3  The impact of increasing CO2 prices 

7.4  The impact of an increasing share of renewables 

7.5  Ancillary services and heat sales 

7.5.1  Ancillary services offered on the German market 

7.5.2  Strong cooperation in balancing operation 

7.5.3  Maintaining the strength of the German system 

7.5.4  Revenues from ancillary services 

7.5.5  Revenue from heat sales 

7.6  Reform of the German electricity market 

7.7  Interconnection capacity 

7.7.1  Expanding interconnectivity to the Netherlands 

7.7.2  Expanding interconnectivity to Poland 

7.7.3  New direct interconnection with Norway 

7.7.4  Quantifying the impacts of improved interconnectivity 

7.8  Electricity storage and demand response measures 
7.9  Concluding remarks 

69 

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87 

88 

89 

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90 

91 

92 

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96 

97 

97 

98 

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105 
106 
108 

8 »  Analysing the Polish electricity market reform 

109 

Interactions between electricity market reforms and climate policies 

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8.1  Main drivers for the proposed electricity market reform 

8.2  Quantitative analysis of the current situation 

8.3  The capacity market under discussion 

9 »  Analysing the French electricity market reform 

9.1  Main drivers for the electricity market reform 

9.2  The adopted decentralised capacity market 

10 »  Analysing the Italian electricity market             reform 

10.1  Main drivers for the proposed electricity market reform 

10.2  The proposed capacity market 

11 »  Lessons learned on the main research questions 

12 »  Conclusions and further work 

References 

Annex 1: Qualitative direct impact analysis 

Annex 2: Model inputs 

A2.1  Choice of baseline scenario 

A2.2  Demand and generation profiles 

A2.3  Detailed modelling assumptions: fuel prices and plant data 

A2.4  Detailed modelling assumptions: ancillary services 

Annex 3: Model outputs 

A3.1  Determining the demand and supply curve 

A3.2  Determining wholesale electricity prices and plant profitability 

A3.3  Detailed result tables 

109 

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164 

Interactions between electricity market reforms and climate policies 

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Terminology and abbreviations 

ACER 

Ancillary services 

Agency for the Cooperation of Energy Regulators 

Collection of services which transmission system operators 

(TSOs) can contract so that they can guarantee system 

adequacy  

Balance Responsible Party  

A party that has a contract with the TSO providing financial 

security and identifying balance responsibility with the 

imbalance settlement responsible of the market balance area 

Balancing 

Activities by the TSO after electricity markets have closed 

(gate closure) and in which the TSO acts to ensure that 

demand is equal to supply, in and near real time 

Balancing markets 

Markets on which balancing services are contracted 

Efficient balancing markets  

Markets that ensure the security of supply at the least cost 

CAES  

Compressed Air Energy Storage 

Capacity adequacy 

Ability of the system to ensure that sufficient investments are 

made to ensure that demand and supply can also be balanced 

in the longer term 

Capacity Remuneration Market (CRM) 

Market system in which a payment is given for keeping 

CAPEX 

CCGT  

CfD 

CFP 

CHP 

certain generation capacity available for production in case 

this is needed to be called upon 

Capital expenditures – the capital costs of a power plant 

Combined Cycle Gas Turbine 

Contract for Differences - contracts stipulating that the seller 

will pay to the buyer the difference between the current value 

of an asset and its value at contract time 

Carbon Floor Price (implemented in the UK) 

Combined Heat and Power production 

Clean Dark Spread (CDS) 

Marginal revenue of a kWh of coal-fired production capacity  

Clean Spark Spread (CSS) 

Marginal revenue of a kWh of gas-fired production capacity 

CO2 

Carbon dioxide – the main greenhouse gas 

Day-ahead market 

Electricity market in which buyers and sellers of electricity 

make contractual arrangements for the delivery of electricity 

for the following day 

EBITDA 

Earnings before interest, taxes, depreciation and amortization 

EC 

European Commission 

Energy-only market 

Form of organisation of energy markets in which payments 

– revenues minus costs where costs do not include the costs 

of interest, taxes, depreciation, and amortization 

ENTSO-E 

EPS 

are provided only for the amount of energy contracted (for 

the electricity market this refers to the kWh sold) 

European Network of Transmission System Operators for 

Electricity 

Environmental Performance Standard 

Interactions between electricity market reforms and climate policies 

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EU ETS 

Gate closure 

GHG emissions 

GW 

EU Emissions Trading System 

Moment in which electricity markets (day-ahead market and 

intraday markets) close and that balancing activities start 

Greenhouse gas emissions  

Gigawatt – unit of production capacity 

Intermittent capacity 

Electricity production capacity that is not continuously 

IEM 

Intra-day market 

available due to a factor outside the direct control of the 

operator of the generation capacity (such as solar electricity 

which depends on solar radiation) 

Internal energy market  

Electricity market in which buyers and sellers of electricity 

make contractual arrangements for the delivery of electricity 

in time periods between the closing of the day-ahead market 

and the gate closure (usually one to a few hours before real 

time) 

LRMC 

Long-run marginal cost – the total costs of producing one unit 

Merit Order 

Ranking of electricity supply options available on the market 

of electricity. This is the short-run marginal cost plus the 

investment cost calculated back per unit of electricity 

produced 

MW 

MWh  

OPEX 

PHS 

Prosumers 

in ascending order of their short-run marginal costs of 

production, so that those with the lowest marginal costs are 

the first ones to be brought online to meet demand  

Megawatt – unit of production capacity 

Megawatt hour – unit of electricity production 

Operational expenditures – the costs of operating a power 

plant 

Pumped hydro accumulation storage  

Electricity consumers that also produce part of their electricity 

load locally  

Reserve margin 

Measure of available capacity over and above the capacity 

needed to meet normal peak demand levels 

SRMC 

Short-run marginal cost - The costs of producing one more 

Strike price 

System adequacy 

TSO  

TOU tariffs 

unit of electricity  

Price of the last supply option needed to satisfy demand 

Ability of the power system to meet the aggregate demand of 

all consumers at virtually all times 

Transmission system operator  

Time-of-use tariffs; electricity tariffs that indicate the 

imbalance between electricity supply and demand at that very 

moment 

Wholesale market 

Market for electricity at the high voltage level, including 

generation, transmission and interconnections to 

neighbouring electricity systems 

Interactions between electricity market reforms and climate policies 

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List of Tables 

Table 1 » Potential impact and level of maturity of different flexibility options .................................... 43 
Table 2 » Classification of the market influencing factors analysed .................................................... 44 
Table 3 » Impact analysis of expanding interconnection capacity ...................................................... 48 
Table 4 » Impact analysis of introducing capacity markets ............................................................... 50 
Table 5 » Impact analysis of strengthening demand response .......................................................... 52 
Table 6 » Impact analysis of stimulating investments in electricity storage capacity ............................ 54 
Table 7 » Impact analysis of additional or new flexibility options on the four EU energy and climate policy 
objectives analysed ..................................................................................................................... 56 
Table 8 » New investments and decommissioning by plant type on the UK market .............................. 70 
Table 9 » Impact of fuel price increase on decarbonisation of the UK power sector .............................. 76 
Table 10 » Impact of change in electricity demand on system net reserve margin............................... 77 
Table 11 » Impact of change in electricity demand on the path to achieving the main climate objectives 78 
Table 12 » Impact of CO2 price changes on UK power sector emissions ............................................. 81 
Table 13 » Impacts of an increase in interconnection capacity, based on 2010 baseline ....................... 83 
Table 14 » Impacts of an increase in interconnection capacity, storage capacity or demand response ... 84 
Table 15 » Impact of fuel price increase on emissions related to fuel switching of the German power 
sector........................................................................................................................................ 91 
Table 16 » Impact of change in electricity demand on the path to achieving the main climate objectives 92 
Table 17 » Impact of CO2 prices on the contribution of fuel switching to the decarbonisation of the 
German power sector  ................................................................................................................. 94 
Table 18 » Types of control power on the continental European market, with reserved capacity indications 
for Germany .............................................................................................................................. 97 
Table 19 » Additional net impact of an increase in interconnection capacity...................................... 106 
Table 20 » Impacts of an increase in interconnection capacity, storage capacity or demand response . 107 
Table 21 » Impact analysis of business operation factors on the four main EU energy and climate policy 
objectives ................................................................................................................................ 134 
Table 22 » Impact analysis of business finance factors on the four main EU energy and climate policy 
objectives ................................................................................................................................ 135 
Table 23 » Impact analysis of market demand factors on the four main EU energy and climate policy 
objectives ................................................................................................................................ 136 
Table 24 » Impact analysis of market design factors on the four main EU energy and climate policy 
objectives ................................................................................................................................ 136 
Table 25 » Impact analysis of exogenous market factors on the four main EU energy and climate policy 
objectives ................................................................................................................................ 137 
Table 26 » Impact analysis of EU supporting policies on the four main EU energy and climate policy 
objectives ................................................................................................................................ 139 
Table 27 » Impact analysis of financial market response factors (intermediate factors) on the four main 
EU energy and climate policy objectives ...................................................................................... 140 
Table 28 » Evaluating different options for selection of the baseline scenario .................................... 142 
Table 29 » Scenario input comparison for Germany....................................................................... 143 
Table 30 » Scenario input comparison for the United Kingdom ....................................................... 144 
Table 31 » Model input data per type of plant ............................................................................... 145 
Table 32 » Costs of input (fuel) source (in €/MWh) ....................................................................... 146 

Interactions between electricity market reforms and climate policies 

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Table 33 » Detailed plant input data for the UK, 2010 – part I ........................................................ 147 
Table 34 » Detailed plant input data for the UK, 2010 – part II ....................................................... 148 
Table 35 » Detailed plant input data for the UK, 2020 – part I ........................................................ 149 
Table 36 » Detailed plant input data for the UK, 2020 – part II ....................................................... 150 
Table 37 » Detailed plant input data for the UK, 2030 – part I ........................................................ 151 
Table 38 » Detailed plant input data for the UK, 2030 – part II ....................................................... 152 
Table 39 » Detailed plant input data for Germany, 2010 – part I .................................................... 153 
Table 40 » Detailed plant input data for Germany, 2010 – part II ................................................... 154 
Table 41 » Detailed plant input data for Germany, 2020 – part I .................................................... 155 
Table 42 » Detailed plant input data for Germany, 2020 – part II ................................................... 156 
Table 43 » Detailed plant input data for Germany, 2030 – part I ............ Error! Bookmark not defined. 
Table 44 » Detailed plant input data for Germany, 2030 – part II ........... Error! Bookmark not defined. 
Table 45 » Detailed plant input data for Poland, 2010 – part I ................ Error! Bookmark not defined. 
Table 46 » Detailed plant input data for Poland, 2010 – part II ............... Error! Bookmark not defined. 
Table 47 » Technology specific economic lifetimes per plant type assumed in the model .................... 157 
Table 48 » Estimated ancillary service revenue by technology for the German market ....................... 160 
Table 49 » Main model results for the UK electricity market ........................................................... 164 
Table 50 » Main model sensitivities for the UK electricity market, compared to 2010 scenario baseline 164 
Table 51 » Main model results for the German electricity market .................................................... 165 
Table 52 » Main model sensitivities for the German electricity market ............................................. 165 

Interactions between electricity market reforms and climate policies 

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List of Figures 

Figure 1 » Electricity supply and spot prices in Germany, March 2014. .............................................. 21 
Figure 2 » Actual production per type of plant in Germany, 10-16 March 2014, indicating urgent flexibility 
needs. ....................................................................................................................................... 21 
Figure 3 » Impact of renewable electricity production on the strike price in the wholesale market. ........ 22 
Figure 4 » Evolution of European average wholesale power prices compared with coal and gas prices and 
the share of renewables in power generation. ................................................................................ 23 
Figure 5 » Clean dark spread and clean spark spread in Germany. .................................................... 23 
Figure 6 » Utilization ratio of different German plant types depending on day-ahead spot prices. .......... 24 
Figure 7 » Overview on various models for capacity remuneration mechanisms. ................................. 27 
Figure 8 » Economics and market maturity of various options for electricity storage ............................ 34 
Figure 9 » Graphical representation of system balancing. The proposed flexibility market would include 
each of the system flexibility mechanisms identified ........................................................................ 41 
Figure 10 » Causes tree for the wholesale electricity price as included in the interaction diagram ......... 46 
Figure 11 » Graphical presentation of the purpose-built model for this study ...................................... 60 
Figure 12 » Fixed costs (CAPEX and OPEX) per unit of electricity (€/MWh) ......................................... 67 
Figure 13 » Merit order for the UK scenarios .................................................................................. 67 
Figure 14 » Load hours per type of plant for the UK scenarios .......................................................... 68 
Figure 15 » Profitability of plant types for the UK scenarios .............................................................. 69 
Figure 16 » Profitability of plant types in 2010 (top), 2020 (middle) and 2030 (bottom), excluding capital 
repayments (left) and including capital repayments (right), both excluding RES support schemes ......... 71 
Figure 17 » Plant profitability requirements: typical plant requirements (iso-lines) and typical market 
conditions in different years. ........................................................................................................ 74 
Figure 18 »  Increase in plant profitability as a response of increase in fuel prices (chart on the left) or 
coal prices (chart on the right), for baseline 2010 scenario assumptions. ........................................... 76 
Figure 19 » Impact of change in electricity demand on profitability of various plant types, for baseline 
2010 scenario assumptions .......................................................................................................... 77 
Figure 20 » Impact of ancillary services revenue on the profitability of different plant types (ancillary 
services data: based on 2013 National Grid data) ........................................................................... 79 
Figure 21 » Illustrative impact of 2018 capacity market revenue on the profitability of different plant 
types ........................................................................................................................................ 79 
Figure 22 » Impact of CO2 price increases on profitability of various plant types (2010 baseline) .......... 80 
Figure 23 » Impact of CO2 price increase from 11 €/tCO2 to 34 €/tCO2 on the merit order ................... 81 
Figure 24 » Illustrative impact of changes in UK interconnection capacity on the UK demand curve ....... 82 
Figure 25 » Illustrative impact of change in electricity storage capacity (left) and demand response (right) 
on the UK demand curve ............................................................................................................. 84 
Figure 26 » Change in electricity production first eight months 2014 versus first eleven months 2013. .. 89 
Figure 27 » Merit order for the German electricity market, 2010 scenario, with RES generation equivalent 
to average load factor ................................................................................................................. 90 
Figure 28 » Increase in plant profitability as a result of increase in prices for coal, lignite and gas (chart 
on the left) or for coal and lignite prices (chart on the right) ............................................................ 91 
Figure 29 » Impact of change in electricity demand on profitability of various plant types .................... 92 
Figure 30 » Impact of CO2 price increases on profitability of various plant types ................................. 93 
Figure 31 » Load hours per type of plant on the German market ...................................................... 94 

Interactions between electricity market reforms and climate policies 

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Figure 32 » Profitability of plant types for the German market .......................................................... 94 
Figure 33 » Profitability of plant types in the German market including annualised capital and interest 
repayments, but excluding feed-in-tariffs. ...................................................................................... 96 
Figure 34 » Cumulated Monetary Value of Netted Imbalances in the International Grid Control 
Cooperation (IGCC). ................................................................................................................... 98 
Figure 35 » Impact of ancillary services revenue on the profitability of different plant types, 2010 ...... 100 
Figure 36 » Illustrative impact of 6 GW additional interconnection capacity in the German market on the 
German demand curve .............................................................................................................. 105 
Figure 37 » Illustrative impact of a change in electricity storage capacity (left) and demand response 
measures (right) on the German electricity demand curve ............................................................. 106 
Figure 38 » Merit order for the 2010 Polish power market, excluding intermittent renewable production as 
generated by the model ............................................................................................................. 110 
Figure 39 » Short-run marginal cost curve for the 2010 Polish power market, excluding intermittent 
renewable production as generated by the model ......................................................................... 111 
Figure 40 » Load generation curve for Poland for the year 2010 ..................................................... 112 
Figure 41 » UK balancing cost and breakdown by main services. Source: OFGEM/National Grid .......... 158 
Figure 42 » Ancillary services revenue on the UK market per plant type as assumed in the model ...... 158 
Figure 43 » Ancillary services revenue on the UK market per unit of capacity per year as assumed in the 
model...................................................................................................................................... 159 
Figure 44 » Merit order generated by the model ........................................................................... 161 
Figure 45 » Electricity generation profile generated by the model ................................................... 162 
Figure 46 » Wholesale electricity price curve generated by the model in comparison with actual historic 
price curve ............................................................................................................................... 163 
Figure 47 » Profitability of different plant types as generated by the model ...................................... 163 

Interactions between electricity market reforms and climate policies 

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1 »  Executive Summary 

1.1 

European policy environment  

Europe’s energy and climate policy has achieved some important milestones in the past two years, with 

significant implications for the power sector. These include the following: 

  Continued ambitious goals for greenhouse gas emission reductions, the share of renewable 

energy and for energy efficiency. These goals were defined in the 2030 framework for climate 

and energy policy (“2030 framework”), which was endorsed by the European Council in October 

2014. The framework also includes a plan to take measures to increase the share of electricity 

interconnections between EU Member States, addressing one of the main challenges to 

completion of the internal electricity market that was originally targeted for 2014.  

  Adoption of the new State Aid Guidelines for environmental protection and energy in April 2014, 

with strong implications for (especially) the support of renewable energy, and covering for the 

first time also capacity remuneration mechanisms, by defining reasoning and conditions for 

granting aid for generation adequacy.  

 

Presentation of the Framework Strategy for a Resilient Energy Union with a Forward Looking 

Climate Change Policy (“The Energy Union Strategy”) in February 2015, which put forward a clear 

vision for Europe’s future energy system with an ambitious climate policy at its core. The Energy 

Union Strategy indicated that a fundamental transformation of Europe's energy system is 

required to achieve this vision. In the scope of this Strategy the Commission in July 2015 

launched the stakeholder consultation on redesigning the electricity market to improve market 

functioning.  

 

The structural reform of the EU emissions trading system (“EU ETS”) and the revision of the EU 

ETS for the period after 2020, which will further limit carbon emissions from the power sector and 

industry and which are expected to lead to higher carbon prices. The structural reform addresses 

the surplus of allowances built up since 2009, including postponing of allowance auctioning and 

the introduction of the market stability reserve (MSR) by 2019. This MSR will hold some of the 

system’s reserve allowance and will adjust the supply of allowances to be auctioned to the 

amount of imbalance between supply and demand for allowances on the market. The European 

Parliament and the Council approved the MSR.  The European Commission, as part of the 

implementation of the agreed 2030 framework, put forward a legislative proposal for the revision 

of the EU ETS for the period after 2020 in July 2015. 

Based on the Energy Roadmap 2050, the reduction in power sector GHG emissions compared to 1990 

should be 57-65% in 2030 and 96-99% in 2050. There are several options that could contribute to such 

deep emission reductions. However, it is almost certain that a strong growth in renewable electricity will 

be required to meet the targets. A higher renewable share will have multiple impacts on the required 

organisation of electricity markets; these markets must be adapted to expand the role of distributed 

generation and to include various forms of flexibility, both on the supply and the demand sides. The 

Commission’s public consultation on the redesign of the electricity market highlights these challenges. In 

the meantime Member States are also planning their own market reforms to further facilitate the 

Interactions between electricity market reforms and climate policies 

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corresponding expected growth of renewables and/or to address future problems expected for system 

adequacy or capacity adequacy. 

1.2 

The issues at stake 

In addition to these policy challenges, profound market developments in a period of economic crisis have 

brought about declining margins (or what is sometimes referred to as 'the missing money problem') in 

the power sector: the revenues from many electricity generation assets are not sufficient to recoup fixed 

costs or provide sufficiently high incentives for new investments. Many stakeholders have advocated 

capacity mechanisms as an important building block of the electricity market reforms which are ongoing 

or under discussion also in many Member States. Capacity markets could potentially address this 

profitability problem in the context of increasing need for more flexibility to ensure adequate generation 

at all times. In these discussions it should be noted that the drivers of the proposals for capacity 

mechanisms differ substantially across Europe. While in some countries the issue is to secure 

investments in new production capacity (e.g. in the UK and in Belgium), in other countries the issue is to 

ensure that existing capacity is not closed (e.g. Germany, Italy and Spain). Differences in existing 

capacity mixes, patterns of energy demand, growth of renewable shares and the various levels of other 

flexibility measures available also influence the tone and content of the debate. The other flexibility 

options include electricity storage, demand response, interconnection and further optimisation of 

balancing markets; these could address the same issues. In a clear contribution to this debate the Energy 

Union strategy states that capacity mechanisms should only be developed to address security of supply if 

a regional system adequacy assessment points to such a need, taking into account the potential for 

energy efficiency and demand-side response. 

These developments and positions have raised several questions, which in this study are specifically 

addressed from the perspective of meeting the EU’s climate objectives. Should developments in the 

European electricity market be seen as putting stress on the current design of the market and do they 

require market intervention? How do the proposed capacity remuneration mechanisms address market 

issues and what impact could these proposed mechanisms have on the likelihood of achieving the main 

climate change and energy targets? Will strengthened energy-only markets (including ancillary services), 

supported by the European carbon market, be able to provide sufficient incentives for future investments 

needed to secure electricity supply in the longer term? 

These questions are the starting point of this study commissioned by the European Commission, DG 

Climate Action and for which this is the final report. The report includes in Chapters 2 to 4 an in-depth, 

system-wide analysis of the interactions between existing and planned electricity market reforms and the 

objectives of decarbonisation of the EU power sector and the wider EU climate policy framework. Next, 

the report provides an analysis on the (proposed) power market reforms in the UK, Germany, Poland, 

France and Italy (Chapters 6 to 10). A qualitative analysis is provided for all countries, supported by an 

in-depth quantitative analysis for the UK and Germany. A short description of the quantitative analysis is 

included in Chapter 5, including a description of the purpose-built quantitative tool that was developed for 

this analysis (further details on model assumptions and results are included in Annex 2 and Annex 3). 

Lessons learned are included in Chapter 11, after which final conclusions and further research needs are 

provided in Chapter 12. The study aims to provide further understanding of the impacts of selected 

Interactions between electricity market reforms and climate policies 

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considered reforms, as well as a further understanding of the current European debate on the future 

evolution of electricity market design and its potential impacts on the targeted decarbonisation of the 

electricity sector. 

1.3 

Approach and methodology 

The project methodology combines a qualitative analysis of power markets, power market reforms and 

their interactions with climate policies with a quantitative modelling analysis. In the qualitative analysis 

the report draws upon existing literature, public reports, EC documentation and the team’s own expertise 

on the structure of electricity markets and the debate around electricity market reforms in general, and 

capacity remuneration markets specifically. The report uses the technique of interaction diagrams to 

illustrate the complexity of the interactions between various electricity market influencing factors, market 

reforms and the four power related EU energy and climate objectives that are the central focus of this 

study: system adequacy, capacity adequacy, decarbonisation of the power sector and the share of 

renewable electricity in total generation. A literature review, discussions with various stakeholders and 

our own expertise on specific market reforms are used to analyse the planned and/or ongoing market 

reforms in the UK, Germany, Poland, France and Italy. A short description of the situation in each of the 

five countries is included in this report. 

The quantitative analysis is employed to provide a deeper understanding of the key issues in two of the 

markets - the UK and Germany. The robustness of these key issues is examined under different scenarios 

of exogenous parameters and technical solutions.  

The quantitative results are used to inform the subsequent qualitative assessment of power market 

organisation and to deepen the understanding of the two specific energy market reforms. 

There are several reasons for focusing on the UK and Germany. First, the discussions on energy market 

reforms in both countries are at an advanced level, yet very different. In the UK a capacity market has 

already been established within wider energy market reform, whereas in Germany a series of research 

projects and policy debates led to the publication of the White Paper with a government proposal for 

power market reform. Second, high levels of decarbonisation and the further or continued growth of 

renewables plays a central role in both markets and market reforms. The UK market reforms centre on 

achieving high decarbonisation and bringing about sufficient new capacity, whereas the German market 

reforms centre on improving system and capacity adequacy with continuing growth of renewables. Where 

possible the analysis for the two countries is used to provide a broader understanding at EU level on the 

interaction of electricity market reforms and achieving climate objectives. 

The quantitative analysis is based on a set of scenarios and the use of a purpose-built model which is 

used to simulate developments on a selected power market. The model consists of two modules: a 

dispatch module, based on a static merit order of the electricity market, and a financial analysis module. 

The first step, the dispatch calculation, is based on short-run marginal cost bidding, which is used to 

calculate wholesale electricity prices, the run hours of each plant type offered to the market on an hourly 

basis, the electricity-only revenues of each plant and the periods lacking flexible operating plants. The 

revenues hence do not cover scarcity pricing nor non-wholesale market revenues. In the next step the 

intermediate outputs are used to perform general financial analysis of plant profitability and, 

Interactions between electricity market reforms and climate policies 

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consequently, to determine whether at individual plant and technology levels the revenues from the 

wholesale markets are sufficient to bring about a production mix that meets investors’ economic 

requirements as well as system needs. In this, profitability is calculated on an annual basis, taking into 

account all costs and revenues at plant level in the given year, differentiating between profitability 

excluding recovery of investment costs (for existing plants) and including recovery of investment costs 

(for new plants). As a further step, the modelling results are complemented with analysis of revenues 

from ancillary services per plant type. 

The quantitative analysis focuses on getting an in-depth understanding of how changes in one aspect of 

the electricity market’s structure, or one influencing factor for plant operation on that market, may 

impact on the following market indicators: 

1.  Relative position of plants in the merit order and resulting load factors (i.e. impact on current 

system operations); 

2.  Impact on plant economics, including possible risk of retirement and mothballing decisions for 

generation plants, impacting the generation mix (i.e. impact on utility business); 

3.  Impact on new generation profitability; 

4.  Impact on the decarbonisation of the electricity sector (i.e. impact on policy objectives). 

The analysis focuses particularly on impacts of changes in the market, by comparing baseline results with 

the impact of the market and policy variants that were modelled. The analysis does not aim to give exact 

predictions of market prices nor individual plant level valuations. 

1.4 

Analysis and results 

This report starts with a review of the current electricity market and the needs for future market design. 

It concludes that, in addition to current actions taken by ENTSO-E and ACER to strengthen day-ahead 

markets and intraday markets, various means exist to further strengthen the energy-only markets in a 

way that could further improve both system adequacy and capacity adequacy. The options available 

include the ending of regulated prices, coupling of electricity markets and balancing markets, 

international market coupling, introduction of balancing markets at local level, and expansion of market 

access opportunities, especially for aggregators. It would be beneficial to implement such options before 

designing complementary markets. 

The report furthermore concludes that if complementary markets were required, the basis of these 

markets should not be limited to supply-side capacity only, but should include a combination of various 

flexibility options, including network flexibility options (e.g. expansion of interconnection capacity), 

demand-side flexibility options (e.g. improved demand response) and improved options for electricity 

storage. In other words: the basis of current (proposed) capacity remuneration markets would then need 

to be changed so that they were instead flexibility markets. By listing and mapping the potential direct 

and indirect impacts of such flexibility options the report identifies their potential contributions to system 

and capacity adequacy. The report furthermore analyses qualitatively their impacts on climate related 

policy objectives, in particular the decarbonisation of the electricity sector and the share of renewables on 

the European electricity market. While for the other flexibility mechanisms impacts are generally positive, 

the impact of capacity remuneration mechanisms as a supply-side flexibility option on the 

decarbonisation of the electricity system is ambiguous. A risk could be that capacity markets would lock 

Interactions between electricity market reforms and climate policies 

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in more carbon-intensive production. They may also hamper the dynamic efficiency of longer-term low-

carbon options, both on the demand side and on the supply side of the power market. 

A review of the proposed or ongoing electricity market reforms in the UK, Germany, Poland, France and 

Italy illustrates that each country is faced with a need to address the organisation of its electricity 

market. There are some similar reasons across countries – these include a growing share of renewables, 

decreasing wholesale prices and reduced revenues for fossil-fuelled power plants, and resulting concerns 

on security of supply. However, differences in regulatory frameworks, levels of achieved and targeted 

decarbonisation of the power sector, existing capacity mixes, levels of interconnectivity, operation of 

wholesale and balancing markets, and the quality of national grids result in a large variety of market 

situations, requirements for change and corresponding stakeholder interests. Consequently, in the 

countries assessed there is a large variety in the (proposed) types of capacity remuneration mechanism 

and the specific design choices. The table below provides a brief summary of the five (proposed) systems 

reviewed. 

Country  Status and summary of (proposed) capacity remuneration mechanisms 

UK 

A capacity market was introduced in 2014. The first auction (December 2014) resulted in a clearing price 

of £19.4/kW/yr and a selection of mostly gas-fired and nuclear capacity. Two additional balancing 

reserves were introduced to target demand response, storage and power plants that are deemed 

necessary for reserve power but would otherwise be closed or mothballed (assumed to be mainly gas-

fired capacity). From December 2015 it is expected that interconnectors will be eligible to participate in 

the capacity market auctions. 

Germany  Discussions on the reform of the power market are ongoing, including the choice of whether to implement 

a capacity market. A White Paper issued in July 2015 includes a proposal for a future power market 

consisting of an energy-only market plus a capacity reserve for times when market forces fail to balance 

demand and supply. The White Paper includes a strong emphasis on ensuring flexibility in the market. 

The German government finalised a corresponding draft law in November 2015. 

Poland 

A capacity market is planned to be introduced by 2018-2020. Two options were analysed, modelled along 

the UK and French examples, with a preference expressed for the former. The draft plan presented in 

October 2014 identifies the Polish TSO as the single buyer for flexibility on the Polish market. The system 

is expected to address the expected capacity gap, while Polish power producers expect it to also address 

the declining profitability problem. The system is said to include all flexibility options, but discussions so 

far have mainly concentrated on bringing additional incentives for existing supply-side capacity. 

France 

A capacity mechanism will be introduced by January 2017 to address the fast growth in peak 

demand. The capacity market will include a capacity obligation for all suppliers and will 

include both demand and supply flexibility options. Obligations can be fulfilled by purchasing 

certificates, which can also be traded on a certificate market. 

Italy 

The current capacity payment system is planned to be replaced by a reliability option capacity 

market by 2017. The new system would be a voluntary market in which power producers can 

sell their capacity options to cover the back-up capacity required by the TSO. Payments will 

be based on the difference between the actual price and the strike price on the capacity 

market. Participation is limited to so-called programmable capacities (supply options that can 

be switched on and off). 

Interactions between electricity market reforms and climate policies 

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The expected impacts on decarbonisation depend on national circumstances. The first auctioning results 

from the only currently existing capacity market (the UK) have illustrated the risk of lock in of fossil 

capacity that would slow down the development of low-carbon and flexibility options - both on the 

demand and supply side – that are required to improve capacity adequacy. In the UK only 0.35% of the 

awarded capacity agreements are demand-side responses, 5.5% are storage, 1.4% are hydro-power 

capacity and 16% are nuclear capacity. The remaining share of capacity (76.8%) is biomass and fossil-

fuelled production capacity. 

Modelling results for the UK and Germany confirm that in current wholesale markets many operators are 

faced with profitability problem: the revenues from their sales on those markets are not sufficient to 

recoup their operating costs or to provide sufficient incentive for new investments. On the basis of these 

results a potential risk is identified that existing plants that guarantee supply could be decommissioned or 

mothballed and that insufficiently high incentives exist for investments in new production capacity. This 

especially concerns the mid-merit, flexible gas plants that play a crucial role in system balancing. The 

issue clearly illustrates the concerns expressed to ensure system adequacy and capacity adequacy and 

the need for changes in the organisation of electricity markets. In the German market the risks mainly 

occur in the short term: a temporary unbalance between supply and demand is expected and the market 

must adapt to the strong growth in renewable electricity supply. In the UK the risks are more related to 

the fact that current electricity-only markets are insufficient to trigger investments that would be needed 

to meet future mid- to long-term demand, especially when larger amounts of intermittent supply are 

expected, combined with the need to either refurbish or decommission ageing and less efficient plants to 

comply with the Large Combustion Plant Directive and the Industrial Emissions Directive. The model 

results for the UK show that gas-fired plants are especially facing the profitability problem. 

Further calculations show that ancillary services are an important source of income, in addition to sales 

on the wholesale markets based on the merit order only, especially for the mid-merit plants. 

Strengthened energy-only markets would be able to trigger sufficient investments, but this would require 

various improvements in the functioning of wholesale markets and balancing markets, as well as higher 

market prices or more frequent peak prices. While ancillary services and balancing markets are a 

significant source of revenue and bring most existing plants close to being profitable, the model results 

show that they are still insufficient to make new investments on the UK and German markets profitable. 

A further increasing share of renewable electricity production could worsen this situation: the load hours 

of coal and – especially – gas-fired plants are further decreased and the wholesale price lowers. Under 

current market conditions the (temporary) shut down of many gas-fired plants would in the short term 

mainly result in an increase of load hours of existing coal plants. Whereas total carbon emissions from 

the power sector and industry are capped by the EU ETS, this could negatively impact on the dynamic 

efficiency of gas-fired power production, low-carbon emission production opportunities and demand-side 

efficiency improvements. Higher carbon prices and improving opportunities for other flexibility options 

could mitigate this effect. 

Higher fuel prices and the resulting increase in electricity prices leads to a large increase in the 

profitability of renewable generation and nuclear, since the revenues from these plants increase but they 

Interactions between electricity market reforms and climate policies 

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do not incur cost increases. Plant profitability increases are higher in case of gas price increases than in 

the case of coal price increases. The differences are explained by the merit order effects. 

Increases in interconnection capacity, demand response or electricity storage can significantly reduce the 

average daily peak and therefore reduce the average short-run marginal cost price, as well as the 

amount of load hours of conventional plants. This can support decarbonisation of the power sector and as 

such is an important element for the longer-term supporting framework. The impact on plant profitability 

depends on country market conditions, as illustrated by the different modelling results for the UK and 

Germany for interconnections, and on the impact on capacity needs. 

The debate centres on whether market interventions are needed to ensure sufficient system adequacy as 

well as sufficient capacity adequacy. Economic theory tells us that the times of scarcity lead to higher 

prices and/or more frequent occurrences of price spikes. Such a situation will result in additional 

revenues for power plant operators and could provide suffiicient incentives to support both system 

adequacy and capacity adequacy. This is not modelled in the analysis. An important question to this, as 

also pointed out in the German White Paper, is whether the stakeholders on the electricity market are 

willing to accept such higher prices and more frequent price spikes. The alternative option most discussed 

is the introduction of capacity markets. In the UK such a market has recently been established, with a 

first auction held in December 2014. The modelling results confirm that the clearing price £19.4/kW/year 

(€27/kW/year) provides an additional incentive that is just sufficient to keep some of the peaking 

capacity in the market under current market conditions and can trigger some new investments in gas-

fired capacity. The model illustrates that, at such price levels, investing in new coal power plants is not 

profitable. 

Another important policy measure that may significantly support both system adequacy and capacity 

adequacy is a strengthened carbon market, with higher carbon prices. A reform of the carbon market is 

ongoing, which is expected to increase carbon prices to levels that are significantly beyond current price 

levels. This expectation is illustrated by recent carbon price developments as a result of announced 

reform and revision of the EU ETS. Higher CO2 prices can have a significant impact on Europe’s electricity 

markets, impacting rates of decarbonisation as well as the dispatch and profitability of individual plants 

and the system as a whole. First, higher CO2 prices result in an increase in wholesale electricity prices, 

which may result in higher revenues, especially for low-carbon technologies. Second, at sufficiently high 

CO2 price levels the merit order can be impacted, as plants with higher carbon exposure may be pushed 

out of the merit order. This may have a significant impact on the decarbonisation of the sector. Modelling 

results show that such a merit order impact could already start to occur at a CO2 price of €22/tCO2, both 

for the UK and the German market. A further increase to €34/tCO2 on the UK market results in a clear 

switch in the position of coal plants and efficient CCGTs in the merit order. The average load hours of coal 

plants drops from 67% to 58%, resulting in a significant reduction in profitability. Consequently the load 

hours of gas plants strongly improves from 58 to 71%, resulting in increased profitability. As a result of 

higher wholesale prices the profitability of other plants (including renewable generation and nuclear 

electricity) also increases strongly. Similar results are obtained for the German market. 

In the study the full extent of additional flexibility services or scarcity pricing was not included in the 

scope of analysis and also the modelling tool applied, which is based on exogenous capacity assumptions, 

has limits with regard to the reflection of complex interactions. Consequently firm conclusions could not 

Interactions between electricity market reforms and climate policies 

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be drawn on this. Further model elaboration and corresponding analysis is recommended, in particular to 

understand the full opportunities of improved system balancing, and the interactions of increased 

flexibility options with decarbonisation policies. 

1.  Synthèse du rapport 

1.1.  Environnement réglementaire européen 

La réglementation énergétique et climatique européenne a franchi d’importantes étapes ces deux 

dernières années, avec des conséquences significatives pour le secteur de l’électricité. Celles-ci incluent 

les éléments suivants: 

  Des objectifs ambitieux et continus pour la réduction des émissions de gaz à effet de serre, la part 

d’énergie renouvelable et l’efficacité énergétique. Ces objectifs ont été définis dans le cadre pour le 

climat et l’énergie à l’horizon 2030 (« cadre 2030 »), approuvé par le Conseil européen en octobre 

2014. Ce cadre inclut également un programme de mesures visant à augmenter le nombre 

d’interconnexions électriques entre Etats Membres de l’UE, répondant ainsi à l’un des défis majeurs 

de la finalisation du marché électrique interne, initialement prévu pour 2014. 

 

L’adoption des lignes directrices concernant les aides d’État à la protection de l’environnement et à 

l’énergie en avril 2014, avec un impact important notamment pour le soutien aux énergies 

renouvelables. Ces lignes directrices incluent pour la première fois également des mécanismes de 

rémunération de capacité, en définissant la logique et les conditions pour l’obtention d’une aide 

pour l’adéquation des capacités. 

 

Présentation du Cadre stratégique pour une Union de l'énergie résiliente, dotée d'une politique 

clairvoyante en matière de changement climatique (« La stratégie d’Union de l’Energie ») en 

février 2015, qui a mis en avant une vision claire du système énergétique européen de demain, 

avec en son cœur une politique climatique ambitieuse. La stratégie d’Union de l’Energie a montré 

qu’une transformation fondamentale du système énergétique européen est nécessaire pour 

atteindre cette vision. Dans le cadre de cette stratégie, la Commission a lancé en juillet 2015 la 

consultation des parties prenantes sur la refonte du marché de l’électricité pour améliorer son 

fonctionnement. 

 

La réforme structurelle du système communautaire d'échange de quotas d'émissions (« SCEQE ») 

et la révision du SCEQE pour la période après 2020, qui limitera plus encore les émissions de 

carbone pour le secteur de l’électricité et l’industrie, et devrait conduire à des prix du carbone plus 

élevés. La réforme structurelle répond au surplus de quotas accumulés depuis 2009, et inclut le 

report de la mise aux enchères des quotas et le lancement de la réserve de stabilité du marché 

(RSM) d’ici 2019. Cette RSM contiendra une partie des quotas de la réserve du système et ajustera 

la quantité de quotas mis aux enchères sur base du déséquilibre de l’offre et de la demande de 

quotas sur le marché. La Parlement européen et le Conseil ont approuvé la RSM. Dans le cadre de 

Interactions between electricity market reforms and climate policies 

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la mise en œuvre du cadre 2030 convenu, la Commission européenne a mis en avant en juillet 

2015 une proposition législative pour la révision du SCEQE pour la période après 2020. 

D’après la feuille de route 2050 sur les énergies, la réduction en émissions de gaz à effet de serre du 

secteur de l’électricité devrait être de l’ordre de 57-65% en 2030 et 96-99% en 2050, comparé à 1990. 

Différentes options pourraient contribuer à atteindre ces réductions d’émission considérables. Il est 

toutefois presque certain qu’un fort développement des énergies renouvelables sera nécessaire pour 

atteindre ces objectifs. Une plus large part de renouvelables aura de multiples impacts sur la nécessaire 

organisation des marchés de l’électricité ; ces marchés doivent être adaptés pour élargir le rôle de la 

production décentralisée et pour inclure différentes formes de flexibilité, à la fois du côté de l’offre et de 

la demande. La consultation publique de la Commission sur la refonte du marché de l’électricité met 

l’accent sur ces défis. Entre-temps, les Etats Membres planifient également leurs propres réformes de 

marché pour davantage faciliter la croissance prévue des énergies renouvelables et/ou pour faire face 

aux futurs problèmes escomptés concernant l’adéquation du système ou l’adéquation des capacités. 

1.2.  Les enjeux 

En plus de ces défis réglementaires, de profonds changements du marché dans une période de crise 

économique ont entraîné une réduction des marges (ce qui est parfois appelé le « problème de manque à 

gagner » (missing money problem) dans le secteur de l’électricité: pour de nombreuses installations de 

production, les recettes sont insuffisantes pour couvrir les coûts fixes ou pour représenter une incitation 

suffisante pour de nouveaux investissements. De nombreuses parties prenantes ont préconisé les 

mécanismes de capacité comme composante essentielle des réformes du marché de l’électricité en cours 

ou en discussion également dans de nombreux Etats Membres. Les marchés de capacité pourraient 

potentiellement répondre à ce souci de rentabilité dans un contexte de besoin croissant de davantage de 

flexibilité pour assurer en permanence une production suffisante. Il est à noter que dans ces discussions, 

les motivations derrière les propositions pour des mécanismes de capacité varient considérablement à 

travers l’Europe. Alors que dans certains pays il s’agit de sécuriser les investissements dans de nouvelles 

capacités de production (par exemple au Royaume-Uni et en Belgique), dans d’autres l’objectif est de 

s’assurer que les capacités en place ne sont pas supprimées (par exemple en Allemagne, en Italie et en 

Espagne). Les différences de mix énergétique en place, les modèles de demande énergétique, la 

croissance des parts des énergies renouvelables et les différents niveaux d’autres mesures de flexibilité 

disponibles influencent également le ton et le contenu du débat. Les autres options de flexibilité incluent 

le stockage de l’électricité, les réponses à la demande, l’interconnexion et l’optimisation poussée des 

marchés d’ajustement ; ces options pourraient aider à faire face à ces mêmes problèmes. Contribuant 

clairement à ce débat, la stratégie d’Union de l’Energie indique que les mécanismes de capacité ne 

devraient être développés pour assurer la sécurité de l’approvisionnement que si un système régional 

d’évaluation de l’adéquation identifie ce type de besoin, prenant en compte le potentiel d’efficacité 

énergétique et la réponse du côté de la demande. 

Ces développements et ces positions ont suscité plusieurs questions, traitées spécifiquement dans cette 

étude sous l’angle de l’atteinte des objectifs climatiques de l’UE. Les développements dans le marché 

européen de l’électricité devraient-ils être considérés comme contraignants pour la conception en cours 

du marché et nécessitent-ils une intervention dans le marché ? Comment les solutions de mécanismes de 

rémunération de capacité peuvent-elles répondre aux problématiques du marché et quel impact les 

Interactions between electricity market reforms and climate policies 

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mécanismes proposés pourraient-ils avoir sur la probabilité d’atteindre les principaux objectifs 

énergétiques et climatiques? Les marchés energy-only renforcés (incluant les services auxiliaires), 

soutenus par le marché européen du carbone pourront-ils fournir les incitations nécessaires pour des 

investissements qui sécuriseraient la fourniture d’électricité à long terme? 

Ces questions sont le point de départ de cette étude commanditée par la Commission européenne, DG 

Action pour le climat et dont ceci est le rapport final. Le rapport comprend dans les chapitres 2 à 4 une 

analyse détaillée, à l’échelle du système, des interactions entre les réformes de marchés de l’électricité 

prévues ou en place, et les objectifs de décarbonisation du secteur électrique de l’UE et le cadre plus 

large de la politique climatique de l’UE. Ensuite, le rapport fournit une analyse des réformes de marchés 

de l’électricité (prévues) au Royaume-Uni, en Allemagne, en Pologne, en France et en Italie (chapitres 6 

à 10). Une analyse qualitative est proposée pour tous les pays, appuyée par une analyse quantitative 

poussée pour le Royaume-Uni et l’Allemagne. Une courte description de chaque analyse est incluse dans 

le chapitre 5, comprenant une description de l’outil quantitatif spécialement conçu pour cette analyse (de 

plus amples informations sur les hypothèses du modèle et sur les résultats sont fournies en annexe 2 et 

en annexe 3). Les enseignements à tirer des résultats sont regroupés dans le chapitre 11 ; les 

conclusions finales et les besoins complémentaires en termes de recherche se trouvent dans le chapitre 

12. L’étude cherche à apporter une meilleure compréhension des impacts d’une sélection de réformes 

envisagées, ainsi qu’une compréhension plus détaillée du débat européen en cours sur l’évolution future 

de la conception du marché de l’électricité et ses possibles impacts sur la décarbonisation ciblée du 

secteur de l’électricité. 

1.3.  Approche et méthodologie 

La méthodologie utilisée dans ce projet combine une analyse qualitative des marchés de l’électricité, ainsi 

que des réformes de marché de l’électricité et leurs interactions avec les politiques climatiques, avec une 

analyse quantitative basée sur une modélisation. Dans l’analyse qualitative, le rapport se base sur la 

littérature existante, les rapports publics, la documentation de la CE et l’expertise propre à l’équipe sur la 

structure des marchés de l’électricité et le débat autour des réformes de marché de l’électricité en 

général, et des marchés de rémunération de capacité en particulier. Le rapport utilise la technique des 

diagrammes d’interaction pour illustrer la complexité des interactions entre les différents facteurs 

influençant le marché de l’électricité, les réformes de marché et les quatre objectifs énergie et climat de 

l’UE liés à l’électricité, qui sont le point central de cette étude: adéquation du système, adéquation des 

capacités, décarbonisation du secteur de l’électricité, et part de l’électricité renouvelable dans la 

production totale. Une analyse documentaire, des discussions avec différentes parties prenantes et notre 

propre expertise sur des réformes de marché spécifiques sont utilisés pour analyser les réformes de 

marchés prévues ou en cours au Royaume-Uni, en Allemagne, en Pologne, en France et en Italie.  

L’analyse quantitative est utilisée pour permettre une meilleure compréhension des enjeux clés de deux 

des marchés – le Royaume-Uni et l’Allemagne. La robustesse de ces enjeux clés est examinée selon 

différents scénarios de paramètres exogènes et de solutions techniques. Les résultats quantitatifs sont 

utilisés pour renseigner l’évaluation qualitative de l’organisation des marchés de l’électricité et pour 

approfondir la compréhension des deux réformes de marché de l’électricité en question. 

Il y a plusieurs raisons pour lesquels se pencher en particulier sur le Royaume-Uni et l’Allemagne. D’une 

part, les discussions sur les réformes de marché de l’électricité sont particulièrement avancées dans ces 

deux pays, mais néanmoins très différentes. Au Royaume-Uni, un marché de capacité a déjà été mis en 

Interactions between electricity market reforms and climate policies 

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place dans le cadre d’une réforme plus large du marché de l’énergie, alors qu’en Allemagne une série de 

projets de recherche et de débats sur les politiques publiques ont mené à la publication du Livre Blanc 

avec une proposition gouvernementale pour la réforme du marché de l’électricité. D’autre part, des taux 

élevés de décarbonisation et la croissance continue ou prolongée des renouvelables jouent un rôle central 

dans les deux marchés et réformes de marché. Les réformes du marché du Royaume-Uni se concentrent 

sur l’atteinte d’une décarbonisation importante et le développement de suffisamment de nouvelles 

capacités, tandis que les réformes du marché allemand s’orientent vers l’amélioration de l’adéquation du 

système et des capacités avec la croissance continue des renouvelables. L’analyse de ces deux pays est 

utilisée, dans la mesure du possible, pour fournir une compréhension plus large au niveau de l’UE de 

l’interaction entre les réformes de marché de l’électricité et l’atteinte des objectifs climatiques. 

L’analyse quantitative est basée sur une série de scénarios et l’utilisation d’un modèle spécialement 

conçu à cette fin, utilisé pour simuler les développements sur un marché de l’électricité présélectionné. Le 

modèle comprend deux modules: un module d’acheminement (dispatch), basé sur un merit order 

(préséance économique des moyens de production) statique du marché de l’électricité, et un module 

d’analyse financière. La première étape, le calcul de l’acheminement, est basée sur l’offre de coût 

marginal à court terme, utilisée pour calculer les prix de gros de l’électricité, le nombre d’heures de 

fonctionnement de chaque type d’installation proposée sur le marché sur une base horaire, les recettes 

spécifiquement liées à la vente d’électricité de chaque installation et les périodes pendant lesquelles les 

installations de production disponibles permettent trop peu de flexibilité. Les recettes ne couvrent alors ni 

le prix de la rareté, ni les recettes autres que celles du marché de gros. Dans l’étape suivante, les 

résultats intermédiaires sont utilisés pour réaliser l’analyse financière générale de la rentabilité de 

l’installation et, par conséquent, pour déterminer si les recettes des marchés de gros sont suffisantes, au 

niveau des installations et technologies individuelles, pour induire un mix énergétique répondant aussi 

bien aux exigences économiques des investisseurs qu’aux besoins du système. Pour ce faire, la 

rentabilité est calculée sur une base annuelle, prenant en compte tous les coûts et les recettes au niveau 

de l’installation pour l’année donnée, et distinguant la rentabilité qui exclut le recouvrement des coûts 

d’investissement (pour les installations existantes), de celle qui inclut le recouvrement de ces coûts (pour 

les nouvelles installations). Pour aller plus loin, les résultats de modélisation sont complétés par l’analyse 

des recettes issues des services auxiliaires en fonction du type d’installation. 

L’analyse quantitative se concentre sur une compréhension détaillée de comment des changements dans 

l’un des aspects de la structure du marché de l’électricité, ou l’un des facteurs pouvant influencer 

l’exploitation des installations sur ce marché, peuvent impacter les indicateurs de marché suivants : 

1.  Position relative des installations dans le merit order et coefficients de charge qui en découlent 

(c’est-à-dire l’impact sur les systèmes d’opération en place); 

2.  Impact sur l’économie des installations, comprenant le possible risque de retrait ou de mise sous 

cocon des installations en place (c’est-à-dire l’impact sur le marché des utilities); 

3.  Impact sur la rentabilité des nouvelles installations de production; 

4.  Impact sur la décarbonisation du secteur de l’électricité (c’est-à-dire l’impact sur les objectifs 

réglementaires). 

L’analyse se concentre en particulier sur les impacts de changements sur le marché, en comparant les 

résultats de référence avec l’impact des variables de marché et de réglementation qui ont été modélisés. 

L’analyse n’a pas pour objectif de fournir des prédictions précises de prix de marché, ni des évaluations 

d’installations spécifiques. 

Interactions between electricity market reforms and climate policies 

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1.4.  Analyses et résultats 

Ce rapport démarre par une analyse du marché de l’électricité en place et des besoins pour la future 

conception de marchés. Il conclut, qu’en plus des actions en cours par ENTSO-E et ACER pour renforcer 

les marchés day-ahead et intraday, divers moyens existent pour renforcer davantage les marchés 

energy-only de façon à améliorer à la fois l’adéquation du système et l’adéquation des capacités. Les 

options possibles incluent la fin des prix régulés, le couplage des marchés de l’électricité et des marchés 

d’équilibrage, le couplage des marchés au niveau international, la mise en place de marchés d’équilibrage 

au niveau régional, et l’expansion des possibilités d’accès au marché, en particulier pour les agrégateurs. 

Il serait utile de mettre en œuvre ce type d’options avant de définir des marchés alternatifs. 

Le rapport conclut par ailleurs que si des marchés alternatifs étaient nécessaires, la base de ces marchés 

ne devrait pas se limiter uniquement aux capacités de production, mais devrait également inclure une 

combinaison de diverses options de flexibilité, dont des options de flexibilité de réseau (par exemple 

l’expansion de la capacité d’interconnexion), des options de flexibilité du côté de la demande (par 

exemple la réponse à la demande améliorée) et des options améliorées pour le stockage de l’électricité. 

En d’autres termes : la base des marchés de rémunération de capacité actuels (proposés) devrait être 

modifiée pour les transformer en marchés de flexibilité. En listant et en cartographiant les possibles 

impacts directs et indirects de ce type d’options de flexibilité, le rapport identifie leur possible 

contribution à l’adéquation du système et des capacités. Le rapport analyse par ailleurs de manière 

qualitative leurs impacts sur les objectifs réglementaires liés au climat, en particulier la décarbonisation 

du secteur de l’électricité et la part des renouvelables sur le marché européen de l’électricité. Alors que 

pour les autres mécanismes de flexibilité, les impacts sont en général positifs, l’impact des mécanismes 

de rémunération de capacité en tant qu’option de flexibilité du côté des capacités de production sur la 

décarbonisation du système électrique est ambigu. L’un des risques est de voir les marchés de capacité 

induire l’utilisation de davantage de production à forte teneur en carbone. Ils pourraient aussi freiner 

l’efficacité dynamique des options à faible teneur en carbone à plus long terme, à la fois du côté de l’offre 

et de la demande du marché de l’électricité. 

Une analyse des réformes de marché électrique proposées ou en cours au Royaume-Uni, en Allemagne, 

en Pologne, en France et en Italie monte que chaque pays fait face au besoin de repenser l’organisation 

du marché électrique en place. Certaines raisons sont communes à plusieurs pays – notamment une 

croissance de la part des renouvelables, la diminution des prix de gros et la baisse des recettes des 

centrales électriques à combustibles fossiles, et les inquiétudes qui en découlent à propos de la sécurité 

d’approvisionnement. Toutefois, des cadres réglementaires différents, les niveaux atteints et visés en 

termes de décarbonisation du secteur de l’électricité, les mix énergétiques en place, les niveaux 

d’interconnectivité, le fonctionnement des marchés de gros et des marchés d’équilibrage, et la qualité des 

réseaux nationaux conduisent à une grande variété de situations de marché, de besoins de changement, 

et donc d’intérêts des parties prenantes. Par conséquent, il y a une grande variété de mécanismes de 

rémunération de capacité (proposés) et de choix de conception dans les pays étudiés. Le tableau ci-après 

résume succinctement les cinq (propositions de) systèmes analysés.  

Interactions between electricity market reforms and climate policies 

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Pays 

Statut et résumé des mécanismes de rémunération de capacité (proposés) 

Royaume-Uni 

Un marché de capacité a été lancé en 2014. La première mise aux enchères (décembre 

2014) a mené à un prix d’équilibre de 19.4 £/kW/an et une sélection de centrales de 

production essentiellement au gaz naturel ou au nucléaire. Deux réserves d’équilibrage 

ont été mises en place pour cibler la réponse à la demande, le stockage et les 

installations de production estimées nécessaires comme puissance de réserve mais qui 

seraient autrement fermées ou mises sous cocon (a priori essentiellement des centrales à 

gaz). A partir de décembre 2015, les gestionnaires d’interconnexions devraient être 

éligibles à la participation aux enchères du marché de capacité. 

Allemagne 

Des discussions sont en cours sur la réforme du marché de l’électricité, comprenant le 

choix de mettre en place ou non un marché de capacité. Un Livre Blanc publié en juillet 

2015 inclus une proposition de marché de l’électricité consistant en un marché energy-

only et une réserve de capacité en prévision des périodes où les forces de marché ne 

parviendront pas à équilibrer l’offre et la demande. Le Livre Blanc met nettement l’accent 

sur la nécessité d’assurer une flexibilité du marché. Le gouvernement allemand a finalisé 

en consequence un projet de loi en novembre 2015. 

Pologne 

La mise en place d’un marché de capacité est prévue pour 2018-2020. Deux options ont 

été analysées, modélisées sur base des exemples anglais et français, avec une 

préférence pour le premier. Le projet de plan présenté en octobre 2014 identifie le GRT 

polonais comme seul acheteur de flexibilité sur le marché polonais. Le système devrait 

faire face au déficit de capacité escompté, tandis que les producteurs d’électricité 

polonais s’attendent à ce qu’il réponde également au problème de baisse de rentabilité. Il 

est prévu que le système inclue toutes les options de flexibilité, mais jusqu’ici les 

discussions se sont surtout penchées sur l’apport d’incitations supplémentaires pour les 

capacités en place du côté de l’offre. 

France 

Un mécanisme de capacité sera mis en place d’ici janvier 2017 pour faire face à la forte 

croissance de la consommation de pointe. Le marché de capacité inclura une obligation 

de capacité pour tous les fournisseurs et comprendra des options de flexibilité à la fois du 

côté de la demande et de l’offre. Les acteurs pourront répondre à leurs obligations en 

achetant des certificats, qui pourront également être échangés sur un marché de 

certificats. 

Italie 

Le système actuel de paiement de capacité devrait être remplacé par un marché de 

capacité avec options de fiabilité d’ici 2017. Le nouveau système serait un marché 

volontaire dans lequel les producteurs d’électricité pourraient vendre leurs options de 

capacité pour couvrir les capacités de secours exigées par le GRT. Les paiements seront 

basés sur la différence entre le prix réel et le prix d’exercice sur le marché de capacité. 

La participation est limitée à ce que l’on appelle les capacités programmables (solutions 

d’approvisionnement qui peuvent être mises en marche et arrêtées). 

Les impacts attendus sur la décarbonisation dépendent des circonstances nationales. Les premiers 

résultats de mise aux enchères du seul marché de capacité actuellement en place (le Royaume-Uni) ont 

montré le risque d’induire l’utilisation de davantage de capacité de production fossile, ce qui ralentirait le 

développement des options à faible teneur en carbone et des options de flexibilité – à la fois du côté de la 

demande et de l’offre – nécessaires pour améliorer l’adéquation des capacités. Au Royaume-Uni, seuls 

Interactions between electricity market reforms and climate policies 

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0,35% des accords de capacité distribués correspondent à des mesures du côté de la demande, 5,5% 

concernent le stockage, 1,4% les capacités de production hydrauliques et 16% les capacités de 

production nucléaire. La part de capacité de production restante (76.8%) correspond à des installations 

de production utilisant de la biomasse ou des énergies fossiles. 

Les résultats de modélisation pour le Royaume-Uni et l’Allemagne confirment que dans le marché de gros 

actuel de nombreux opérateurs font face au problème de rentabilité : les recettes de leurs ventes sur ces 

marchés sont insuffisantes pour couvrir leurs coûts opératoires ou pour représenter une incitation 

suffisante pour de nouveaux investissements. Sur base de ces résultats, le possible risque que les 

installations en place garantissant une fourniture d’énergie suffisante soient désaffectées ou mises sous 

cocon, et qu’il y ait trop peu d’incitation pour investir dans de nouvelles capacités de production, a été 

identifié. Ceci concerne en particulier les centrales à gaz flexibles, qui représentent des solutions 

médianes dans le merit order, et jouent un rôle crucial dans l’équilibrage du réseau. Le problème illustre 

clairement les inquiétudes exprimées à propos de l’adéquation du système et de l’adéquation des 

capacités, et le besoin de changements dans l’organisation des marchés de l’électricité. Dans le marché 

allemand, les risques existent surtout à court terme: un déséquilibre ponctuel entre l’offre et la demande 

est attendu et le marché doit s’adapter à la croissance importante de la fourniture d’électricité d’origine 

renouvelable. Au Royaume-Uni, les risques sont davantage liés au fait que les marchés électriques 

energy-only actuels sont insuffisants pour inciter aux investissements nécessaires pour répondre à la 

demande prévue à moyen/long terme, surtout lorsque de plus importantes quantités 

d’approvisionnement intermittent sont attendues, ce qui s’ajoute au besoin de soit rénover soit mettre 

sous cocon les installations de production vieillissantes et moins efficaces, afin de respecter la Directive 

sur les grandes installations de combustion et la Directive sur les émissions industrielles. Les résultats du 

modèle pour le Royaume-Uni montrent que les centrales à gaz sont particulièrement vulnérables au 

problème de rentabilité. 

Des calculs supplémentaires montrent que les services auxiliaires représentent une source importante de 

revenus, en plus des ventes sur les marchés de gros basées uniquement sur le merit order, surtout pour 

les centrales à rendement moyen. Des marchés energy-only renforcés pourraient engendrer des 

investissements suffisants, mais cela nécessiterait diverses améliorations dans le fonctionnement des 

marchés de gros et des marchés d’équilibrage, de même que des prix de marché plus élevés ou des prix 

de période de pointe plus fréquents. Alors que les services auxiliaires et les marchés d’équilibrage sont 

une source significative de revenus et permettent à la plupart des centrales en place d’être presque 

rentables, les résultats de modélisation montrent qu’ils restent insuffisants pour une rentabilité de 

nouveaux projets d’investissement au Royaume-Uni et en Allemagne. 

Une augmentation supplémentaire de la part de production d’électricité à partir d’énergie renouvelable 

pourrait aggraver cette situation: les taux d’utilisation des centrales à charbon et – en particulier – des 

centrales au gaz naturel seraient encore réduits et le prix de gros baissé. Dans les conditions actuelles du 

marché, la fermeture (provisoire) de nombreuses centrales à gaz entraînerait surtout à court terme une 

augmentation du taux d’utilisation des centrales à charbon. Alors que l’ensemble des émissions de 

carbone du secteur de l’électricité et de l’industrie sont plafonnées par le SCEQE, cela pourrait avoir un 

impact négatif sur l’efficacité dynamique des centrales à gaz, les opportunités de production à faible 

teneur en carbone, et l’amélioration de l’efficacité du côté de la demande. Des prix du carbone plus 

Interactions between electricity market reforms and climate policies 

 14 

 
 
 
 
 
élevés et l’amélioration des opportunités permettant d’autres options de flexibilité pourraient atténuer cet 

effet. 

La hausse des prix du combustible et l’augmentation des prix de l’électricité qui en résulte entraînent un 

large accroissement de la rentabilité de la production d’énergie à partir de renouvelables et de nucléaire, 

étant donné que les recettes de ces centrales augmentent sans coût supplémentaire. L’accroissement de 

la rentabilité des installations est supérieur dans le cas d’une hausse des prix du gaz naturel par rapport 

à une hausse des prix du charbon. Ces différences s’expliquent par les effets du merit order. 

L’augmentation de la capacité d’interconnexion, de réponse à la demande, ou de stockage d’électricité 

peut réduire de manière significative la pointe moyenne de consommation journalière et de ce fait réduire 

le coût marginal moyen à court terme, de même que le taux d’utilisation des centrales traditionnelles. 

Ceci peut venir en aide à la décarbonisation du secteur de l’électricité et est de ce fait un élément 

important du système de soutien à long terme. L’impact sur la rentabilité des installations dépend des 

conditions de marché au niveau national, comme l’illustrent les résultats de modélisation différents pour 

le Royaume-Uni et l’Allemagne pour les interconnexions, et de l’impact des besoins en capacité. 

Le débat se concentre sur la nécessité ou non d’interventions de marché pour s’assurer une suffisante 

adéquation du système et des capacités. La théorie économique nous dit que les périodes de pénurie 

mènent à des prix plus élevés et/ou des pics de prix plus fréquents. Une telle situation aura comme 

conséquence des recettes supplémentaires pour les opérateurs de centrales électriques et pourrait fournir 

les bonnes incitations à soutenir à la fois l’adéquation du système et l’adéquation des capacités. Ceci 

n’est pas modélisé dans l’analyse. Une question importante à ce sujet, comme le montre aussi le Livre 

Blanc allemand, est de savoir si les parties prenantes du marché de l’électricité sont prêtes à accepter de 

telles hausses de prix et des pics de prix plus fréquents. L’alternative la plus souvent évoquée est la mise 

en place de marchés de capacité. Au Royaume-Uni, un marché de ce type a récemment été créé, avec 

une première mise aux enchères qui s’est tenue en décembre 2014. Les résultats de modélisation 

confirment que le prix d’équilibre de £19.4/kW/an (€27/kW/an) fournit une incitation supplémentaire qui 

suffit tout juste à conserver une partie de la capacité de pointe sur le marché dans les conditions 

actuelles du marché, et qui peut déclencher quelques nouveaux investissements dans des centrales à 

gaz. Le modèle montre qu’à ces niveaux de prix, investir dans de nouvelles installations au charbon n’est 

pas rentable. 

Une autre mesure politique importante qui peut contribuer de façon significative à la fois à l’adéquation 

du système et à l’adéquation des capacités est un marché du carbone renforcé, avec des prix du carbone 

plus élevés. Une réforme du marché carbone est en cours, qui devrait permettre d’augmenter les prix du 

carbone pour qu’ils atteignent des niveaux bien au-delà des prix actuels. Les évolutions récentes des prix 

du carbone suite à l’annonce de la réforme et de la révision de l’EU-ETS illustrent bien cette prévision. 

Des prix plus élevés du CO2 peuvent considérablement impacter les marchés de l’électricité européens, 

avec des répercussions sur les taux de décarbonisation tout comme sur la répartition et la rentabilité 

d’installations individuelles et du système dans son ensemble. Dans un premier temps, des prix plus 

élevés du CO2 entrainent une augmentation des prix de gros de l’électricité, ce qui peut engendrer une 

hausse des revenus, surtout pour les technologies à faible teneur en carbone. Ensuite, lorsque les prix du 

CO2 sont suffisamment élevés, cela peut influencer le merit order dans la mesure où des installations 

fortement émettrices en CO2 peuvent se retrouver exclues du merit order. Ceci peut fortement influencer 

Interactions between electricity market reforms and climate policies 

 15 

 
 
 
 
 
la décarbonisation du secteur. Les résultats de modélisation montrent qu’un tel impact sur le merit order 

pourrait commencer à se produire dès un niveau du prix du CO2 à €22/tCO2, à la fois sur les marchés 

anglais et allemand. Une hausse supplémentaire jusqu’à un niveau de €34/tCO2 sur le marché 

britannique mène à un échange sans ambiguïté entre les positions dans le merit order des centrales à 

charbon et des turbines à gaz à cycle combiné efficaces. La moyenne des taux d’utilisation des centrales 

à charbon baisse de 67% à 58%, provoquant une baisse significative de la rentabilité. Par conséquent, le 

taux d’utilisation des installations à gaz est fortement amélioré, passant de 58% à 71%, et entraînant 

une hausse de rentabilité. Suite à la hausse des prix de gros, la rentabilité d’autres installations (dont la 

production à partir de renouvelables et l’électricité nucléaire) augmente également de façon significative. 

Des résultats similaires sont obtenus pour le marché allemand. 

L’impact des services de flexibilité supplémentaires ou du prix de la rareté n’a pas été pris en compte 

dans sa totalité dans le cadre des analyses réalisées dans cette étude, et l’outil de modélisation utilisé, 

basé sur des hypothèses de capacité exogènes, ne reflète pas l’ensemble des interactions complexes. 

C’est pourquoi aucune conclusion définitive n’a pu en être tirée. Il est recommandé de poursuivre cette 

analyse sur base de modèles plus affinés, notamment pour exploiter au mieux l’équilibrage amélioré du 

réseau, et les interactions entre les options de flexibilité accrues et les politiques de décarbonisation. 

Interactions between electricity market reforms and climate policies 

 16 

 
 
 
 
 
 
 
 
2 » Policy and market context 

Chapter 2 discusses the policy and market context to the developments in the European electricity sector. 

Following a description of the energy and climate objectives (Section 2.1), and the role of the electricity 

sector in achieving these objectives (Section 2.2) we discuss the challenges identified in the electricity 

market (Section 2.3). In Section 2.4 we introduce the terminology of system adequacy and capacity 

adequacy and address various means how these are addressed in the current market. Whereas 

introduction and/or strengthening of capacity remuneration systems is the main option currently 

discussed to address these we conclude that other flexibility options are available and needed. This is 

discussed in Section 2.5. Section 2.6 identifies the main research questions that were identified for this 

study. 

2.1 

The energy and climate objectives 

Europe’s current energy and climate policy framework focuses on reducing greenhouse gas (GHG) 

emissions, increasing the share of renewable energy in the energy mix and improving energy efficiency. 

To this end, EU leaders in 2007set the well-known "20-20-20" targets to be achieved by the year 2020:  

  A 20% reduction in EU GHG emissions from 1990 levels; 

  A 20% share of EU energy consumption produced from renewable sources;  

  A 20% improvement in the EU's energy efficiency. 

These targets were later enacted through the climate and energy package adopted in 2009 and additional 

energy efficiency legislation, notably the Energy Efficiency Directive adopted in 2012. 

Building on the lessons learned so far, the European Commission presented in January 2014 the 2030 

policy framework for climate and energy. The 2030 framework was agreed by the European Council in 

October 2014, and was integrated in the framework strategy for a resilient Energy Union with a forward 

looking climate change policy ("Energy Union strategy") presented by the European Commission in 

February 2015. The key targets include: 

  A reduction of EU domestic GHG emissions by at least 40% below the 1990 level by 2030. This 

target is defined to keep the EU on the cost-effective track towards an 80% reduction by 2050. 

Sub-targets set to achieve this 40% reduction are:  

o  A reduction of 43% in emissions from the sectors covered by the EU Emissions Trading 

System (EU ETS) by 2030, compared to 2005 emission levels;  

o  A reduction of 30% of emissions from sectors outside the EU ETS by 2030, compared to 

2005 emission levels;  

  An increase in the share of renewable energy to at least 27% by 2030; 

  An indicative target of at least 27% improvement in energy efficiency by 2030. 

Interactions between electricity market reforms and climate policies 

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2.2 

The role of the electricity sector 

Back in December 2011 the EC had indicated the importance of the decarbonisation of the power sector 

in achieving the EU’s long-term GHG reduction targets. In the Energy Roadmap 2050 the following 

indicative shares of GHG emission reductions from the power sector, depending on the specific scenario, 

were given: 

  57-65% in 2030; 

  96-99% in 2050. 

The main EU climate policy instrument to achieve these objectives is the EU ETS. The EU ETS sets a cap 

on carbon emissions from the electricity sector and the energy-intensive industries, and by establishing a 

market for EU allowances it has resulted in a carbon price. If the carbon price is sufficiently high, the 

power sector will have a strong incentive to move away from carbon-intensive power production and will 

most likely invest in low-carbon electricity production technologies such as nuclear energy, fossil-fuelled 

power with CCS and renewable energy. The current prices of carbon on the European market, however, 

are relatively low and have little impact neither on the sector’s investment decisions nor on the sector’s 

operational decisions. The low prices are mainly caused by an oversupply of allowances on the market.  

The current design of the EU ETS includes some elements that will reduce the oversupply of allowances 

on the market, such as decreasing the cap for fixed installations each year. The European Union has 

furthermore decided on a reform of the EU ETS. Two elements of this reform have been decided upon: 

the ‘backloading’ of 900 million allowances (i.e. postponing the moment to auction these allowances) and 

the introduction of the market stability reserve (MSR) by January 2019. This MSR will adjust the amount 

of allowances to be auctioned to the amount of imbalance between supply and demand for allowances on 

the market. As a result of these actions market analysts expect the EU ETS prices to increase to 

approximately €20/t by 2020 (PointCarbon Thomson Reuters, 2014). In July 2015 the European 

Commission presented a proposal for a further revision of the EU ETS after 2020 and launched a 

consultation on this proposal. The proposal includes a further reduction of the cap after 2020 in line with 

the EU 2030 targets. 

In addition to a GHG emission reduction target, a separate EU-level binding target was set to increase the 

share of renewable energy to at least 27% by 2030. The overall target setting gives more flexibility to 

Member States on the preferred ways to reach this target, in accordance with their specific 

circumstances, energy mixes and capacities to produce electricity from renewable sources. It is, however, 

beyond any doubt that the electricity sector will play a large role in achieving this target. To achieve the 

overall renewable energy target, it is expected that the share of renewable energy in the electricity sector 

would increase from 21% today to at least 45% in 2030. 

The targets for decarbonisation of the electricity sector and increasing the share of renewables in 

electricity production are included in the four energy and climate policy objectives that are analysed in 

this study. Although primarily aimed at combating climate change these targets also aim to increase 

energy security in the EU, to strengthen the competitiveness of its energy sector and to keep energy 

affordable for European citizens. These drivers are not always naturally aligned and the challenges of 

defining appropriate rules for the market systems and governing regulation are widely recognised. 

Interactions between electricity market reforms and climate policies 

 18 

 
 
 
 
 
 
 
In July 2009, the third legislative package for the internal energy market was adopted. This legislation 

set the framework within which the European internal energy market needs to develop. The European 

Heads of State agreed that the internal energy market should be realised by 2014. One of the main 

elements of the third package was the establishment of ENTSO-E and ACER, the single European bodies 

for the coordination of European Transmission System Operators (TSOs) and European regulators. These 

bodies aim to further strengthen the single European electricity market by formulating framework 

guidelines and network codes aimed at providing harmonized rules for cross-border exchanges of 

electricity. They also prepare (ENTSO-E) and oversee (ACER) the bi-annual ten-year network 

development plan which includes a European generation adequacy outlook. 

To date the internal market for electricity has not been completed in Europe. The European Council 

conclusions and later the Energy Union strategy included various measures to support the further 

completion, including urgent measures to increase the share of electricity interconnections to at least 
10% in 2020 and set the objective to increase this share to 15% by 2030.1 In July 2014 the European 

Commission had already adopted new rules on public support for environmental protection and energy to 

support achieving the objectives. In addition to rules on providing support to renewable energy sources 

these guidelines also include new provisions on aid to energy infrastructure and generation capacity to 

strengthen the internal energy market and ensure security of energy supply. 

The Energy Union strategy took the debate on the reform of energy markets some steps further than the 

2009 package. It indicates that a fundamental transformation of Europe's energy system is required. It 

also points out the need for flexible markets on both the supply and demand sides, in order to integrate 

renewable electricity generation. To this end a need was indicated to expand the possibilities for 

distributed generation and demand-side management, for example by increasing the use of intraday 

markets, and by developing new high-voltage long distance connections and new storage technologies. 

For the aim of this study to analyse the interactions between electricity market reforms and climate 

policies, four specific energy and climate policy objectives are considered: 

1.  Developing power systems that meet the aggregate demand of all consumers at all times with 

sufficient quality (system adequacy, see Section 2.4); 

2.  Ensuring that sufficient energy infrastructure investments are made such that demand and supply 

of power systems are balanced in the longer term (capacity adequacy, see Section 2.4); 

3.  Decarbonisation of the European power sector to support the EU’s ambitions to become a 

competitive low carbon economy by 2050; 

4.  To continue growing the share of renewable energy sources in the production of electricity. 

2.3 

More renewables as challenge for today’s electricity market 

The transition of centrally organized fossil-based electricity supply systems towards a system with an 

increased share of intermittent renewable energy sources and a larger share of decentralised production 

is expected to continue. The transition will play a significant role in the realisation of the low-carbon 

economy and will have a significant impact on the way the product electricity is viewed by society. In the 

1 The interconnection targets are defined to ensure that the share of interconnection of each EU Member State reaches a level equivalent to or 
beyond a certain percentage of their installed production capacity. 

Interactions between electricity market reforms and climate policies 

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next decades this may have strong impacts on the revenues and opportunities for various market 

players.  

In short the concerns relating to a higher share of renewable electricity are: 2 

  A high share of renewables has resulted in lower wholesale prices, as a result of the low variable 

costs of renewables. This has negatively impacted on the revenues of power generation; 

 

The steep growth of renewable generation, in combination with lower demand than expected, has 

resulted unexpectedly in much lower supply opportunities for fossil-fuelled generation capacity. 

This is impacting the profitability of fossil-fuelled plants, especially the latest investments; 

  Higher volatility in wholesale market prices, as a result of increased variability due to a larger 

share of intermittent renewables. This has increased uncertainty for operators; 

 

The uncertainty in the hourly feed-in from renewable electricity generation capacity can vary 

considerably, depending on local weather conditions; 

  Consequently the residual load (electricity demand minus renewable electricity generation) can 

be highly volatile; 

  Higher volatility in residual load will require operation of fossil-fuelled electricity at partial-load or 

with fast ramping up or down. This is technically less efficient, more costly and leads to higher 

NOx emissions; 

 

The higher system volatility increases the challenges for system balancing: more flexibility needs 

to be included to balance the rapid changes in renewable generation; 

  High system volatility may also impact the optimal capacity mix as some production capacities 

are technically restricted in their ability to change generation levels; 

  Additional balancing requirements will impact the final consumer prices for electricity. 

These concerns are explained in the sections below. 

2.3.1  Increased fluctuation of supply 

Strong support policies have resulted in a rapidly increasing share of renewable electricity generation in 

European power markets, reaching approximately 27% by the end of 2014 (EC, 2015). The growing 

share of renewable electricity is an important pillar in the targeted decarbonisation of the European 

electricity sector, and in fighting climate change more generally. The hourly feed-in of electricity from 

wind and solar systems can, however, be highly uncertain as it depends on the local weather conditions 

at that time. Electricity market systems in the past were not designed with such a large share of 

renewables in mind; they have instead been designed and operated with a very high level of certainty 

and smaller amounts of fluctuating power supply that could be easily absorbed. 

Now that fluctuating power supplies in some regions have reached larger market shares the first system 

challenges have been experienced. This is, for example, illustrated by Figure 1, where on a windy Sunday 

in March 2014 the German electricity system had difficulties to cope with the large amount of wind power 

in times of low demand. In this period German electricity market prices dropped to negative, even below 

Note 1 »  This report does not aim to provide a full analysis on the impact of renewables on European power markets. With respect to the role of renewables 

on the European power market the analysis focuses on the impact of the growing share of renewables on system adequacy, capacity adequacy and 

the decarbonisation of the power sector. Hence other (potential) benefits and drawbacks of an increasing share of renewables are not addressed 

and therefore this report does not provide a full analysis on the value of a growing share of renewables in Europe. 

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-/- €50/MWh. Similar events happened in February, April, May and August 2014. Concerns have been 

expressed that with continued growth of renewable electricity supply these problems will worsen. 

Figure 1 » Electricity supply and spot prices in Germany, March 2014.  

Source: Mayer (2014) 

In the specific situation in Germany in March 2014 the large fluctuations in renewable electricity supply 

required urgent flexibility in the electricity system. Within a time span of a few hours, a large part of the 

fossil capacity had to be ramped down or shut down entirely (see Figure 2). With increasing amounts of 

renewable production capacity across Europe these situations could occur more often in the future. In 

very general terms: the larger the share of intermittent renewable electricity capacity on the market, the 

higher the potential imbalance on the market and therefore the higher need for flexibility.  

Figure 2 » Actual production per type of plant in Germany, 10-16 March 2014, indicating urgent flexibility needs.  

Source: Burger, B., Fraunhofer ISI (2014) 

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2.3.2  Lower revenues for fossil-fuelled producers 

The aim of the European target model is that power markets are for the main part organised according to 
the ‘energy-only’ market model.3 In this market model supply options are ranked according to their 

marginal costs (the ‘merit order’) and the last option needed to meet demand determines the market 

price (the ‘strike price’). The producer’s revenue is based on the amount of kilowatt hours sold on the 

market and the strike price. The strike price in theory will rise to higher levels during peak hours and the 

additional revenues generated during these hours should be sufficient to pay back investment costs. 

Consequently the market price will automatically trigger new investments and therewith ensure long-

term security of electricity supply. In recent years, however, both the prices and the amount of kilowatt 

hours sold have faced downward pressure. 

 

Lower market prices: the high share of renewables is pushing down system prices, as is 

illustrated in Figure 3;  

 

Lower amount sold: a high amount of renewable production is decreasing the residual load 

(electricity demand minus renewable electricity generation). Consequently fossil-fuelled electricity 

generators sell much fewer hours on the market. 

The economic crisis has further worsened the situation as electricity demand has decreased, or has not 

grown as expected, whereas investment plans were based on the assumption of a steady increasing 

demand. This problem is often described as ‘the missing money problem’. 

Figure 3 » Impact of renewable electricity production on the strike price in the wholesale market.  

Source: Agora (illustration of the German electricity market with a fictive power supply curve) 

The missing money problem and (temporary) closure of capacity especially concerns gas-fired production 

capacity. The operational profits from these plants has continuously been negative in the last 3 years. 

This has been mainly due to low coal prices, the overcapacity on the European electricity market and 

carbon prices that were too low to induce a switch from coal- to gas-fired electricity production. As a 

result gas-fired producers have been making continuous losses. The decrease in coal prices is pictured in 

Figure 4 on the following page, along with the development in gas prices, wholesale electricity prices and 

the share of renewable electricity. Figure 5 shows the marginal net revenue of a kWh of coal-fired 

3 Note that on some markets prices for (mainly) smaller consumers are still (partially) regulated and that long-term contracts between suppliers 
and consumers also may influence the functioning of the energy market. 

Interactions between electricity market reforms and climate policies 

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production capacity (black line) compared to that of a gas-fired production capacity (blue line). The 

marginal net revenues take into account all production costs, including the costs of the EU carbon price.  

Figure 4 » Evolution of European average wholesale power prices compared with coal and gas prices and the share of 

renewables in power generation.  

Source: EC (2015). Data sources for figure: Platts, BAFA, ENSTO-E. Platts PEP: Pan European Power Index (in 

€/MWh); Coal CIF ARA: Principal coal import price benchmark in North Western Europe (in €/Mt). DE border imp. 

stands for long term contract based import natural gas price on the German border (in €/MWh). RES (renewables) 

includes hydro, wind, solar and biomass; RES share in the total power generation estimation for the EU-28 as a whole 
(right hand scale). 

Figure 5 » Clean dark spread and clean spark spread in Germany. 

Source: RWE Supply & Trading. Prices until 2 May 2015  

Interactions between electricity market reforms and climate policies 

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Figure 6  provides an illustration of the missing money problem in practice, showing that in 2014 most of 

the gas-fired capacity on the German market was used at less than one third capacity.  

The EU ETS was expected to be an important instrument in influencing the merit order. By putting a price 

on carbon emissions, coal-fired electricity production – which has approximately double the amount of 

carbon emissions per kWh compared to gas-fired generation – would become much more expensive and, 

at sufficiently high EU ETS market prices, would be automatically pushed out of the merit order by gas-

fired electricity production. EU ETS prices, however, have in recent years not been sufficiently high to 

close the price gap between a kWh of coal-fired electricity and a kWh of gas-fired electricity. Following 

the continued loss-making situation for gas-fired capacity producers have responded by mothballing or 

closing plants, as well as putting new investment plans on hold. Cedigaz reports that 28 of Europe’s 

current gas power plants are currently under review by major European utilities, covering a total of 50 

GW of capacity (Bloomberg, 2014).  

In addition, an ageing generation infrastructure and enhanced European legislation and regulatory 

compliance is expected to result in further reduction in fossil-fuelled generation capacity. This especially 

concerns closures of older, less efficient coal plants as a result of implementation of the Large 

Combustion Plant Directive and the Industrial Emissions Directive. Some of these older coal plants 

expected to be closed can also provide flexibility on the market. The expected decreasing net reserve 

margins is causing concern for both system balancing and the longer-term security of electricity supply, 

especially when seen in combination with expected continued growth in intermittent generation capacity 

and its resulting need for higher flexibility on the market. 

Figure 6 » Utilization ratio of different German plant types depending on day-ahead spot prices.  

Source: Mayer (2014) 

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2.4 

System adequacy and capacity adequacy 

In the previous sections we have described how the rapidly increasing share of renewable electricity 

production has resulted in a downward pressure on wholesale market prices and has increased flexibility 

needs to balance the system. At the same time the strong reduction of residual load causes lower 

revenues for fossil-fired capacity, with gas-fired capacity being especially disadvantaged in a market with 

negative spark spreads. Consequently a large amount of gas-fired production capacity has been 

(temporarily) closed down. It is, however, this gas-fired capacity that has in the past been the backbone 

of system balancing, as these plants typically can be quickly ramped up or down, or quickly started up. 

Stakeholders consequently have expressed increasing concerns about whether the current market 

structure is able to provide sufficient incentives to secure both system adequacy and capacity adequacy. 

Some stakeholders have responded by proposing several types of market interventions and market 

reforms, which are elaborated in the sections below. 

System adequacy and capacity adequacy 

The terminology of system adequacy and capacity adequacy are crucial concepts in this report. They 

define the strength of the power system in, respectively, the short term and the longer term. The 

definitions used are: 

  System adequacy: the ability of the power system to meet the aggregate demand of all 

consumers at virtually all times.  

  Capacity adequacy: the long-term ability of the power system to match demand and supply for 

electricity. In other words, the ability of the system to ensure that sufficient investments are 

made such that demand and supply can also be balanced in the longer term. 

2.4.1  The various electricity markets 

In classical energy-only markets all potential electricity suppliers bid their potential supply 24 hours in 

advance. A central power exchange collects all bids, aggregates them into one power supply curve, 

compares them to the 24 hour consumption profile and clears this day-ahead market. More recently the 

intraday market has been added to this system. In the intraday market electricity can be traded during 

the day of operation after the day-ahead market is closed. In this way bids that were offered on the day-

ahead market can be somewhat adjusted to respond to variations in actual supply and demand. Intraday 

markets typically operate until one hour before real time, the so-called moment of gate closure. 

After gate closure the system operator will use additional services to resolve remaining imbalances. 

These services are offered at balancing markets. Roughly speaking two clusters of services are contracted 

by the system operators. First, contracted reserve and response operating services are contracted with 

balance responsible parties at capacity or reserve markets. Second, short-term balancing operations are 

contracted as ancillary services. On ancillary services markets, participants are paid to keep balancing 

capacity or demand available. When called for services they should immediately deliver the required 

increase or lowering of production or demand. 

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2.4.2  Ancillary services 

Ancillary services are services operated by the TSO to control the electricity system and maintain 

dispatch at all times, including at periods of rapid load changes. Each TSO ensures that ancillary services 

for maintaining the security of the network are always available and working properly. Various ancillary 

services are distinguished, including: 

 

Frequency control - Continuous modulation of power to maintain the system at frequency levels 

within given margins. Frequency control is essential after unpredictable events such as large load 

outage or the loss of a generating unit;  

  Voltage control – Maintaining the system at the required voltage level by means of reactive 

power via synchronous or static compensation; 

  Spinning reserve – Increase or decrease in generation or reduction in consumption that can be 

provided at short notice. In practice this is provided by generating units operating in partial load 

and by interruptible consumers; 

  Standing reserve – Increase or decrease in generation or reduction in consumption other than 

spinning reserve; 

  Voltage support services - This concerns the ability to produce or absorb reactive power and the 

ability to maintain a specific voltage level under both steady-state and post-contingency 

operating conditions subject to the limitations of the resource's stated reactive capability; 

  Black start capability - The capability of a generating unit to restart the energy system from a 

shutdown condition (also called system black out) to an operating condition, and start delivering 

power without assistance from a power system. 

  Grid loss compensation – Compensation of transmission losses between the generators and the 

loads (the consumers); 

 

Emergency control actions – Maintenance and use of special equipment such as power system 

stabilisers to maintain a secure transmission system; 

  Remote automatic generation control – Regulating the frequency of the grid by an automated 

control system. 

The increasing use of renewables and the market liberalization is altering the needs for ancillary services. 

In addition the increase of cross-border trade has resulted in making grid integration, cross-border 

balancing and even traders a top priority in the organisation of the electricity market. TSOs are now 

facing a mounting pressure to develop balancing systems that will include in the future demand response, 

energy storage and interconnectors to be able to respond to all new challenges. 

Frequency control issues became critical when electricity markets were deregulated and frequency control 

became an ancillary service with a decisive commercial focus. This commercial focus has spawned a lot of 

work on frequency control markets and economics but not much research has been devoted to dynamic 

simulation of large interconnected systems. Frequency control in large interconnected systems can be 

economically optimized if primary control and secondary control can be provided at lower costs. In the 

European synchronous systems, this consists essentially on minimising the amount of reserve used for 

primary and secondary control. 

Technological development, including Smart Grid development, is continuing in step with further 

developments for future ancillary services. Smart Grid technological development will presumably change 

Interactions between electricity market reforms and climate policies 

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the supplier portfolio and the requirement for ancillary services. How these elements could help to 

operate the system in the short term is not yet clear, however. A further uncertainty factor is how the 

development work to do with the integrated planning of the individual production and consumption 

technologies will be put into practice. There may be differences in the degree of central control that will 

be implemented in the planning. A player could, for example, combine his various minor resources to act 

as a large aggregate unit. At present, efforts are continuously being made to involve alternative suppliers 

of ancillary services, e.g. wind turbines and consumption units. 

Flexible production capacity is an important ancillary service provider. The market for ancillary services 

can therefore be an important source of revenue for such providers. Gas-fired production plants in 

particular have benefited from their flexibility and usually provide a substantial part of ancillary services. 

Flexible peaking plants typically make a large part of their net revenues from ancillary services and only a 

small part from sales on energy markets. Further details are provided in Section 2.5.3, discussing supply-

side flexibility options. 

2.4.3  Capacity remuneration mechanisms 
In Europe the need for system adequacy and capacity adequacy is not contested, but large differences of 

opinion exist about the means of how to improve this in countries where this is needed. A large part of 

the debate concentrates on the need for so-called capacity remuneration mechanisms (hereafter called 

CRMs) to strengthen investment incentives for those capacities that are considered crucial to provide 

system adequacy or capacity adequacy in markets where the existing markets are thought to provide 

insufficient support to trigger such investments. CRMs can be divided into volume-based and price-based 

mechanisms. Typically five types of CRMs are distinguished, as is illustrated in Figure 7.  

Figure 7 » Overview on various models for capacity remuneration mechanisms. 

Source: Acer, 2013 

CRMs are to a large extent tailored to the specific market situation in each country; therefore they may 

combine elements from the five different types of mechanisms. Experience with use of CRMs with cross-

border participation is limited. 

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The important characteristics to classify implemented CRMs are4: 

  Whether mechanisms are market wide (remunerating all capacity needed to meet demand) or 

targeted (remunerating the additional capacity needed beyond what is expected to be delivered). 

This could also include differentiation between different kinds of capacity, and demand side 

participation. 

  Whether obligations refer to the present or the future, or both. 

  How the level of (adequate) capacity is determined. 

  How availability is documented or certified. 

  How the capacity payment is determined: whether prices are set administratively, according to 

auctions or in the market. 

  How the costs are allocated: Whether the capacity obligation is imposed on the TSO (centralised) 

or on load serving entities (decentralised). 

 

The rules for operation and activation of the capacity, including participation in energy markets. 

In short the five types of CRMs can be defined and classified as: 

Volume-based capacity remuneration 

1.  Strategic reserve It establishes contracts for targeted long-term reserve capacity to ensure 

access to so-called strategic reserves. These contracts are usually procured through a tendering 

procedure. Generation capacity in the strategic reserve is held as back-up, ready to generate 

when called upon, and is not bid into the market. The strategic reserve is generally activated only 

if the (day-ahead) market is not able to cover demand. The strategic reserve may consist of 

existing or new generation built for the purpose of reserve capacity, and may include demand 

resources. The strategic reserve is implemented by imposing an obligation on the TSO. This type 

of mechanism is (among others) used in Finland and Sweden; 

2.  Capacity obligation. A decentralised mechanism in which an obligation is imposed on large 

consumers and on large suppliers to contract a certain level of capacity linked to their future 

consumption or supply respectively. In times of shortages contracted parties are required to 

make the contracted capacity available to the market. Compliance with capacity obligations can 

be achieved in three ways: by handing in capacity certificates bought from capacity providers, by 

keeping large generation capacity available or by closing long-term contracts with generators. 

Non-availability is usually penalized. Capacity obligation schemes may apply to present or future 

load volumes. Contracting for capacity may be done on a “spot” basis or in a forward market 

style, depending on whether current or future load needs to be served. A capacity obligation has 

been adopted in France, including the market for capacity certificates. Greece also has a capacity 

obligation; 

3.  Capacity auction. Another form of market-wide capacity remuneration mechanism which relies 

on capacity certificates. Capacity auctions, however, do not enforce capacity obligations on load-

serving entities. Instead, the TSO procures the required capacity on behalf of the total load to be 

served on a capacity auction. Generators receive standard payment contracts for capacity 

Note 2 »  4 Classification taken from (Tennbakk, 2013) 

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availability via certificates. In principle, interruptible loads may also participate in the auction. 

Capacity auctions make it easier to standardise conditions and set one common price in the 

capacity contracts. This facilitates transparency, as capacity prices can be disclosed to market 

participants in a much easier way than in the case of capacity obligation. Contrary to capacity 

obligations, capacity auctions do need in-depth assessments of reliability and other estimates and 

forecasts of peak demand and reserve margins. Capacity auctions have been adopted in the UK 

and planned in Spain;   

4.  Reliability option. The reliability option is a financial instrument in which capacity contracts 

offered to generators have the form of a one-way call option. This call option refers to a strike 

price, usually with reference to the system marginal price of the wholesale market. Capacity 

providers anticipate the potential revenues in hours in which the market price in the wholesale 

market is above the strike price, in exchange for the option revenues. Consumers, on the other 

hand, pay the option premium and in return avoid prices above the strike price. The reliability 

option in other words is an auction system in which a financial instrument is used to cap the 

electricity purchase price in peak periods. Generators must be available when called in situations 

when the spot price exceeds the strike price, or pay the difference between the two prices. 

Reliability options require a well-functioning wholesale market and a market-wide system price. 

This mechanism is so far not used but was proposed in Italy. 

Price-based capacity remuneration 

5.  Capacity payment. Capacity payment. Capacity payments are the simplest type of capacity 

mechanisms. A fixed capacity payment is provided in addition to a generator’s revenue from the 

regular energy-only market. Capacity payments aim to provide incentives for new capacity and 

for maintaining existing capacity. The capacity payment is usually defined and controlled by a 

regulatory body. The electricity generated from units receiving capacity payments is sold in the 

wholesale market or through bilateral contracts. The rules of capacity payments can differentiate 

between specific types of generators or plant types to be rewarded, for example between base-

load and peak capacity, existing and new capacity, etc. In most cases, capacity payments are 

only provided for existing capacity, but they could also be applied to new capacity. Capacity 

payments are often combined with price caps in the wholesale markets in order to avoid extreme 

price spikes. Capacity payments are used in Ireland, Italy, Spain and Romania. 

CRMs can have a significant impact on the organisation of the electricity market and the revenues of 

individual plants. Moreover, they may impact the achievement of climate objectives by favouring high 

carbon electricity generation. In this study we have analysed the proposed or existing CRMs in five 

selected countries: The UK, Germany, Poland, France and Italy. A short description is available in 

Chapters 6-10.  

2.5 

Flexibility options 

Current discussions on improving both system adequacy and capacity adequacy focus on the debate 

about whether capacity remuneration systems should be introduced or strengthened and, if so, how this 

Interactions between electricity market reforms and climate policies 

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should be done. It should, however, be noted that various other options are available on the market to 

improve the system capacity while at the same time ensuring security of electricity supply and increasing 

the share of renewables. These options can be seen either as alternative options or complementary to 

proposed capacity oriented market reforms. In this section we discuss these flexibility options according 

to the following classification: 

 

Flexibility options in the organization of electricity markets 

  Network system flexibility options 

  Supply-side flexibility options 

  Demand-side flexibility options 

 

Electricity storage flexibility options 

2.5.1  Flexibility options in the organization of electricity markets 

A central element in achieving improved flexibility is the organization of electricity markets. In Europe 

markets are currently mostly organized at national level. International cooperation is actively pursued in 

the framework of the Single European Electricity Market, which received a strong push with the adoption 

of the third package and the establishment of ENTSO-E and ACER. There are also a wide range of other 

options that could improve the flexibility of electricity markets. One prominent example was discussed in 

the previous section: the introduction of intra-day markets in which market parties have been provided 

with additional bidding options to find the optimal supply curve to meet electricity demand. Other options 

will be elaborated on in the next chapter. 

2.5.2  Network flexibility options  

The second category of flexibility options distinguished are the network flexibility options, both at the 

level of the transmission network and at the level of the distribution network, and including 

interconnection capacity. Grid balancing has become more complex as a result of large intermittent 

generation capacities and more dynamic electricity consumption patterns. The main bottlenecks for 

congestion management in Europe are: 

1.  Inefficient dispatch within countries due to poor communication to the market on the exact value 

of generation at different locations; 

2.  Underutilisation of the transmission network across national boundaries because scheduling is 

treated separately from domestic dispatch. This results in incomplete information on flows, 

demand and generation; 

3.  Limited ability to deliver ancillary services across countries because the available transmission 

capacity for international allocation is determined long before real time. 

Network flexibility options aim at improving the utilization rate of the existing networks to address the 

problems listed above. The options include the upgrading of dispatch rules, better communication 

between TSOs, and building more, or upgrading existing, transmission and distribution lines, including 

interconnection capacity. Network flexibility essentially deals with intelligent electronic devices including 

sensors, data and communication technologies and other smart technologies that will improve 

cooperation over larger geographic areas to improve network netting capacity and congestion 

management. Capacity optimisation and congestion management mainly relies on all information being 

centrally available; implementation of better rules and more transparency in market information would 

otherwise not be sufficiently effective. The available means to incorporate flexibility options in the 

electricity network include distributed command and control systems, flexible communication, a wide 

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variety of digital devices, power electronic technologies such as HVDC (High Voltage Direct Current) 

transmission and power control devices such as Flexible Alternating Current Transmission System 

(FACTS) devices and phase-shifting transformers. The integrated communications infrastructure also 

requires the strengthening of cyber security to ensure reliable long-term operations of millions of nodes. 

The benefits of implementing network flexibility options are: 

1.  Full use of existing transmission capacity to reach effective domestic and international congestion 

management;  

2.  Flexible joint allocation of international transmission capacity for its use where it is most needed 

at the day-ahead market; 

3.  Full use of low-cost generation sources across countries when international transmission 

allocation is integrated with the day-ahead energy market; 

4.  Better response to weather forecast uncertainties when integrating congestion management with 

the intraday and balancing markets; 

5.  Robust analysis of future congestion patterns to guide investment choices.  

2.5.3  Supply-side flexibility options 

Power plants have traditionally provided nearly all system flexibility. The services that can be 

distinguished include services which provide continuous response to balance generation and load under 

normal conditions (frequency response and reactive power), fast reserve services that are on stand-by to 

deliver additional power in response to a power system contingency, voltage control and black start (the 

ability to restart the power system following a black-out). 

Supply-side flexibility is delivered by a fast increase or decrease of output from a production plant. 

Response during operation is defined by the ramp rate – the rate at which the plant can increase (ramp 

up) or decrease (ramp down) its output. Some types of production units can also provide additional 

production at short notice while not being operated, a so-called quick start. Gas turbines are typical plant 

types that are used for quick starts or ramping. The average ramp rate of gas turbines is 25 MW per 

minute, with variations between 10 and 100 MW per minute. The ramp rate depends on the capacity and 

configuration of the plant, its operating conditions (idle, just starting up, operating at partial load) and 

optional technologies for reducing start-up time and increasing ramp rate. Full ramp rates can only be 

achieved when the plant has reached self-sustaining speed. Gas fired power plants that use integrated 

combustion engines can also have very quick start capabilities and ramping. Estimates for reaching full 

load vary from 2 to 8 minutes under hot start conditions and 10 to 13 minutes under cold start 
conditions.5 

Supply flexibility has been so far nearly exclusively provided by conventional generation. In the debate 

for defining capacity remuneration markets, it is often assumed that this near-exclusivity would remain. 

However, with increasing needs for system flexibility and decreasing shares of conventional generation, 

intermittent renewable generation could provide a larger share of ancillary services and most likely this 

option will be needed to provide the necessary flexibility to allow for the integration of the larger 

expected share of renewables. 

5 The lower limits can, for example, be found in communications from the industry such as (Wärtsilä, 2014). The upper limits can among others 
be found in (Kiviluoma, 2013). 

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Against this background manufacturers are further developing the technical capability of wind and PV to 

deliver ancillary services, and some countries, e.g. Germany and Spain, offer incentives for wind farms 

with increased capabilities. The ability of intermittent renewables to provide ancillary services is 

determined by their technical capability, the stochastic nature of their production and the economics of 

providing these services. 

A European project (Faiella, 2013) concluded that wind farms are capable with today’s technology of 

providing frequency response but some further technology developments are required for sustained 

support. By operating wind turbines at part load positive balancing can be provided. Under current 

conditions this is, however, usually not economic (Dena, 2010). Wind farms are more readily able to 

provide negative balancing (i.e. lower their production on request of the system operator). For longer-

term reserve services the main issue is the stochastic nature of wind production. The ability of wind to 

provide these services relies on increases in forecasting accuracy and pooling/smoothing of wind 

generation clusters. A further barrier is represented by the requirement of many ancillary services to 

commit a fixed amount of capacity ahead in time, which cannot be guaranteed due to the imprecise 

nature of wind forecasts. In the same project it is concluded that although PV is technically capable of 

providing ancillary services, it is expected to be economic only for large portfolios of PV spread over large 

areas (Kreuzkamp, 2013). 

A European project (Faiella, 2013) concluded that wind farms are capable with today’s technology of 

providing frequency response but some further technology developments are required for sustained 

support. By operating wind turbines at part load positive balancing can be provided. Under current 

conditions this is, however, usually not economic (Dena, 2010). Wind farms are more readily able to 

provide negative balancing (i.e. lower their production on request of the system operator). For longer-

term reserve services the main issue is the stochastic nature of wind production. The ability of wind to 

provide these services relies on increases in forecasting accuracy and pooling/smoothing of wind 

generation clusters. A further barrier is represented by the requirement of many ancillary services to 

commit a fixed amount of capacity ahead in time, which cannot be guaranteed due to the imprecise 

nature of wind forecasts. In the same project it is concluded that although PV is technically capable of 

providing ancillary services, it is expected to be economic only for large portfolios of PV spread over large 

areas (Kreuzkamp, 2013). 

2.5.4  Demand-side flexibility options (demand response) 

Flexibility options on the demand side have traditionally been used to a far lesser extent than supply-side 

options but they have very significant potential. A general distinction can be made between demand 

response in terms of temporarily curtailing electricity demand and shifting demand to other time periods. 

Demand response is defined as a consumer’s ability to reduce its electricity demand in response to price 

signals or other incentives or regulations. The most common type of demand response in the past has 

been energy management programs in which a large industrial consumer has a contractual arrangement 

with its power utility for the option to curtail or shift demand during pre-defined time periods against 

contractual pricing arrangements. Advances in communications and control technologies have greatly 

expanded demand response capabilities. Automated communication has improved the application in 

industry but also opened the door to medium-sized consumers. 

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Demand side response can potentially be used to decrease energy costs, both by shifting or reducing 

demand procured in the wholesale market and by providing ancillary services to balance demand and 

supply. Furthermore, by reducing peak demand, required investments in generation capacity and 

networks can be reduced. Several studies provide estimates of the potential of demand side response to 

reduce peak demand in 2020, varying from 5%-20% in 2020 (see for example (Dena, 2010), (Gils, 

2014) and (Bertsch, 2012)). Responsive demand is economically and commercially most readily available 

in industrial and commercial sectors. Most of the current and expected near-term demand side response 

is also from these sectors. Many studies identify an even larger potential in the residential sector, but in 

many member states further technical rollout and commercial arrangements (aggregation and market 

access) are required to unlock this potential. 

The result of peak shaving (demand reduction) usually also results in a decrease of overall CO2 emissions 

due to a reduction of electricity demand. However, market services for demand reduction do not 

necessarily distinguish between “pure” demand reduction and increase in embedded supply, for instance 

from back up or emergency diesel generators. In case the latter are employed the direct impact on 

emission could be an increase. The impact on CO2 emissions of peak shifting is less straightforward and 

depends on details of market arrangements, demand profile and generation mix. 

2.5.5  Electricity storage  

Storage of electricity is an option that can serve both the supply and demand sides of the electricity 

system by facilitating a shift in either over time. The type of services that storage can provide depends 

on both the level of application and the characteristics of the storage asset. Storage assets can be 

deployed at centralised generation and transmission level (large scale centralized storage), down to 

distribution and residential level (distributed storage). A key distinction between storage technologies is 

their ability to provide power (kW) and their ability to provide energy (kWh, h). Their cost, in terms of 

power (€/kW) and energy (€/kWh) capacity, together with the cycle lifetime, are the most pertinent 

characteristics determining which applications storage technologies are most suited for. Energy 

management applications such as peak shifting can be provided by both centralised and distributed 

storage. Centralised storage is currently more suited to providing ancillary services due to size 

requirements and current commercial arrangements, but through emerging aggregation services 

distributed assets could provide similar services. Distributed storage also has the potential to support 

distribution networks in the integration of embedded intermittent generation through local network peak 

reduction. Some distributed options have quite big advantages; for example they are scalable, can be 

sited anywhere and have a very fast response time. 

Large-scale pumped hydro accumulation storage (PHS) is traditionally storage option that is most used. 

During periods of low electricity demand and/or prices, water is pumped from a lower level reservoir to 

an upper reservoir. During periods of high electricity demand and/or prices, the water is released to 

generate and sell the electricity. Many opportunities for pumped storage in Europe have already been 

exhausted and it is not expected to be able to provide all types of services that are required in a fully or 

partially decarbonised energy system. 

Interactions between electricity market reforms and climate policies 

 33 

 
 
 
  
 
 
The further potential for stationary energy storage could increase significantly. Several studies estimate a 
further EU system optimal deployment of storage by 2020 of some 20-50GW.6 For many grid storage 

applications price signals are still relatively weak compared to the capital cost of storage, and overall 

conditions for the large scale commercial deployment of grid scale energy storage are expected to arise 

only after 2020-2030 in most EU Member States (Dena, 2010). However, favourable conditions for 

storage could arise in local areas much sooner, as well as for specific applications, especially the 

provision of frequency response and PV integrated solar. 

Batteries are currently the next biggest category of storage technologies after pumped hydro storage. 

Historically sodium sulphur type batteries have seen the highest deployment, but the market share of 

other batter types, including Li ion and flow batteries is strongly increasing. At distribution level other 

storage options distinguished are fly wheels, super capacitors, hydrogen, and power-to-gas and electric 

vehicle storage. Another large-scale storage option is compressed air energy storage (CAES) where, 

during low price periods, the compressed air is injected into subterranean caverns or porous rock layers 

and, during high priced periods, the air is released to drive a generator to produce electricity. The 

economics and market maturity of various storage options are pictured in Figure 8. 

Figure 8 » Economics and market maturity of various options for electricity storage 

Source: JRC (2011) 

An important item not addressed in this study is thermal storage (storage of heat). In several European 

markets the electricity production capacity contains a significant amount of combined heat and power 

generation, owned and operated by energy companies, by industry, by agriculture or by municipalities 

(mostly district heating). Most of these production units are tuned to providing heat at the time this is 

required for process heat, space heating or water heating. Electricity is produced as a by-product and 

their producers are price-takers on the electricity market. However, part of this capacity could be 

6 For example (Bertsch, 2012) estimates 46 GW, (Lux, 2012) reports 15 GW for 2017. 

Interactions between electricity market reforms and climate policies 

 34 

 
 
 
 
 
operated to follow electricity demand instead of heat demand. This flexibility allows CHP plants to 

generate electricity at times of high demand or turn down at times of low demand and high renewable 

generation, if it would otherwise not have been able to do so due to heat demand constraints. This 

optimisation may increase the profitability by increasing the share of generation at times of system high 

demand and high electricity prices. If electricity is supplied at times when it is most needed it can be sold 

at higher prices. A condition to switch to following electricity demand is that part of the heat would need 

to be stored. Heat storage can be a cheaper option than electricity storage and therewith an interesting 

option to improve the economics of the entire energy system. 

2.6 

Identifying the main research questions 

This study aims to provide further understanding of recent and future developments in European 

electricity markets and their interactions with climate policies, specifically: 

  Whether revenues on existing markets are sufficient to provide sufficient level of profitability to 

cover costs; 

  How changes to existing markets and/or complementary markets would impact the revenue 

generation in the power sector. 

  How selected proposed market reforms may impact progress towards the main energy and climate 

change objectives. 

Specific research questions identified are: 

1.  Which problems are faced by the electricity sector and how do they relate to the transition 

towards a decarbonised electricity sector? 

2.  How would the problem evolve in case of further decarbonisation of the EU power sector? 

3.  Will strengthened energy-only markets (including ancillary services and carbon prices) be able to 

provide sufficient incentives for new investments?  

4.  What additional capacity remuneration measures are currently applied, or debated, in the 

European markets to face system and adequacy challenges? How do the (proposed) electricity 

market reforms and capacity remuneration mechanisms reviewed in the five countries analysed in 

this study address the problems identified?  

5.  How could the proposed CRMs influence the decarbonisation of the power sector?  

Interactions between electricity market reforms and climate policies 

 35 

 
 
 
 
 
 
 
 
3 » Tomorrow’s electricity market 

Historically, balancing services in electricity markets were required only for rare occasions or for small 

load volumes. As the vast majority of electricity production facilities were fossil-fuelled units the need for 

balancing services occurred only in cases of load prediction errors and in the rare event of unplanned 

power station outages. The amount of balancing power was thus very small compared to the total 

amount of production in the market. With relatively high amounts of reserve capacity contracted and 

small amounts of actual balancing power requested, the need for short-term ancillary services was also 

small. 

With the large growth of intermittent electricity production capacity in European markets, this situation 

has changed. The uncertainties of balancing at real time are much higher now, both in volume and 

frequency. This has resulted in a more significant demand for services that balance markets. Various 

proposals have been made for additional markets that should complement the existing energy-only 

market. The expansion of CRMs is the option that is most frequently advocated and is a focus of this 

study. However, to enhance system adequacy and capacity adequacy, further improvements can also be 

made to the energy-only markets themselves. This chapter discusses recent developments and provides 

an analysis on further ways to strengthen the energy-only markets, specifically focusing on the balancing 

markets. In section 3.6 we briefly raise the issue of changing conditions to the integration of renewables, 

which is not further taken up in this report. In Section 3.7 we add a discussion on the possible role and 

design of CRMs, arguing that it is unclear if they are needed once the other elements have been 

addressed and that if a CRM is considered as needed then it would be best to ensure that its design 

features incorporate a wider set of flexibility options. 

3.1 

Ending regulated prices? 

Regulated prices for small consumers have traditionally aimed at preserving fairness and preventing 

abuses against small consumers, especially in times when large investments were needed to reach not-

yet served consumers. 

Regulated prices, however, also have important impacts on system and capacity adequacy. System 

adequacy is affected by price regulation when price caps that are used to protect consumers against high 

(short-term) prices limit the opportunity for cost recovery for flexible and peaking units that are needed 

for balancing the system. For the same reasons, these price caps increase the “missing money problem” 

for fossil-fuelled power plants that cannot recover their investment, especially gas-fired power plants. 

This directly affects capacity adequacy, especially future capacity adequacy, as new investments for 

increasing the net reserve margin are either stopped or delayed. 

Price caps can also affect the two key climate objectives of decarbonising the power sector and increasing 

the share of renewables. If regulated prices are kept artificially low, demand side response for small 

consumers will not be cost-effective and might result in too high consumption. An increasing electricity 

demand, especially when unexpected, usually results in fossil-fuelled power plants operating more hours 

than planned. Instead, market-based price signals are a better basis to promote a fair development of 

Interactions between electricity market reforms and climate policies 

 36 

 
 
 
 
 
 
renewables and investments in new technologies and flexible solutions both in the generation side and in 

the demand side. Assuming a more realistic price formation dynamics in tomorrow’s power market may 

very well help the energy-only market to be able to provide a fair capital cost recovery of required 

investments. 

There are of course strict boundary conditions to the timing of ending price regulations. In order to 

ensure sufficient consumer protection, the markets should be sufficiently opened. Consumers should have 

good switching opportunities and there should be sufficient market elements to set limitations to the level 

of price variations. Enhanced market coupling, a stringent regulator, and improved interconnection 

capacity are some of the main market elements that would facilitate this. 

3.2 

Coupling of electricity market and balancing market 

Electricity markets and the markets for ancillary services are currently organised separately. In practice, 

however, both markets are strongly connected. The connection results from the fact that both markets 

concern the same transmission system and the services in both markets largely concern the same 

stakeholders. More importantly, however, actions taken in one of the markets affect the other one. Many 

producers bidding on the balancing market can only adjust the output of their plants close to real time if 

they are already operating, so when actually dispatched on the day. This clearly is the case for negative 

balancing – plants can only ramp down when there is actual production - but in most cases also positive 

balancing as there are very few plant types that can perform a quick start; all others can only ramp up 

while in operation. Conversely, a producer would only want to bid for negative balancing when the 

corresponding balancing price is higher that the foregone margin on its plant in the electricity market. 

This strong connection seems to be a contradiction with the separate organisation of markets, where 

parties submit separate and independent bids without knowing the result of the other market and without 

being able to make an explicit connection in their bid. With the increasing share of renewable electricity 

production and the higher need for balancing it seems a logical next step to link explicitly the two 

markets. This could provide efficiency benefits as production capacity that is contracted in the day-ahead 

market but no longer needed (for example because of improved information on wind power deliveries) 

could be offered in the intra-day market. This would allow those producers to earn a higher margin while 

the costs for contracting it as reserve capacity could be avoided. 

3.3 

International market coupling 

In February 2014 the Commission announced that it was starting a pilot project in which grid operators 

and electricity exchanges from 14 EU Member States and from Norway, covering 75% of the EU’s 

electricity consumption, will couple their day-ahead markets. The Commission is furthermore preparing 

EU Regulation that will make market coupling binding in the entire EU, and has indicated that this will 

lead to significant cost savings. This enhanced market coupling is an important step towards further 

realisation of the Single European electricity market. Europe is also making progress at the level of 

balancing markets. ACER has implemented cross-regional roadmaps that have resulted in successful 

integration of day-ahead markets and aims to implement a cross-border intraday market and flow-based 

market coupling in Central West Europe.  

Interactions between electricity market reforms and climate policies 

 37 

 
 
 
 
 
 
International linking of markets beyond current control zones has various benefits. First it can lower 

administrative costs, for example by holding joint auctions. This has already been shown in the German 

balancing market in which the four network operators have jointly operated one combined balancing 

market since 2001. Since 2004 the suppliers from the Austrian control areas of TIRAG and VKW have also 

participated in the German market and the Dutch network operator Tennet is contracting its primary 

reserve via the German auction system since the beginning of this year. Tennet has estimated that this 

joint approach could reduce annual costs by tens of millions of euros annually compared to continuing 

their own auctioning system (Tennet, 2014). Separately, a study conducted for the European Commission 

concluded that integration of the Nordic electricity market could lead to estimated cost savings of 

approximately €221 million each year compared to operation as stand-alone balancing markets. The 

same study indicated that total cost savings in Europe from the integration of balancing markets and the 

exchanging and sharing of reserves could be in the order of €3bn/year and could result in up to 40% less 

requirements for reserve capacity (Mott MacDonald, 2013). The IEA quotes estimates from various 

studies that quantified the potential benefits of market integration in Europe at between 12.5 and 40 

billion Euros per year, or a medium value of €6.8/MWh of consumed electricity (IEA, 2014). 

A second benefit of international market coupling is the increased balancing opportunities across borders 

and therefore increased resource efficiency in the European electricity market. With increasing 

interconnection between various national control zones the TSOs will anyway have to strengthen their 

cooperation since the physical characteristics of electricity will treat the system as one (electrons will flow 

through the entire system). Joint balancing needs could be best served by joint operation of balancing 

markets. This could result in further cost savings and, ultimately, even prevent investments in new 

production capacity when neighbouring countries have idle capacity. Allowing foreign producers access to 

the bidding across borders would therefore include a wider set of supply and demand options and lead to 

both short and long-term cost savings. An example of long-term cost savings could be realised in the 

Netherlands where currently idle gas-fired production capacity could be used as reserve capacity for 

Belgium and Germany, who both expect their net reserve capacity to be too low within a few years’ time. 

A third potential benefit is the opportunity to improve liquidity on the balancing markets. Increased 

access opportunities (and therefore a large amount of participants) could facilitate increased liquidity on 

the market. 

A pre-condition to enhance international market coupling, and therefore to actually reap the benefits 

identified, is that the electricity grids between the cooperating countries should be sufficiently connected. 

3.4 

Introducing balancing markets at local level 

More and more electricity consumers also produce part of their electricity load locally. The production and 

role of these so-called prosumers will be a very important element in the full decarbonisation of the 

electricity sector. By providing prosumers the option to balance their own production and consumption 
locally, as well as with neighbouring prosumers, local imbalances can be significantly lowered.7 This local 

optimisation should not just depend on individual consumer choices, but should be facilitated by time-of-

7 The balancing would likely also be a necessity when a strong growth in the use of electric cars would occur, as this will strongly influence the 
consumption pattern of small consumers. But then again these electric cars would also act as a local storage provider, which is another argument 
to pursue local balancing opportunities. 

Interactions between electricity market reforms and climate policies 

 38 

 
 
 
 
 
 
 
use tariffs (TOU tariffs), smart appliances that respond to these TOU tariffs and smart grids and smart 

meters that organise this use in a smart and automated manner. Industrial prosumers already engage in 

demand management, for instance in the UK to avoid high transmission system payments (TRIAD 

charges) by reducing load during the highest demand periods and by participating in balancing markets, 

especially for reserve services (STOR in the UK). 

Industrial sectors also make up the largest part of the further 2020 demand side management economic 

potential. Balancing for smaller consumers at low voltage levels is not the cheapest balancing option, but 

besides being a key element in the decarbonisation of the electricity sector, it provides a further 

stimulant to increase energy saving. The current electricity supply companies could act as aggregators on 

this market: bundling various prosumers into a net balancing capacity of significant size. In addition 

separate aggregator companies are emerging that perform this service. A similar development seems to 

be happening in the US where several states are shifting utility regulation to meet the needs of a more 

distributed, consumer-focused energy system and where the utilities of the future are indicated as 

Distributed System Platform Providers. Bundling services can also be developed by specialised service 

companies, following the concept of energy supply companies. The risk of neglecting this measure is that, 

given the current developments in distributed generation and storage, soon prosumers will have the 

choice to disconnect from the grid themselves when the cost of storage goes down (gating factor). 

3.5 

Expanding market access opportunities 

The fast increase of intermittent renewable electricity supply has already prompted the development of 

intraday markets, which play a prominent role in reducing the high uncertainties of wind power 

predictions in the day-ahead market. Access to balancing markets in many European countries, however, 

is restricted to balance responsible parties, which in most cases are the larger electricity suppliers and 

traders in that market. Other market parties can make bilateral arrangements with these balance 

responsible parties but direct access is not allowed. This limitation severely restricts the possibilities for 

smaller renewable electricity generation units and other distributed generation. Current technological 

developments including improvements in wind prediction tools and energy management systems, are 

strongly improving the certainty of hourly feed-in, allowing renewable electricity generators to make firm 

delivery commitments already on a share of their production capacity. For non-intermittent generation 

even more firm delivery commitments can be given. 

In some balancing markets – for example markets for contracting emergency reserve - specific 

aggregators are allowed to bid. These aggregators bundle the balancing capacity of several (smaller) 

producers and offer this as one package to the market. Such service packages could also include storage 

units and demand-side response options. Broadening the possibilities for such aggregators to operate 

also on other balancing markets would improve the opportunities for smaller renewable electricity 
generation units and other distributed generation to participate in balancing markets.8 By doing so the 

liquidity in these markets could increase. 

8 Note that on the basis of EC Law flexibility providers such as aggregators or storage operators have the right to operate in balancing markets, 
reserve markets and other system services markets. In most of these markets, however, access is restricted or at least complicated. 

Interactions between electricity market reforms and climate policies 

 39 

 
 
 
 
 
 
 
3.6 

Changing conditions to the integration of renewables 

An important matter is the (need for) changing conditions to integration of renewables and/or 

decentralised generation in the market systems. In this, it is especially important that renewable 

electricity production options that have reached a certain level of maturity take up full system balancing 

responsibilities as well as face market competition requirements. The latter would be implemented by 

ensuring that their electricity production is sold on regular electricity markets while additional financial 

support provided is granted in the form of a premium in addition to the price obtained on the electricity 

market. These elements are addressed in the new Guidelines on State aid for environmental protection 

and energy 2014-2020, which entered into force in July 2014 and are not further taken up in this report 

given the focus of the analysis. 

3.7  Which role for (redesigned) capacity markets? 

Introduction of capacity mechanisms is frequently proposed as a key solution to complement the energy-

only market. The main argument used is that electrcity prices are insufficient to provide incentives for the 

invsetment needed to ensure secure electricity supplies and thus that such mechanisms are required to 

trigger new investments. This solution is especially advocated by some of the larger electricity generation 

companies, who have a keen interest in obtaining an additional source of revenue, and by some policy 

makers who are concerned about near-term power failures or future capacity shortages. The latter (often 

implicit) objective results in (proposed) capacity markets to be accessible only to domestic electricity 

production units. This is, for example, the case in the proposed French system.  Such limitations of 

access to capacity markets are not consistent with the goals of establishing a Single European market for 

electricity. 

Capacity markets and other types of CRMs are designed to correct market failures in the energy-only 

market. However, some (proposed) CRMs only deal with capacity adequacy within national borders and 

do not take cross-border capacity and trade into account. This potentially results in new market 

distortions. Individual (asymmetric) CRMs are liable to distort cross-border trade by causing over-

capacity and/or by distorting allocation of investments. The consequence of this is that importing 

countries must invest more and exporting countries must export less. Adverse effects may result, even if 

countries implement the same CRM, but with different design parameters like capacity payment levels, 

strike prices and reliability standards. When designing the CRM, it is therefore important to build in 

support for international trade options as well as the domestic power sector. 

If adapted energy-only markets would not be able to provide the required market incentives to ensure 

the adequacy of the system and introduction of a capacity mechanism is concluded to be the best option 

to complement the energy-only market, then some design features could be altered to ensure that such a 

proposed complementary market would better fit within the scope of the European energy and climate 

policy framework. It is important to note that capacity markets and other CRMs have an inherent risk of 

creating lock-in effects which might also be in tension with the decarbonisation objective. Investments 

that will be made on the basis of this complementary market will become a part of the European energy 

landscape and would in normal market circumstances be operated for decades. Policy makers must 

therefore ensure that such new investments do not create additional barriers to the goals defined for the 

completion of the Single European electricity market and the targeted decarbonisation of the electricity 

Interactions between electricity market reforms and climate policies 

 40 

 
 
 
 
 
sector. Moreover, it is important to ensure that the complementary market in itself would not become a 

locked-in element of the European electricity system. If the energy-only market could be adapted so that 
it delivered the correct price signals9 to ensure the required investment, system adequacy and capacity 

adequacy, then the complementary market would no longer be needed or would need to be adapted 

towards services then needed or valued by consumers for which yet no adequate price signals exist. This 

could for example be demand response services or electricity storage. The energy-only market with 

higher wholesale market prices in itself in combination with a reformed carbon market would also provide 

strong support to such services as their cost-effectiveness would strongly improve. 

3.8 

A fine balance between supply and demand flexibility options 

In addition to restricting access to national parties the current proposed and/or implemented market 

reforms primarily focus on stimulating the availability and use of flexible capacity. Flexible capacity is one 

of the main flexibility options, but other options are also available and needed for long-term reliability of 

the electricity system. In the scope of the decarbonisation of the electricity sector it is particularly 

important that the flexibility options with a lower carbon footprint are also stimulated. Ideally, if a 

capacity market or another type of CRM was formulated alongside the energy-only market, this would be 

a mechanism for providing flexibility that would include all options required to secure electricity supplies 

both in the short and the long terms. This ideal balancing is illustrated in Figure 9. By providing potential 

regular payments to all these flexibility options, each one’s business case could improve. The integration 

of all flexibility options into a common market system would enhance the single European electricity 

market and, by including an element of competition between various options, a cost-effective solution 

could be found. If it turned out that a specific option was preferred, e.g. due to having a lower carbon 

footprint, being a stronger facilitator of the decarbonisation of the power sector, or any other societal 

reason, then additional support could be provided in the form of a premium for this option. 

Figure 9 » Graphical representation of system balancing. The proposed flexibility market would include each of the 

system flexibility mechanisms identified 

9 In the current European climate policy framework this would require high carbon prices and thus a strong reform of the EU ETS in which carbon 
allowances became much scarcer. In the quantitative analysis we address whether a combination of an energy-only and a strengthened carbon 
market would indeed be able to provide price signals at this required level. 

Interactions between electricity market reforms and climate policies 

 41 

 
 
 
 
4 » Interaction between electricity market reforms 

and EU policy objectives 

The interactions between electricity market reforms and the EU energy and climate policy objectives are 

complicated and diverse. Achieving the four power related energy and climate policy objectives analysed 

in this study (as defined in Section 2.2) requires that electricity market reforms are operationalised by a 

mix of flexibility options. 

This chapter illustrates the main interactions between market factors and their impacts on energy and 

climate policy objectives. These impacts are measured by the corresponding electricity system indicators. 

Interaction diagrams are presented in the next sections to illustrate in a simplified way the complexity of 

these interactions, and to help to visualise the main impacts of introducing a selection of flexibility 

options. The relations shown in tables and diagrams are based on a literature review and qualitative 

interpretations. These relations do not include the results of the quantitative analysis reported in the 

following chapters. 

4.1 

Selection of flexibility options 

Flexibility options contribute in different ways to system adequacy and capacity adequacy, therefore they 

contribute differently to the energy objectives considered in this study. Depending on the nature of the 

specific measures, flexibility options impact also with different intensity on the decarbonisation of the 

electricity sector and on the growing share of renewable energy in the production of electricity. 

Five categories of flexibility options are analysed. These are flexibility options affecting:  

1.  The electricity system  

2.  The network system 

3.  The supply side of the market 

4.  The demand side of the market 

5.  Electricity storage 

Each category of flexibility options serves a different purpose. For example flexibility options in demand 

response and flexibility options in electricity storage have a high value in time-shifting of demand, 

whereas flexibility options in the supply side have a high value in providing reserve capacity. 

Technical and economic availability of the different categories of flexibility options varies considerably. 

Table 1 illustrates their levels of maturity, as well as their potential impacts on the decarbonisation of the 

power sector and on the further growth of renewables on the market. The indicated impact ranges from 

very negative (--) to very positive (++), with 0 indicating a (net) neutral impact. A similar classification is 

used to indicate from least mature (--) to most mature (++). A more detailed assessment is included in 

the following sections and Annex 1. 

Interactions between electricity market reforms and climate policies 

 42 

 
 
 
 
 
 
 
 
Table 1 » Potential impact and level of maturity of different flexibility options 

Technical 
maturity 

Economic 
maturity 

Decarbonisation of 
the power sector 

+ to ++ 

0 to ++ 

0 

Electricity system 
flexibility options 
Network system 
flexibility options 
Supply side flexibility 
options 
Demand-side flexibility 
options 
Electricity storage 
flexibility options 

+ to ++ 

0 to ++ 

++ 

+ 

++ 

+ 

- to + 

- / + 1) 

+ to ++ 

+ 

- to ++ 

-- to 0 

0 to + 

0 to ++ 

Growing 
share of 
renewables 

0 to + 

0 to + 

- / + 1) 

The ranges indicate that the extent of the impact depends on the specific design choice of this flexibility option. 

1): Negative when fossil-fuelled flexible capacity is stimulated; positive when renewable flexible capacity is stimulated 

A combination of flexibility options rather than the implementation of one single category is likely to be 

needed given the growing amounts of renewable electricity on the European market, and the technical 

and/or economic limitations of each technology. 

To achieve a cost-effective mix of flexibility options in the short term, with sustainable results for the 

longer term, electricity markets should be designed in such a way that the various options compete 

against each other in the same market. 

Four different flexibility options (one per category) are analysed in this chapter. These are options that 

will later also be quantified with the purpose-built modelling tool. No measure is analysed for the option 

to improve the organisation of the electricity system organisation since the model is not built to assess 

such options. 

1.  Network system: Increasing interconnections. This is an example of a network flexibility option 

and an integral element of the Single European Electricity Market. 

2.  Supply side: introducing capacity markets. This is an example of a supply-side flexibility option 

and one of the main topics of research for this study. 

3.  Demand side: Stimulating demand response. This is a potentially powerful flexibility option. 

Stimulation could entail financial support programmes, but could also rely on a change of tariff 

structure (such as introduction of TOU tariffs), change in the regulatory framework (that would 

enhance the value of demand response and/or ensure that the costs and benefits of demand 

response would be with the same market party), or information campaigns. 

4.  Electricity storage: Stimulating investments in storage capacity. Electricity storage could support 

supply shifting and therewith especially enhance the value of intermittent supply. If electricity 

storage flexibility would be considered needed then it would likely require additional support since 

most electricity storage flexibility options are not yet economic. 

Interactions between electricity market reforms and climate policies 

 43 

 
 
 
 
 
 
 
4.2 

Selection of market influencing factors 

The selection of the market influencing factors used in the analysis of this study is presented in Table 2. 

To help readability of tables and diagrams, these market influencing factors are classified by their 

features in six groups. 

Table 2 » Classification of the market influencing factors analysed 

Business operation 

Business finance 

Market demand  

  Operation of nuclear power 

plants 

  Maintaining coal-fired 

production capacity 

  Maintaining gas-fired 

production capacity 

  Maintaining storage capacity 

  Operation of renewable 

capacity (intermittent and 
non-intermittent) 

 

 

 

Economics of fossil-based 
capacity (coal-fired plants, 
gas-fired plants) 

Economics of storage 
capacity 

Economics of renewable-
based capacity (intermittent 
and non-intermittent 
renewable capacity) 

  Market electricity demand 

Market design  

Exogenous to market  

EU supporting policy 

 

Retail price regulation 

  Merit order rules 

 

 

Economic growth  

Coal prices  

  Gas prices   

 

 

Carbon prices 

Import/export capacity 

 

 

 

Renewable electricity policy  

Energy efficiency policy 

EU ETS 

4.3 

Analysing the influence of each factor and their interactions  

We have analysed the main direct influences of each market influencing factor and financial market 

response factor presented in Section 4.2. This is done by analysing the direct influence of each factor 

independently on each of the four objectives as well as on two intermediate electricity system impact 

indicators that provide a signal on the financial market response to the market influencing factors. These 

two additional intermediate indicators are: 

1.  Wholesale electricity price 

2.  Investments in new fossil fuel capacity, import and storage capacity 

These intermediate indicators are influenced by one or more of the market influencing factors. These two 

intermediate indicators are crucial to our analysis as they define whether capacity is kept in place or not 

and whether new investments are being made or not. At the same time these intermediate indicators act 

as financial market response factors as they also influence the four electricity system indicators 

corresponding to each key policy objective. 

The results of this analysis are included in various tables in Annex 1, comprising of:  

 

 

Table 21: Impact analysis of business operation factors 

Table 22: Impact analysis of business finance factors 

Interactions between electricity market reforms and climate policies 

 44 

 
 
 
 
 
 

 

 

 

 

Table 23: Impact analysis of market demand factors 

Table 24: Impact analysis of market design factors 

Table 25: Impact analysis of exogenous market factors 

Table 26: Impact analysis of EU supporting policies 

Table 27: Impact analysis of financial market response factors (intermediate indicators) 

However, while it is interesting to understand the direct possible impact of each of factor, the real market 

developments show us that the factors also may trigger several indirect market impacts. All these 

interactions result in a complicated picture of multiple direct and indirect impacts, which may occur in 

parallel, may strengthen each other’s impacts or may alleviate certain impacts. This broader picture of 

direct and indirect impacts is further analysed and illustrated in interaction diagrams. Sections 4.5 to 4.8 

show the interaction diagrams developed for the selected four flexibility options. A concluding table on 

market interactions is included in Section 4.9. 

4.4 

Direct and indirect interactions  

Following the identification of direct interactions between the various factors and flexibility options with 

the four energy and climate policy objectives, the next step of our analysis is to identify also the indirect 

interactions. To do so we use the concept of interaction diagrams. This is a simplified graphical 
representation of a selection of factors and interactions10, showing at one glance both a selection of direct 

and indirect impacts. This method can be used to understand the set of factors influencing a certain 

system indicator, how a certain potential direct impact can be strengthened or reduced by other potential 

impacts, or how indirect effects or loop effects influence the potential impacts. In the provided diagrams 

the positive impacts are indicated with green arrows and a positive influencing sign “+”, while the 

negative impacts are indicated with red arrows and “-” signs. The influencing factors are indicated in 

correspondence to the classification used in Table 2. 

The simple interaction diagram used for illustrative purposes in this study is shown on the following page. 

The diagram shows, for example, that wholesale electricity prices are determined by (among other 

things) electricity demand and the operation of various types of plants. Demand is determined by 

economic growth and various (European) energy and climate policies while plant operation is influenced 

by the plants’ economics, which in turn is determined by the fuel prices on the market (again among 

other things). Isolating the first two influencing steps, we generate the following ‘causes tree’ for the 

wholesale electricity price (Figure 10). 

10 To keep the functionality of the interaction diagram only a selection of the market factors and interactions is shown. 

Interactions between electricity market reforms and climate policies 

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Figure 10 » Causes tree for the wholesale electricity price as included in the interaction diagram 

The interaction diagram also illustrates the loop effects impacting the wholesale electricity price. The 

wholesale price is, among other things, determined by electricity demand, which in turn is influenced by 

the price level itself. Other loops are identified when focusing on plant economics. These economics are 

influenced by the wholesale price but this, in itself, also influences the operation of the plants, which are 

an influencing factor for that same wholesale price. 

In the following sections the interaction diagram is used to analyse the interactions and impacts of adding 

a specific flexibility option to the market system. The flexibility options selected for analysis are the same 

as the ones identified in Section 4.1. The qualitative analysis of interactions is further detailed in the 

modelling analysis which is illustrated in the following chapters. 

Interactions between electricity market reforms and climate policies 

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Wholesale electricity priceElectricity demandEconomic growthEnergy Efficiency policies(Wholesale electricity price)Maintaining coal fired production capacityEconomics existing coal fired power plantMaintaining gas fired production capacityEconomics existing gas fired power plantOperation nuclear power plantOperation of intermittent renewable capacityEconomics Intermittent renewablesOperation of non-intermittent renewable capacityEconomics Non-intermittent renewables 
 
 
 
Interactions between electricity market reforms and climate policies 

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4.5 

The potential impact of network flexibility options  

The impact of expanding interconnection capacity is analysed as an illustration of the potential impact of 

network flexibility options. 

Table 3 » Impact analysis of expanding interconnection capacity  
Expanding interconnection capacity 

Policy environment and potential 

Expansion of interconnection capacity or better utilization of import/export capacity in Europe is a crucial element in 

the realization of the Single European Electricity Market. In 2002 Member States agreed to increase minimum 
interconnection levels between Member States to 10% in 2020.11 In 2007 the Priority Interconnection Plan  was 

defined to further stimulate increased interconnection, including a list and ranking of projects eligible for Community 

assistance. In various regulations, programmes and facilities that followed the need for increased interconnection was 

strengthened and funds were made available to support the realisation of key infrastructural projects in the energy 

sector: the projects of common interest (PCIs). In its 2014 TYNDP ENTSO-E identified that the interconnection 

capacity must double on average throughout Europe, with a required investment of approximately €150 billion by 

2030 (ENTSO-E, 2014c). The EC made €5.85 billion available between 2014 and 2020 through the Connecting Europe 

Facility (CEF). 

Main direct impacts 

 

 

System Adequacy: Expanding import/export capacity has a direct positive impact on system adequacy as it 
contributes to a further integration of electricity markets. This enables a more efficient short-term balancing of 
supply and demand because system balancing is spread over a larger geographical area. System adequacy is 
furthermore supported as increased interconnection facilitates further market coupling. 

Capacity Adequacy: Expanding import/export capacity has a direct positive impact on capacity adequacy as 
supply and demand can be matched for a larger geographical region, which lowers the need for back-up or 
new investments in capacity for a single country. 

  Decarbonisation of the electricity system: Expanding import/export capacity does not directly contribute to 

further decarbonisation of the electricity system. 

  Growing share of renewables: The same as for “Decarbonisation of the electricity system”. 

Main indirect impacts 

 

 

System Adequacy: Improved interconnection can lead to lower investment needs for back-up and new 
capacity for individual Member States; the costs for system balancing will decrease. 

Share of renewables: It could facilitate the integration of more renewable energy production, as it supports 
that electricity can be more easily transported from the more cost-efficient production locations to the places 
with (high) demand. 

  Decarbonisation of the electricity sector: The potential higher share of renewables supports further 

decarbonisation of the electricity sector. However, if this results in export of renewables the national impact 
would be negative. On a broader level improved interconnection would facilitate better complementarity of 
different low carbon options and EU wide carbon price incentives will become more effective. 

Further potential impacts 

  When improved interconnection results in improved market coupling it may increase market liquidity and 

improve price signals in the European electricity market. 

 

Possible price increases to recover the costs of interconnections. 

11 European Council meeting, Barcelona, 15 and 16 March 2002. The current level is approximately 8%. In its communication on the European 
Energy Security Strategy the European Commission proposed to extend the interconnection target to 15% by 2030, a target confirmed by the 
European Council in October 2014. 

Interactions between electricity market reforms and climate policies 

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Interactions between electricity market reforms and climate policies 

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4.6 

The potential impact of supply-side flexibility options  

Table 4 » Impact analysis of introducing capacity markets  

Introducing capacity markets 

Policy environment and potential 

The strong growth of renewables and the pressing missing money problem in some Member States has resulted in a 

high level of attention for strengthening existing capacity remuneration mechanisms (such as strategic reserves) or 

the introduction of a new CRM such as a capacity market. The design characteristics of (proposed) capacity markets 

largely vary between the Member States as a result of which there is a large variation in types of plants or 

stakeholders that can participate. In general, however, proposed capacity markets would improve the economics of 

existing fossil fuel power plants. This could result in continued operation instead of closing or mothballing of oil-, coal- 

and gas-fired capacity. 

Main direct impacts 

 

 

System Adequacy: Capacity markets in general have a positive impact on system adequacy, as the amount of 
available capacity is maintained and/or increased to balance supply and demand. 

Capacity Adequacy: Capacity markets in general have a positive impact on capacity adequacy, as they make 
the business case for new investments in fossil fuel capacity more attractive. This may result in a decision by 
electricity producers to invest earlier in new capacity. 

  Decarbonisation of the electricity system: Depending on the specific design characteristics Capacity markets 

can either have a negative or positive impact on decarbonisation of the electricity system. The more 
favourable the design is for low-carbon technologies, and the more the capacity market stimulates more 
efficient capacity over less efficient capacity, the more positive its potential impact. Many proposed or planned 
capacity markets, however, seem to support mainly existing coal- and gas-fired plants which is hampering the 
further decarbonisation of the electricity system. A major risk could be that capacity markets would lock-in 
more carbon-intensive production or would hamper the dynamic efficiency of longer-term low-carbon options, 
both on the demand-side and on the supply-side of the power market. 

  Growing share of renewables: Capacity markets do not directly impact the share of renewables. 

Main indirect impacts 

 

Share of renewables: Most proposed capacity markets would provide additional benefits to fossil-fuelled 
plants. If the market structure would no longer provide priority access to renewables this could limit their 
further growth and/or operation. Depending on the specific design of the capacity market it could provide 
benefits for the growth of renewables as the capacity market could be tailored to support those flexibility 
options that support the use of renewables. The capacity market, for example, could support flexible gas-fired 
production or support demand-side options that support the integration of renewables (such as electricity 
storage). 

Further potential impacts 

  Disturbance of the energy-only markets : depending on the specific design of the capacity market a risk could 

be introduced of not providing proper price signals as a parallel market is created.  

 

 

Economic literature tells us that unilateral mechanisms distort investments and trade and lead to higher 
system costs. As for capacity markets: if capacity markets are targeted at specific capacity types they are 
likely to distort competitiveness among technologies (for example a capacity market targeted at peaking units 
would distort incentives for investments in CCGT and base load capacity), (Tennbakk, 2013). 

Capacity markets generally would be expected to reduce the frequency of peak price periods and could reduce 
peak prices. Therefore they could also reduce incentives for demand response, interconnection and storage. 
On the other hand, if remuneration mechanisms are also available to demand-side, storage and renewables 
options, then these options can receive additional revenues and possibly the corresponding government 
support could be lowered. In other markets (e.g. the PJM market in the US) experiences have shown 
significantly lower prices than expected when a broad range of flexibility options is considered in the capacity 
market 

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Interactions between electricity market reforms and climate policies 

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4.7 

The potential impact of demand-side flexibility options  

Table 5 » Impact analysis of strengthening demand response 

Strengthening demand response 

Policy environment and potential 

Estimates on the potential of demand response potential vary widely. The EC estimated that EU peak demand could 
be reduced by 60 GW, approximately 10% of the EU's peak demand. It also estimated that that broadly only 10% of 
the demand response potential is used today.12 Experiences from the US, and more limited experiences in Europe, 
show that in addition to a shift of electricity consumption in time, actual energy savings can be achieved. EU policy is 
actively stimulating several elements that facilitate demand response including: 

 

 

 

 

The 2006 Energy Savings Directive required individual meters to be installed when an existing meter is 
replaced. This was reconfirmed in the Energy Efficiency Directive in 2012. 

The same Directives require utilities to ensure that billing is based on actual consumption, and that tariffs do 
not prevent (and may support) demand-side response. 

The 2009 Electricity Directive that was adopted as part of the third energy package requires that at least 80% 
of consumers should be equipped with intelligent metering systems by 2020.  

As part of the 2013 Communication from the EC on delivering the internal electricity market a staff working 
document was published on demand response. 

Main direct impacts 

 

 

System Adequacy: Demand-side response could reduce system balancing needs as it acts as a balancing 
mechanism itself. 

Capacity Adequacy: It can flatten the load curve and lower capacity investment needs. In addition, demand 
side response can interact with small scale generation and storage, leading to further improved capacity 
adequacy. 

  Decarbonisation of the electricity system: It has a positive impact on decarbonisation as less generation from 

fossil fuel power plants is needed.  

  Growing share of renewables: It has a positive impact on achieving renewable energy targets as it lowers the 

total amount of consumption and therewith could lower the amount of fossil fuel production. 

Main indirect impacts 

 

 

Besides lowering peak demand, demand response policies can help to lower total consumption levels. (CE, 
2012) identified an average absolute saving of 4%, based on a large number of projects.  

(Dena, 2013) estimates that total avoided investments in fossil-fuelled generation capacity and transmission 
capacity could be in the order of €4bn per year. 

Further potential impacts 

 

Smaller consumers can more actively participate in the electricity market as they are able to sell their 
flexibility. 

  Demand-side response can create opportunities for aggregators and other service providers to enter the 

electricity market. 

12 EC, 2013a 

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Interactions between electricity market reforms and climate policies 

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4.8 

The potential impact of electricity storage flexibility options  

Table 6 » Impact analysis of stimulating investments in electricity storage capacity 

Electricity storage 

Policy environment and potential 

Electricity storage can be applied at different scales and based on various technologies, as has been elaborated in 

Section 2.5. With current wholesale prices, and especially decreasing spreads between peak and off-peak wholesale 

prices, most storage options are more expensive than other flexibility options such as additional transmission capacity 
or gas-fired flexible generation capacity.13 The Energy Roadmap 2050 considers energy storage as a critical element 

to facilitate the transition towards a sustainable energy system. The Priority Interconnection Plan PIP) and the list of 

PCIs includes some projects with a storage element, but most of these are pumped storage. 

Main direct impacts 

 

 

System Adequacy: Storage has a positive impact on system adequacy as it improves the utilization of the 

network, both at transmission and distribution level. 

Capacity Adequacy: Storage has a positive impact on capacity adequacy as it can delay or reduce the need for 

investment in new production capacity. 

  Growing share of renewables: Storage has a positive impact on decarbonisation of the electricity system as it can 

facilitate better use of renewables and improved integration into the electricity system. 

Main indirect impacts 

 

 

System Adequacy: Local storage options (batteries or electrical vehicles) enable system balancing at local level. 

System Adequacy: Storage facilities can provide effective balancing services.  

  Decarbonisation of the electricity system: Storage has a positive impact on decarbonisation of the electricity 

system as it enables better integration of renewables. 

Further potential impacts 

 

Electricity storage can shift electricity consumption from high-priced peak time to lower-priced off-peak time. 

13 This excludes pumped hydro storage, but most pumped storage capacity in Europe has already been 

exhausted. 

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Interactions between electricity market reforms and climate policies 

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4.9 

Summary on the impact analysis for the four flexibility options 

Table 7 summarises the impact analysis conducted in the previous sections. Each of the flexibility options 

selected can provide a range of positive impacts on four EU energy and climate policy objectives related 

to the power sector, as well as potential negative impacts. Chapters 6-10 include a more detailed and 

quantitative analysis on the potential impact of each of these flexibility options. 

Table 7 » Impact analysis of additional or new flexibility options on the four EU energy and climate policy objectives 

analysed 

Influencing 
factor 

System adequacy 

Capacity 
adequacy 

Decarbonisation 
electricity sector 

Growing share of 
renewables 

Additional or new flexibility options 

Network: 
strengthen 
interconnection 
capacity 

Supply side: 
strengthening or 
introduction of 
capacity market 

- Positive impact, 
as it makes 
additional 
production capacity 
available. The 
possibility of an EU 
market coupling 
the day-ahead and 
intra-day markets 
would provide 
improved price 
signals and a 
better basis for 
long-term financial 
markets and 
investments 
- Positive impact as 
capacity markets in 
general improve 
the 
competitiveness of 
fossil fuel power 
plants 

- Positive impact, 
as it makes more 
flexible resources 
available to 
balance systems. 
Also creates the 
possibility of an EU 
market coupling 
the day-ahead and 
intra-day markets, 
which increases 
cooperation 
between TSOs for 
balancing markets 

- Positive impact, 
as capacity 
markets in general 
improve the 
competitiveness of 
fossil fuel power 
plants. Could result 
in flexible capacity 
being able to be 
maintained 

- Positive impact, 
as it creates the 
possibility to 
import/export 
renewable energy 
to/from where 
demand exists. 
This more effective 
use of resources 
can facilitate a 
larger share of 
renewables 

- Potential negative 
indirect impact as 
capacity markets 
do not promote the 
further deployment 
of renewables but 
support fossil-
fuelled capacity 

- Positive or 
negative direct 
impact at country 
level, depending on 
the differences in 
carbon intensity 
between countries  

- Depending on 
the CRM design, 
potential positive 
impact when the 
capacity market 
favours cleaner 
and newer 
technologies. 

- Otherwise 
potential negative 
impact due to lock-
in risk 

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Influencing 
factor 
Demand side: 
support to demand 
response 

Enhancing storage 
capacity 

System adequacy 

- Positive impact as 
demand-side 
response could 
considerably 
reduce system 
balancing needs as 
it itself acts as a 
balancing 
mechanism 
(frequency 
response, reserve 
service, etc.) 

Capacity 
adequacy 
- Positive impact, 
as demand-side 
response 
smoothens the load 
curve and 
moderates 
electricity demand 
growth. Demand 
side response can 
interact with small 
scale generation 
and storage as 
well, leading to 
further improved 
capacity adequacy 

- Positive impact, 
as it enhances the 
competitiveness of 
storage capacity 
which is translated 
into a positive 
effect on system 
adequacy 

- Positive impact, 
as it enhances the 
competitiveness of 
storage capacity 
which is translated 
into a positive 
effect on capacity 
adequacy 

Decarbonisation 
electricity sector 
- Positive impact, 
as less generation 
from fossil fuel 
power plants is 
needed 

Growing share of 
renewables 

- Positive impact, 
as less generation 
from fossil fuel 
power plants is 
needed 

- Potential negative 
impact from 
reduction of peak 
prices and 
therewith lower 
plant revenues. 

- Positive impact, 
as it supports 
maintaining the 
storage capacity of 
low carbon options 

- Positive impact, 
as it supports 
maintaining the 
storage capacity of 
renewables 

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5 »  Quantifying the impact of market reforms 

A quantitative assessment was made to support further understanding of the effects of proposed 

electricity market reforms and, specifically, the (planned and ongoing) capacity mechanisms. This 

quantitative assessment is conducted on the basis of a purpose-built model and follows a step-wise 

approach to determine the potential future costs and revenue for various plants types. The assessment 

looks at three possible markets for revenue, including the impact of the carbon market: 

 

 

The wholesale markets (including the carbon price); 

The ancillary services markets; and, 

  Capacity markets and other flexibility options.  

The model uses exogenous assumptions about the production capacities that are available in the power 

sector, and looks specifically which capacities will supply this production at which prices, assuming price 

formation takes place in principle in a wholesale market driven by the merit order. This assessment gives 

insights on forecasted plant profitability, electricity prices and carbon emissions of a given capacity mix, 

which in term can give insights what market setups can better provide for the ongoing transformations in 

this sector in relation with energy and climate objectives. 

As a first step, the quantitative assessment focuses on determining the forecasted revenues from the 

wholesale market. The model used includes the carbon price – and therefore a plant’s opportunity costs 

from the carbon market - as an exogenous factor. As a second step, the modelling results are 

complemented with an assessment of the revenue created from ancillary services per type of plant. As a 

third and final step, a sensitivity analysis is conducted on the possible impact of market reforms, 

including changes in the existing markets as well as the impact of establishing additional capacity 

markets. 

5.1 

Profitability assessment 

In the analysis “profitability” will be assessed on an annualised basis, as outlined in the section below. 

𝒐𝒑𝒆𝒓𝒂𝒕𝒊𝒏𝒈 𝒑𝒓𝒐𝒇𝒊𝒕 = 𝒆𝒍𝒆𝒄𝒕𝒓𝒊𝒄𝒊𝒕𝒚 𝒓𝒆𝒗𝒆𝒏𝒖𝒆 + 𝒐𝒕𝒉𝒆𝒓 𝒓𝒆𝒗𝒆𝒏𝒖𝒆 − (𝒗𝒂𝒓𝒊𝒂𝒃𝒍𝒆 𝒄𝒐𝒔𝒕𝒔 + 𝒇𝒊𝒙𝒆𝒅 𝒄𝒐𝒔𝒕𝒔) 

The model determines electricity revenue for each plant as electricity generated by that plant 

multiplied by the wholesale price, which itself is determined by the short run marginal cost of generation. 

The electricity revenue is calculated for each example plant and aggregated by type of plant, such that 

the most efficient plant could be profitable, the least efficient plant unprofitable, and the aggregate could 

be either. A caveat that is repeated throughout the analysis is that the short run marginal cost of 

generation underestimates the wholesale price at times of scarcity. 

Variable costs are also determined on the basis of the dispatch calculation and include fuel and carbon 

costs, plus any other variable operating costs.  

Other revenue includes an estimate of ancillary services (per plant) and of heat sales from must-run 

CHP.  

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Fixed costs are taken from the literature on a per kW basis.  

To determine a proxy for the viability from an investment perspective, the capital cost (plus interest) is 

amortised over the lifetime and subtracted from operating profit for the given year: 

𝒆𝒂𝒓𝒏𝒊𝒏𝒈𝒔 = 𝒐𝒑𝒆𝒓𝒂𝒕𝒊𝒏𝒈 𝒑𝒓𝒐𝒇𝒊𝒕 − 𝒂𝒎𝒐𝒓𝒕𝒊𝒔𝒆𝒅 𝒄𝒂𝒑𝒊𝒕𝒂𝒍 𝒄𝒐𝒔𝒕 

The amortisation is calculated as the annualised investment cost, based on a 7.5% weighted average 

cost of capital (WACC) and technology specific economic lifetimes. The technology specific economic 

lifetimes are summarised in Table 43 (see Annex II). 

Earnings of zero, means that the investor receives the minimal needed return on its investment for 

compensating capital expenditure but nothing more. The interest return is assumed to be 7.5% and equal 

for all technologies. The second caveat that is repeated through the analysis is that we are only looking 

at operating costs and revenues for one year and that an investor would consider the lifetime. This 

method hence does not cover investment incentives emerging from future changes in electricity prices, 

fuel prices or carbon prices, and may hence underestimate investment incentives for low carbon 

technologies. Throughout the report the term “profitability” will refer to the annualised earnings as 

outlined above focussing on one representative year. 

5.2 

Step 1: The wholesale market 

The purpose-built model draws upon existing model components earlier developed by the project team. 

These components were put together and fine-tuned to address the specific questions put forward in this 

study. This section provides a brief overview of the modelling approach and the type of analysis for which 

it can be applied. Further details on the model and the modelling assumptions are included in this section 

as well as in Annex 2. 

The model focuses on analysing the impact of planned reforms with respect to the following main 

aspects: 

1.  Relative position of plants in the merit order and resulting load factors (i.e. impact on current 

system operations); 

2.  Impact on plant economics, leading to retirement and mothballing decisions for generation 

plants, impacting the generation mix (i.e. impact on utility business); 

3.  Impact on new generation profitability; 

4.  Impact on the decarbonisation of the electricity sector and the share of renewables in the 

electricity supply mix (i.e. impact on policy objectives). 

The model is built as an optimisation tool consisting of two modules:  

  A dispatch module, based on a static merit order of the electricity market; and, 

  A financial analysis module.  

A graphical representation of the model is shown in The model determines the merit order of plants on 

the basis of their short-run marginal costs. Plants that are labelled as ‘must-run’ capacity are included 

immediately after the (other) renewable production units. The must-run capacity includes renewable 

Interactions between electricity market reforms and climate policies 

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production plants that have priority dispatch on the market based on the current regulatory framework 

and plants that have a heat delivery contract, either to a district heating facility or to an industrial 

operator. Plants with heat delivery contracts have structured their operations on the basis of the 

contracted heat demand and supply electricity as a by-product, against any given price on the wholesale 

market. 

Figure 11 on the following page.  

The dispatch calculation is based on short-run marginal cost bidding and uses the demand profile of a 

country, which is assumed as fixed, given a certain generation capacity breakdown, cost and 

performance of technologies and the data around wind and solar availability. It estimates the run hours 

of each plant, the electricity-only revenues of each plant assuming all revenues are generated through 

the wholesale market. The model also determines the periods that have an insufficient amount of flexible 

operating plants available to address balancing needs. These intermediate outputs will be used to 

perform the general financial analysis of plant investment incentives. 

The model determines the merit order of plants on the basis of their short-run marginal costs. Plants that 

are labelled as ‘must-run’ capacity are included immediately after the (other) renewable production units. 

The must-run capacity includes renewable production plants that have priority dispatch on the market 

based on the current regulatory framework and plants that have a heat delivery contract, either to a 

district heating facility or to an industrial operator. Plants with heat delivery contracts have structured 

their operations on the basis of the contracted heat demand and supply electricity as a by-product, 

against any given price on the wholesale market. 

Figure 11 » Graphical presentation of the purpose-built model for this study 

5.2.1  Main model assumptions 

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The model is used to obtain an understanding of the first order impacts of market developments and/or 

policy decisions made. As with any model, it provides an abstract representation of the much more 

complicated real-life situation. The main assumptions made in this model with respect to the scope and 

methodology are: 

  Timeframe: Model calculations are made for the most recent year of available data, for 2020 

and for 2030; 

 

Investment decision making: the model follows a static, rational approach with exogenous 
assumptions on power generation capacity and investment decisions. It does not consider 
changes in the generation mix based on agent-based investment decision making. In other 
words, aspects such as strategic behaviour, portfolio approach and gaming are not included in the 
model; 

  Dispatch bidding: The dispatch bidding of individual market parties is based on technology 

costs, and not on strategic bidding or their entire production portfolio; 

  Wholesale price formation: Price formation on the wholesale market is based on short-run 

marginal cost bidding; 

  Demand: Demand is an exogenous factor to the model based on existing scenarios and it is 

inelastic to price fluctuations. The model uses an hourly demand profile. The model is based on 
net demand, i.e. excluding own consumption of power plants and refineries.  

  Plant dynamics: Plants are modelled in a static way. Production-based dynamic aspects are not 
included in the model. This includes ramp rates, minimum up and down time, part load efficiency 
derating (i.e. efficiencies that are lower at low production rates) and minimum stable generation; 

  Network: The network capacity modelled is based on the ENTSO-E ten-year development plans. 
Transmission limits such as location and congestion are not explicitly modelled. Network stability 
issues - such as whether sufficient spare capacity in flexible generation is available for frequency 
support - is not modelled, but conclusions on this are drawn on the basis of the model outputs; 

  Flexibility: The impact of flexibility services (e.g. demand response) and interconnectors are 

taken into account in the demand scenarios. 

Detailed model assumptions are included in Annex 2. 

5.2.2  Model results 

The model has been used to analyse the development of the profitability of assets in an energy-only 

market, with various market parameters adjusted to test sensitivity. The main outputs provided by the 

model include:  

1.  Profitability of each technology type, under various scenario conditions. The main output factors 

presented include: 

2.  Peak, mid-merit, intermittent and base-load profitability - to assess the profitability of the various 

market strategies. 

3.  Distribution curve of individual technology profitability - to assess the range of profitability. 

4.  The electricity price: Average annual price based on prices set by the merit order. 

5.  The number of dispatched hours for each type of plant and the number of hours when dispatched 

flexible capacity falls below a threshold limit - this provides a first order indication on system 

reliability issues. 

6.  The amount of CO2 emissions and CO2 emission intensities. 

The model uses a methodology based on short-run marginal cost pricing. This approach does not capture 

scarcity pricing above the short-run marginal costs, especially for periods of high demand. In such cases 

Interactions between electricity market reforms and climate policies 

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the price is set at level even higher than peak capacity prices, with is dispatched at a much higher price 

than the average wholesale market price. As a result the model will underestimate profitability. We can 

get a first indication of the extent to which prices are underestimated by comparing the modelling results 

for 2010 to historic market prices: 

  Average for all hours in the year: prices are 7% underestimated  

  Average for 60% highest demand hours in the year: prices are 11% underestimated 

  Average for 30% highest demand hours in the year: prices are 17% underestimated 

The question that is addressed in the model runs is whether changes in the structure of the specific 

market design impact revenue generation in the power sector. Or, put in another way, it given insight 

whether the required revenue to cover costs could plausibly be generated by such a market. In the 

following chapters the impacts are illustrated for the UK and Germany. In principle the analysis covers 

impacts of changes in market parameters such as: 

1.  Capacity mix 

2.  Fuel prices 

3.  CO2 prices 

4.  Demand (level and profile) 

5.  Interconnection capacity 

6.  Electricity storage and 

7.  Demand response 

The model provides interim results on plant profitability in a given year, electricity price developments 

and dispatch hours. Based on these results we draw conclusions on the resulting impact of market 

developments. 

5.3 

Step 2: The value and impact of ancillary services 

In step 1, the tailor-made model determines plant and system profitability on the basis of a wholesale-

only market. The calculations include the price developments in the European power market but neglect 

another important source of revenue for the power plants: the revenues from ancillary services. 

In step 2, the potential revenues from ancillary services are determined. This revenue is calculated based 

on expense data (from the TSOs) and known revenue streams (for power plants) on the current markets. 

Combining the modelling results and the revenues from ancillary services provides updated results on the 

plant revenues, which feed into an updated analysis on system adequacy and capacity adequacy, as well 

as an updated analysis on the decarbonisation of the power sector and the share of renewables. 

The analysis will guide further understanding of the formulation of market reforms. For example, the 

calculations may show that, on the basis of the current markets, certain plant types are not able to 

recover their costs and plant closure may seem imminent. While at present there is over-capacity in the 

EU market, these calculations could also reveal that insufficient incentives are provided for new 

investments, therefore threatening system adequacy in the longer term. The nature of the issues 

identified will provide explanations to the choices made in the proposed market reforms. 

Interactions between electricity market reforms and climate policies 

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5.4 

Step 3: The impact of further changes  

In the third and final step, the impacts of potential market reforms are presented. Starting from the 

perspective that policy makers aim to secure both system adequacy and capacity adequacy, some market 

interventions are defined. 

Understanding that many different types of market reforms exist and that the market reforms proposed 

will be very specific, we do not aim to draw exact conclusions on the impacts, but rather point out the 

direction of such impacts. To illustrate with an example, we will not provide estimates of the price impact, 

the value of lost load of enhanced international cooperation in balancing markets or the value of 

improved interconnection. The results will instead indicate to what extent considered market reforms may 

have a positive or negative impact on system adequacy, capacity adequacy, decarbonisation of the power 

sector and on growing the share of renewables on the European power market. 

Interactions between electricity market reforms and climate policies 

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6 » Analysing the UK electricity market 

This chapter contains an analysis of the UK electricity market, including the electricity market reforms 

that were recently introduced, further planned reforms and the interaction of the reforms with climate 

policies. It starts with a summary of the main drivers for the electricity market reform (Section 6.1), 

followed by a status update of its main elements (Section 6.2). Sections 6.3 to 6.9 present the step-wise 

quantitative assessment of the UK electricity market. First we present an assessment of the UK’s capacity 

mix (Section 6.3) and its sensitivity to various market elements (Section 6.4). Next, we assess the 

impact of adding revenues from ancillary services (Section 6.5). The modelling results illustrate the 

challenges on system adequacy and capacity adequacy in the UK market, which provides a further insight 

on the necessity of market reform. In Section 6.6 we analyse the impacts of the first results from the 

capacity auctions. In Sections 6.7 to 6.9 the impacts of an increased CO2 price and of alternative 

flexibility options on the UK market are analysed, after which conclusions are drawn in Section 6.10. 

6.1 

Main drivers of the electricity market reform 

The UK has committed to achieving 80% emission reductions by 2050, stringent Carbon Budgets up to 

2025 and 2020 RES targets. The UK’s decarbonisation strategy of the electricity sector is based on the 

deployment of three low-carbon technology groups: renewable sources, nuclear power and carbon 

capture and storage (CCS). Wind energy is expected to be the main technology employed in meeting the 

UK’s RES targets, as a result of which intermittency issues are expected. These expected developments 

have been the main drivers for the proposed energy market reform (EMR). Other drivers include: 

 

Lack of end-user demand response as a result of information asymmetries (consumers only react 
to average prices) leads to overall inefficiencies in the market whereby consumers do not face the 
higher marginal prices at times of high demand, and thus have suboptimal demand response. 

 

Expectations of overall electricity demand to increase due to electrification of heating and 

transport.  

 

Expectations of de-rated capacity margins likely to fall below 5% by 2020, which would put the 

UK at risk of blackouts.  

  A large share of existing capacity – approximately one quarter– is expected to be closed down by 

the end of this decade, either due to ageing of the facilities (e.g. nuclear reactors) or due to 

stringent emissions regulations (coal plants). A large part of the existing coal-fired capacity is 

expected to either close by 2016 under the Large Combustion Plant Directive (approx. 8GW) or 

opt out of the Industrial Emissions Directive, thereby closing by the end of 2023. 

  Gas plants have higher operating costs than the low-carbon options, so they rely on high 

electricity prices in peak demand and run less often overall, which is often cited as a disincentive 

to investment. New coal plants are not possible without CCS in the UK because of the Emissions 

Performance Standard (EPS) regulation (as part of EMR), while investment in new nuclear is 
forthcoming but is not expected to lead to new capacity until at least 2020.14 

Renewable electricity capacity in the UK has almost tripled in the past 5 years, albeit from low starting 

levels, while total generating capacity has grown only slightly. This has led to an increase in intermittent 

Note 3 »  Note that in the current situation older nuclear plants are seeing their lifetime extended. 

Interactions between electricity market reforms and climate policies 

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supply but not to a degree to undermine the functioning of the dispatch market (wholesale prices have 

remained positive and there have not been brownouts or blackouts). The steep increase in intermittent 

renewable capacity expected in the medium term, combined with the expectation that non-intermittent 

capacity will drop by a quarter in the next decade, has led to concerns about the operation of the future 

electricity market. The UK Government has therefore developed a proposal for a capacity market, as part 

of the Electricity Market Reform package. Using this mechanism the government aims to stimulate 

investment to replace the closure of base-load coal and nuclear plants in the context of considerable 

(perceived) uncertainty in the electricity market, and to ensure reliability of the system. 

6.2 

The market reform 

The UK Electricity Market Reform (EMR) programme was introduced to incentivise investment in secure, 

low-carbon electricity, while improving the security of the electricity supply in England, Wales and 

Scotland, and improving affordability for consumers. The Energy Act 2013 introduced a number of 

initiatives to achieve this, in particular the Capacity Market (to help ensure security of electricity supply) 

and Contracts for Difference (incentives for new low-carbon initiatives). Other elements of the EMR 

included the Electricity Balancing Significant Code Review that led to major changes in imbalance 

settlement (allowing prices to rise to GBP 6,000/MWh and including a forced price adder when ancillary 

services are running low), a domestic carbon price floor and introducing emission performance standards 

on new production capacity that in practice prevent new investments in coal capacity without CCS. 

The Electricity Capacity Regulations 2014 were officially published on July 31st 2014. The capacity 

market is designed to ensure security of electricity supply by providing a payment to reliable sources of 

capacity, alongside their electricity revenues, to ensure that they are available to deliver energy when 

needed. The capacity market aims to encourage the investment needed to replace older power stations 

that will be closed, and also serves to stop plants from being mothballed. It also aims to provide the 

capacity to back up more intermittent and inflexible low-carbon generation sources. Finally, the capacity 

market has also been designed to support the development of more active demand management in the 

electricity market. 

The British capacity market is a so-called capacity auction system. The design of the capacity market 

includes the following features: 

  Annual auctions will run every autumn, four years before delivery.  Capacity agreements will be 

auctioned in which selected suppliers will be committing to providing capacity with penalties 

imposed in case of non-compliance. The first capacity auction was held in December 2014 for 

delivery in the winter of 2018. The clearing price on that auction was £19.4/kW/yr. 

 

Existing as well as forthcoming capacity is eligible and, as auctions are held several years in 

advance, additional capacity may be built in the interim. Results from the first auction included 

only 5% of the capacity to be provided by new build with the remaining capacity won by existing 

plants. 

 

Eligibility is limited to plants not under Contracts for Difference (i.e. renewable energy projects, 

new nuclear or CCS projects that receive an additional financial support). Also, interconnectors 

are not allowed to participate in the first round of auctions, but current plans are for them to be 

Interactions between electricity market reforms and climate policies 

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eligible for the first time in the planned December 2015 auction. Demand side response measures 

are eligible. 

Two more additional tools were introduced to bridge the period to the start of the capacity market: 

 

The Supplemental Balancing Reserve (SBR) to target power plants that are deemed necessary for 

reserve power and that would otherwise be closed or mothballed.  

 

The Demand-side Balancing Reserve (DSBR) to target large energy users who are willing to 

reduce their electricity use during peak times in return for a payment. 

6.3 

Capacity mix and the impact of decarbonisation and further 

renewable growth 

The model was calibrated using UK 2012 historic market electricity prices and installed generation 

capacity. It has been used to analyse the future profitability of assets in the UK energy-only market, the 

resulting impact on profitability of individual plants and the effects on the main energy and climate 

objectives. In the first sensitivity analysis the impacts of variations in market parameters were analysed 

in order to understand where the largest market sensitivities lie (Sections 6.3 and 6.4). In step 2 of the 

quantitative assessment (section 6.5) the value of ancillary services was added, resulting in an updated 

impact assessment and therewith determine the potential risks to the system in terms of system 

adequacy and capacity adequacy. In the third step further sensitivity analysis was conducted to 

determine how the results of the first auction for capacity availability could mitigate such risks (Section 

6.6). In the following sections we analyse the impact of carbon price increases (Section 6.7), expansion 

of interconnection capacity (Section 6.8) and the impact of electricity storage and demand-side 

management (Section 6.9). Finally, Section 6.10 draws conclusions on the analysis of the UK electricity 

market. 

The short-run marginal cost dispatching that is assumed in the model is determined by total variable 

costs, which consist of fuel costs, CO2 costs and other variable operating costs. The SRMC does not 

consider the costs of capital repayment. The plants with low variable costs are therefore “lower” in the 

merit order and are dispatched before plants with higher variable costs. Figure 12 on the following page 

shows that the variable costs are generally high for fossil-based power plants (gas, coal) and low for 

nuclear and capital-intensive renewable plants, such as onshore wind and (especially) offshore wind. The 

capital repayments must be recovered by the margin between plant variable costs and SRMC prices. 

Fixed operating costs (OPEX) of existing gas plants (‘Gas – old’) have a strong impact on their annual 

generation costs, as these plants operate for few hours. 

The figure illustrates that under today's capacity mix and cost assumptions, and assuming only revenues 

from the energy-only market and price formation only on wholesale markets, gas is the most costly 

means to produce electricity in existing plants, with wind and nuclear being the cheapest. On the other 

hand, if investments were also considered, then gas would be the cheapest option and nuclear and wind 

the most expensive. 

Interactions between electricity market reforms and climate policies 

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Figure 12 » Fixed costs (CAPEX and OPEX) per unit of electricity (€/MWh)  

t
s
o
c
n
o
i
t
a
r
e
n
e
g

l

a
u
n
n
A

140

120

100

h
W
M
/
€

80

60

40

20

0

Capex

Opex

CO2

Fuel

Note: OPEX includes fixed and variable OPEX. Fixed costs (CAPEX and fixed OPEX) per unit of electricity (€/MWh) are 

calculated by the model on the basis of annual costs (€/MW) and baseline modelled annual running hours. The chart 

shows the UK 2010 scenario. 

6.3.1  Illustrating the impact of increased renewable generation on load hours and operating 

profit 

Figure 13 below shows the merit order determined by the model for two scenarios. On the left-hand side 

the figure shows the base case 2010 scenario with 7 GW of renewables on the UK market; on the right-

hand side it shows a sensitivity on the same scenario with 28 GW of renewables (based on the National 
Grid’s 2020 Gone Green scenario, of which 26 GW is wind power).15 Detailed model results are shown in 

Annex 3. 

Figure 13 » Merit order for the UK scenarios  

Note: The chart on the left shows the 2010 base case scenario (7 GW renewables), and the chart on the right shows a 

sensitivity of the same scenario with installed renewable generation according to the Gone Green Scenario (28 GW in 

2020). 

15 Note that when presenting a merit order graph the renewable electricity generation capacity is included by using a 45% aggregate load factor. 
Consequently the MWs shown in the graphs are 45% of the total installed capacity. 

Interactions between electricity market reforms and climate policies 

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A comparison of the two merit orders, as well as the load hours shown in Figure 14 shows that, all other 

parameters being equal, the steep increase in the share of renewable electricity production significantly 

reduces the load hours of other production plants and lowers the wholesale price. The average SRMC 

price (volume-weighted price) drops from 52 to 48 €/MWh, with peak prices dropping much less from 62 

to 61 €/MWh, because meeting peak demand still requires the same plants. 

Figure 14 » Load hours per type of plant for the UK scenarios  

Note: the chart on the left shows the 2010 scenario (7 GW; the current amount of renewables in the UK); the chart on 

the right shows a sensitivity of the same scenario with installed renewable generation according to the Gone Green 

Scenario (28 GW of renewables in 2020). 

6.3.2  Impact on plant profitability, excluding RES incentives 

In the illustration above, average coal load hours reduce from 72% to 68% and average gas load hours 

reduce from 89% to 49%. This has significant impacts on plant profitability, as is illustrated in Figure 15. 

on the following page. Profitability of the fossil fuel plants is strongly impacted by the reduced run hours 

as well as lower wholesale prices. The profitability of nuclear and renewables is also reduced due to lower 

prices but the reduction is less since their operating hours remain (almost) constant. Note that Figure 15 

CfD payments, which would protect wind and solar projects from market prices falling below the strike 

price. 

Interactions between electricity market reforms and climate policies 

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Figure 15 » Profitability of plant types for the UK scenarios  

Note: the chart on the left shows the 2010 baseline scenario (7 GW of renewables); the chart on the right shows a 

sensitivity of the same scenario with installed renewable generation according to the Gone Green Scenario (28 GW in 

2020).  

The model results show that the already difficult economic situation for gas-fired power plants is further 

worsened. The results also show that the operation of most coal-fired power plants will no longer be 

profitable under current conditions assuming RES as expected in the 2020 Gone Green scenario. In this 

case, there is a large variation in the profitability of various coal and gas plants as a result of increasing 

amounts of renewable production. The size of impact largely depends on the actual efficiency of the types 

of plants. In practice this situation will likely lead to closure of the most inefficient plants, which would 

push up the average efficiency and load hours of the remaining fleet and, as a result, their profitability. 

6.3.3  Analysing future UK market developments  

Whereas in the previous section we analysed only the impacts of an increasing share of renewable 

capacity (as included in the Gone Green scenario), we now focus on a combination of expected future 

developments, as included in the 2013 EU Reference scenario for the UK for the years 2020 and 2030. 

The scenario projects an increase in the amount of renewable generation capacities (note that the 2020 

RES capacity in the EU reference scenario is different from the illustrative assumption used in the 

previous sections), decommissioning of older gas and coal fired plants, and installation of a number of 

new CCGTs. Overall energy prices increase significantly, and the carbon price also increases. 

The UK 2020 scenario requires significant investments in gas-fired plants and even much more in new 

on- and off- shore wind power capacity. The total capacity needs in the period 2010-2030 is shown in 

Table 8. 

Interactions between electricity market reforms and climate policies 

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Table 8 » New investments and decommissioning by plant type on the UK market 

Data in GW 

2010-2020 

2020-2030 

New investments 

Decommissioning 

Plant type 

New investments 

Plant type 

CCGT 

Gas CHP 

7 

4 

Wind onshore 

14.4 

Wind offshore 

Solar PV 

Coal 

Coal CCS 

Biomass 

Nuclear 

19 

6 

- 

0.5 

0.75 

- 

Source: EU Reference scenario 2013 – UK data. 

2 

2 

- 

- 

- 

17 

- 

- 

- 

CCGT 

Gas CHP 

7 

4 

Wind onshore 

14.4 

Wind offshore 

Solar PV 

Coal 

Coal CCS 

Biomass 

Nuclear 

19 

6 

- 

0.5 

0.75 

- 

Figure 16 on the following page shows the development of profitability levels for different plant types 

from 2010 to 2020 and 2030, both excluding and including capital repayments. The 2010 results confirm 

that, with current capacity, and prices for fuel and carbon, profitability is challenging for gas plants, while 

for new investment without subsidies neither gas nor renewables are seen as profitable. 

The key driver for changes in operating profit between 2010 and 2020 are the underlying fuel prices, 

which increase, while the CO2 price decreases slightly. Higher fuel prices result in higher electricity prices 

in 2020, especially for periods of high demand when more inefficient older plants or peaking plants are 

required to meet demand. The higher electricity prices lead to higher operating profits for all plants, 

except for old gas plants and peaking plants. In particular, the profitability of coal plants (with a high load 

factor), must-run plants (nuclear, CHPs and biomass) and price-taking renewable plants (solar and wind) 

increases significantly. The increase in operating profit of gas plants is very limited, even for new gas 

plants. Older gas-fired plants continue to make losses, which indicates the risk that these plants would be 

mothballed or decommissioned. Coal is significantly more profitable than gas, which provides the risk that 

these plants would stay on the market rather than being replaced by new gas capacity for flexibility. 

The key driver for changes in operating profit between 2020 and 2030 is the projected increase in the 

CO2 price. This almost halves the operating profit of coal plants in 2030 compared to 2020, while the 

operating profit for the most efficient gas plants almost doubles. 

The combined effect of these assumed developments is a low amount of the load hours of older gas 

plants from 2010 to 2030, while the load hours for the remaining coal plants and newer gas plants 

increases throughout. 

Interactions between electricity market reforms and climate policies 

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Figure 16 » Profitability of plant types in 2010 (top), 2020 (middle) and 2030 (bottom), excluding capital repayments 

(left) and including capital repayments (right), both excluding RES support schemes    

When adding capital repayments the model results in Figure 16 show that the market may not provide 

sufficient incentives for new investments in gas-fired capacity (based on their annualised profitability) in 

the base year 2010 nor in 2020. In 2030, however, investments in new efficient gas-fired capacity are 

profitable, driven by the increase in fuel and CO2 prices. Investments in new coal plants are not shown 

since these are de-facto blocked from the market as a result of the new Emissions Performance Standard 

Interactions between electricity market reforms and climate policies 

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(EPS) which is part of the UK Energy Market Reform, but new coal would also not be profitable at the 
presumed 2030 market conditions.16  

The model does not include Feed-In-Tariffs, CfDs or previous incentives for renewable energy. As such, 

the model reveals that in the year 2020 onshore wind is almost profitable without subsidy due to the 

higher wholesale market prices. Offshore wind still requires additional support and biomass plants and 

solar electricity are also not profitable without subsidies. This is obviously influenced by relatively low 

wholesale market prices (see Annex 2). The results show that by 2030 new investments in offshore wind 

become profitable, driven by a combination of a high load factor, high electricity prices, and significant 

reductions in the projected capital expenditures. Onshore wind is projected to be close to profitability 

without subsidies, having a lower load factor than offshore wind. Under these scenario assumptions new-

build solar electricity and biomass are not yet profitable in the wholesale market without subsidies. 

It should be noted that these results show only the revenues from the sales of electricity on the 

wholesale market. Revenues from balancing markets and ancillary services have not yet been included in 

this analysis, which leads to an underestimation of the profitability of the various plants types. The 

difference is particularly important for the mid-merit plants that remain crucial players in the balancing 

market and offer various types of ancillary services. The impacts of additional revenues from ancillary 

services are presented in Section 6.5. As explained in Section 5.2.2, a further underestimation is due to 

the use of short-run marginal cost pricing which does not capture scarcity pricing above the short-run 

marginal costs. 

In a further sensitivity analyses the Carbon Floor Price (CFP) is taken into account. The CFP, which has 

been in effect in the UK since April 2013, increases the investment incentives for gas, nuclear and 

renewable generation, compared to coal. The impact on the modelling results is relatively small. The 

current floor price of £18/ton CO2 (€24/ton CO2 at exchange rate of 1.35 €/£) still results in coal plants 

being significantly more profitable than gas plants in 2020. Only a CFP approaching £30/ton CO2 (€41/ton 

CO2) would make gas and coal plants equally profitable and therefore trigger a switch between 

operational coal and gas plants in the mid-merit range. 

The impacts at current prices, as determined by the model, include: 

 

The Carbon Floor Price results in a strong increase in revenues for renewable generation. The 

main driver of this is the increase in electricity price, resulting from the higher CO2 prices.  

  Based on the current Carbon Floor Price, the running hours of different types of plants are not 

strongly affected. Consequently there is little change in direct CO2 emissions.  

Figure 17 shows the clean spreads and load hours for different plant types in 2010, 2020 and 2030 

(based on wholesale market modelling). The iso-lines show combinations of clean spread and load hours 

at which the different plant types are profitable (solid includes capex, dotted excludes capex). The figure 

visualises the profitability trends discussed before. 

The UK 2020 scenario analysed includes decommissioning of approximately 20 GW of coal plants. This is 

included in the model calculations. Decommissioning of gas plants is negligible. The possible capacity 

16 The EPS is defined as an annual limit on carbon emissions from new and refurbished fossil fuel plants, limiting annual average emissions to 
450g CO2/kWh at base-load capacity. Coal plants without CCS would not be able to meet that limit. 

Interactions between electricity market reforms and climate policies 

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adequacy risk resonates with the UK market reform debate on additional incentives to keep mid-merit 

capacity in place. If this would result in some of the coal plants that are to be decommissioned to prolong 

their lifetime that would have a significant negative impact on the speed of decarbonisation of the UK 

power sector. 

Note again that revenues from ancillary services and balancing and from scarcity pricing are not included 

in the model calculations, so the actual situation will be less negative than shown in the figure. 

Interactions between electricity market reforms and climate policies 

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Figure 17 » Plant profitability requirements: typical plant requirements (iso-lines) and typical market conditions in different years.  

2030 

Old gas 

2020 

2010 

Interactions between electricity market reforms and climate policies 

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6.4 

Further sensitivity analysis 

In the further sensitivity analyses we analyse the impact of variations in model assumptions for the fuel 

prices and for variation in electricity demand. 

6.4.1  Lower amounts of investment and divestment  

In a sensitivity analysis we assume a generation mix for the year 2020 that more closely follows today’s 

generation mix. In other words, only part of the projected investment and decommissioning is carried 

out. We assume that half of the 18 GW projected coal decommissioning is not decommissioned and none 

of the projected 7 GW CCGT investments are taken up. This scenario has large impacts for projected CO2 

emissions from the power sector, resulting in 22% higher CO2 emissions than in the baseline scenario for 

the year 2020. The resulting wholesale electricity prices are approximately 9% lower. 

6.4.2  Sensitivity to fuel price variations 

Higher gas prices lead to higher electricity prices because the marginal cost of generation increases. The 

electricity price increase is especially high at times of high demand, when older plants with low efficiency 

are dispatched. The higher electricity prices in turn result in higher profitability for all producers, 

regardless of plant type. This effect also occurs when coal prices increase at the same time, at a 

comparable level. The model shows that the impact on load hours of various plant types is small, because 

the order of plants in the merit order is not strongly affected. 

Figure 18 shows (the chart on the left side) that an increase in fuel prices (coal, lignite and gas) and the 

resulting increase in electricity prices result in a large increase in the profitability of renewable generation 

and nuclear, since their revenues increase but these plants do not incur cost increases. When both coal 

and gas prices increase by a similar amount, then coal plant profitability increases more strongly than the 

profitability of (gas-fired) CCGT plants. This is a result of the fact that at hours of high demand the 

increase in the margin of coal plants is much stronger than the increase in the margin of CCGTs, since 

the generation costs of CCGTs are closer to the marginal cost than the generation costs of coal-fired 

plants. In addition, coal plants typically make more running hours, so the electricity price increase adds 

to the plant revenue for more load hours than for CCGT plants. 

Interactions between electricity market reforms and climate policies 

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Figure  18  »    Increase  in  plant  profitability  as  a  response  of  increase  in  fuel  prices  (chart  on  the  left)  or  coal  prices 

(chart on the right), for baseline 2010 scenario assumptions.  

Fuel price increase factor compared to baseline 

Fuel price increase factor compared to baseline 

When gas prices remain constant and only coal prices increase (the chart on the right hand side), the 

profitability of renewable plants again increases, but by much less than the corresponding profitability 

increases that results from higher gas prices. These differences are explained by the merit order effects. 

For small increases in coal prices the SRMC prices show little change as the strike price is still determined 

by gas plants. For larger increases in coal prices the coals plants will move up in the merit order and can 

increase the SRMC price. Also load hours will only see a small variation when the coal price increase is 

small, but a large variation at the moment that coal plants move up in the merit order compared to gas 

plants. 

In the scenario with higher coal prices and constant gas prices, the increase in profitability of renewable 

generation and nuclear increases is less strong than in the previous case with higher coal and gas prices. 

This lower impact is due to the smaller effect on electricity prices. The profitability of coal plants reduces, 

while that of gas plants increases. This is due to the fact that the higher coal prices result in a decrease 

of running hours and margins of coal plants, while the running hours and margins of gas plants increase. 

Table 9 illustrates the expected positive impact of an increase of coal prices to the decarbonisation of the 

power sector. 

Table 9 » Impact of fuel price increase on decarbonisation of the UK power sector 
Share of renewable 
production 

Share of flexible 
gas generation 

CO2 emissions 
(g/kWh) 

CO2 emissions 
(Mton) 

50% fuel price 
increase - gas and 
coal 
50% fuel price 
increase - coal only 

8% 

8% 

27% 

35% 

488 

442 

173 

157 

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6.4.3  Sensitivity to variation in demand 

Assuming the same generation mix, a higher level of electricity demand may result in higher electricity 

prices. This especially holds true at times of high demand (i.e. if peak demand were to increase), where 

there is a larger role for peaking plants with low efficiency in meeting demand. Higher electricity prices 

result in increased profitability of all power plants, as is illustrated in Figure 19. The increase is highest 

for renewable generation, nuclear and base-load coal plants. The profitability increase for mid-merit and 

peaking plants (older coal and gas plants) can be lower than for base-load plants, as the mid-merit and 

peaking plants have lower operating hours and their operating costs are closer to the strike price. 

Figure 19 » Impact of change in electricity demand on profitability of various plant types, for baseline 2010 scenario 

assumptions 

As a result of higher demand levels, the load hours for mid-merit and peaking plants increase, resulting 

in further profitability increases for these types of plants. The system capacity net reserve margin (shown 

in Table 10) decreases, meaning a higher risk of unserved demand. If electricity prices increase to 

significantly high levels, this could trigger investments in additional capacity and then in the longer term 

this additional capacity would mitigate the negative reserve margin impacts. 

Table 10 » Impact of change in electricity demand on system net reserve margin 

Demand factor 

0.8 

Reserve margin (%) 

1.58 

0.9 

1.4 

1.0 

1.1 

1.2 

1.26 

1.15 

1.05 

Table 11 on the following page shows the impact of changes in electricity demand on the decarbonisation 

of the power sector and the share of renewables in total production. The latter only varies with the 

variation in demand since the total volume of renewables remains constant. Higher demand levels 

increase the load hours of flexible gas generation, which results in higher CO2 emissions. With a higher 

share of gas-fired production the average emissions per kWh decrease. 

Interactions between electricity market reforms and climate policies 

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Table 11 » Impact of change in electricity demand on the path to achieving the main climate objectives 

Share of 
renewable 
production 
8% 
9% 
7% 

Baseline case 
90% demand 
110% demand 

Share of flexible 
gas generation 

CO2 emissions 
(g/kWh) 

CO2 emissions 
(Mton) 

27% 
20% 
33% 

488 
492 
483 

173 
157 
189 

6.5 

Ancillary services 

The analysis in the previous sections looks at the revenues from the wholesale market. Power plants can, 

however, obtain significant additional revenues from ancillary services, which may significantly improve 

their competitive position. 

In the UK the following types of ancillary services are provided: 

  Frequency Response: this includes Mandatory Frequency Response, Firm Frequency Response 

and Frequency Control by Demand Management; 

  Reserves: Fast Reserve, Short Term Operating Reserve (STOR), BM Start-up, Fast Start and 

STOR Runway; 

  System Security Services: Transmission Constraint Management, Contingency Balancing 

Reserve, Maximum Generation, Intertrip Services, Black Start and SO to SO17; 

  Reactive Power: Obligatory Reactive Power Services and Enhanced Reactive Power Services. 

Most of these ancillary services are provided by suppliers and therefore provide an additional source of 

revenue for the production units. This includes all of the above ancillary services, with the exception of 

Frequency Control by Demand Management, Short Term Operating Reserve Runway, and SO to SO. Black 

start services are only provided by dedicated units and are consequently also not included in the further 

analysis. The detailed modelling assumptions on the revenues from ancillary services per plant type and 

per type of service are included in Annex 2. 

Figure 20 shows the impact of ancillary services revenue on the profitability of different plant types. It 

should be noted that the revenue estimates shown are determined for average plant types, whereas in 

practice revenue estimates will be different for each plant. 

The Figure shows that plant profitability for the more efficient gas plants increases to €20,000/MW. 

Consequently, the additional ancillary services revenues may be sufficient to keep these existing plants in 

the market. For less efficient plants used for peaking, however, this is less likely to be the case. The plant 

profitability of existing coal plants increases too, but with less of an increase than for efficient gas plants. 

Whereas the additional revenue from ancillary services may contribute to keeping existing capacity in the 

market, it is not sufficient to make new investments possible, with earnings after payment of capital 

costs still negative. This conclusion not only holds for peaking plants, but also for investments in new gas 

or coal plants. 

Note 4 »  System Operator to System Operator Services are provided by the transmission system operators via interconnectors. 

Interactions between electricity market reforms and climate policies 

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Figure 20 » Impact of ancillary services revenue on the profitability of different plant types (ancillary services data: 
based on 2013 National Grid data) 

6.6 

Impacts from the market reform 

The first capacity auction that was held in December 2014 resulted in a clearing price of £19.4/kW/year, 

which is approximately €25,000/MW/yr. When adding this revenue to the fraction of installed capacity of 

each plant type that is awarded a capacity contract we conclude that this is similar to the average 

revenue gap that peaking plants are facing on the market. Consequently, the auction clearing price would 

be sufficient to keep some of the peaking capacity in the market, as is illustrated in Figure 21. The 

auction clearing price is far from sufficient to trigger new investments in coal-fired capacity, so in that 

respect the UK capacity market would not risk bringing new coal-fired capacity on stream (even without 

the EPS), which would go against the objective of decarbonisation of the power sector. The auction 

results illustrate this: only 5% of the budget was won by CCGT plants that are yet to be built, whereas 

the majority of the budget will go to existing capacity. 

Figure 21 » Illustrative impact of 2018 capacity market revenue on the profitability of different plant types  

6.7 

Increasing CO2 prices 

As discussed in chapter 2, the EU ETS has not yet resulted in carbon prices at a level that facilitates the 

decarbonisation of the European power sector, as expected in the Energy roadmap 2050. Sufficiently high 

carbon prices would influence operational decisions – i.e. a shift towards low-carbon production units - 

Interactions between electricity market reforms and climate policies 

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and sufficiently high price expectations would impact investment decisions – i.e. limit investments in 

high-carbon production units. To illustrate the extent and impact of such developments we apply the 

model under various price scenarios. Higher CO2 prices impact the profitability of the various plant types 

as carbon prices influence total costs. Higher CO2 prices also increase wholesale prices for electricity and 

can potentially change the order of plants in the merit order. The price impact is especially large at times 

of high demand when older plants with low efficiency are dispatched. Finally, higher CO2 prices can have 

a strong impact on the load hours of various plants, as the order of plants in the merit order can change 

due to differences in CO2 price exposure. Doubling the CO2 price from €11/tCO2 to €22/tCO2 results in an 

increase in the average short-run marginal cost of the UK electricity market from €53/MWh to €58/MWh. 

The impact on load hours is very small; the average load hours of existing gas plants increases by 2%, at 

the expense of existing coal plants. 

Figure 22 » Impact of CO2 price increases on profitability of various plant types (2010 baseline) 

Note: these calculations assume fixed generation capacities and exclude RES subsidies.  

A further increase in CO2 prices has a more significant impact on the UK electricity market. An increase 

from €11/tCO2 to €34/tCO2 shows (see Figure 23) a clear switch in the position of coal plants and 

efficient CCGTs in the merit order with the average load hours of coal plants dropping from 67% to 58%. 

Consequently the average load hours for gas plants strongly improve (from 58% to 71%) and the 

profitability of switching gas plants increases, while coal plant profitability decreases. Profitability of 

renewable generation and nuclear electricity increases strongly, due to increasing electricity revenue and 

no increase in costs (as these plants have no CO2 emissions and therefore do not depend on the CO2 

price). With high CO2 prices resulting in gas production pushing out some of the coal production the path 

towards decarbonisation of the power sector is positively influenced, as is illustrated in Table 12 on the 

following page. 

Interactions between electricity market reforms and climate policies 

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Figure 23 » Impact of CO2 price increase from 11 €/tCO2 to 34 €/tCO2 on the merit order 

Table 12 » Impact of CO2 price changes on UK power sector emissions 

CO2 price 
(€/ton) 

11.2 
33.6 

Share of 
renewable 
production 
8% 
8% 

Share of flexible 
gas generation 

CO2 emissions 
(g/kWh) 

CO2 emissions 
(Mton) 

27% 
33% 

488 
455 

173 
162 

Note: installed capacities (including RES and nuclear) are kept fixed according to the scenario 

6.8 

Expanding interconnection capacity 

Changes in interconnection capacity, the level of electricity storage capacity and demand response 

measures can all impact the level or the shape of either the gross demand curve or the net demand for 

residual capacity. Such changes can reduce the system need for generation capacity to meet peak 

demands, but impacts on plant profitability are not straightforward. Changes in interconnection capacity 

are analysed in this section; the following section includes an analysis of changes in electricity storage 

and demand response. 

The UK electricity market currently has 4GW of interconnector capacity (OFGEM, 2015):  

  2 GW to France; 

  1 GW to the Netherlands; 

  0.5 GW to Northern Ireland; 

  0.5 GW to the Republic of Ireland. 

The following expansion to this interconnection capacity is planned (EC, 2013c): 

  A new DC interconnection of 1 GW capacity between Richborough (UK) and Zeebrugge (Belgium); 

  A HVDC interconnection between Cotentin (FR) and the vicinity of Exeter (UK), via the island of 

Alderney, with a capacity between 1 GW and 1.4 GW; 

  A new DC interconnection of 1 GW between Coquelles (FR) and Folkestone (UK), via the Channel 

Tunnel; 

  A new HVDC interconnection with a capacity of 1.4 GW between Norway and the UK; 

  A HVDC underground cable interconnection with a capacity of 1.2 GW between Ireland and the 

UK. 

Interactions between electricity market reforms and climate policies 

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Increases in interconnection capacity can result in a higher net import volume, which may lower the 

residual demand for domestic capacity. With a continued dispatch priority for renewables, this in the end 

reduces the residual demand for non-renewable capacity.  

Figure 24 illustrates the expected impact of an additional 3.9 GW interconnection capacity on the UK 
demand curve, comparing the expected capacity in the National Grid 2020 Gone Green projection18 with 

the larger expected capacity for 2020 in the European “Projects of common interest”. The demand curve 

shown is based on the historic interconnector flows for the year 2012, and includes the BritNed cable. 

Figure 24 » Illustrative impact of changes in UK interconnection capacity on the UK demand curve 

Table 13 on the following page lists the impacts of increased interconnectivity on peak demand, the 

average electricity price and the profitability and load hours of four types of production plants. The 

modelling results show that the assumed 3.9 GW of additional interconnection capacity results in a 

decrease in the average daily peak (-1.7 GW). Since electricity prices in the UK generally are higher than 

on the European continent, the UK is a net importer of electricity. As a result of increased interconnection 

capacity these imports increase, resulting in a decrease of the SRMC price of €1/MWh and reduced 

amounts of operating hours for domestic production capacity. Consequently the expansion of 

interconnection capacity results in a net reduction of revenue for domestic producers, but potentially also 

lower generation capacity requirements. Increased interconnection for the UK effectively reduces 

generation as well as the residual load and therefore total CO2 emissions in the UK. The overall CO2 

impact depends on the CO2 intensity of the imported electricity compared to the CO2 intensity of 

electricity generated in the UK. 

For the countries exporting electricity to the UK, the impacts will be the opposite, i.e. increases in prices 

and generation levels. 

18 National Grid Future Energy Scenarios 2014. 

Interactions between electricity market reforms and climate policies 

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Table 13 » Impacts of an increase in interconnection capacity, based on 2010 baseline  

Interconnection 
capacity (3.9 GW) 

Average daily peak (GW) 

Average SRMC price

(€/MWh) 

Wind onshore 

Profitability (€/MW/year) 

Average CCGT 

Load hours  

Profitability (€/MW/year) 

Efficient CCGT 

Load hours  

Profitability (€/MW/year) 

Coal 

Load hours  

Profitability (€/MW/year) 

-1.7 

-1 

-2591 1) 

-13.4%  

-4420 

-6.6% 

-8711 

-1.5% 

-7723 

1)  The high reduction of wind profitability is mainly an artefact of the interconnector analysis based on the 2012 

profile instead of the 2010 profile. 

6.9 

Electricity storage and demand response 

Increases in storage capacity and increased demand response could be used to ‘flatten’ the demand 

curve: part of the peak hour demand is shifted to off-peak hours. 

Detailed modelling of increased storage capacity or demand response is beyond the scope of the tailor-

made model developed for this study, but first order estimates can be made. In general there are three 

main aspects to consider: 

1.  Where storage capacity and/or demand response are used to provide ancillary services they can 

reduce CO2 emissions (prevent thermal plant start-ups & part load operation);  

2.  When storage capacity and/or demand response are used to shift demand from peak to off-peak, 

CO2 emissions could increase if the shifted demand is met by coal instead of gas;  

3.  Use of storage capacity and/or demand response may also reduce the need for thermal backup 

capacity. 

Figure 25 shows the expected impact of 2 GW/7 GWh additional storage capacity (chart on the left-hand 

side) and of 3 GW demand response capacity (chart on the right-hand side). These amounts are typical in 
the 2020 projections included in several system studies19 (for capacity storage) and in the Gone Green 
scenario (for demand response).20 

19 For example Strbac, 2012, Institute of Energy Economics University of Cologne, 2012 and LUX research, 2012. These assume a storage 
capacity of 7 GWh. 
20 The Gone Green scenario defines a demand response for 2020 of 6.7% of peak demand. In the model a static implementation was used in 
which demand is reduced in a pre-defined window if it rises above the start value, and is shifted to a later time window. 

Interactions between electricity market reforms and climate policies 

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Figure 25 » Illustrative impact of change in electricity storage capacity (left) and demand response (right) on the 
UK demand curve 

Table 14 lists the impacts of increased storage capacity and increased demand response on peak 

demand, the average electricity price and the profitability and load hours of four types of production 

plants. The reduction of both the average SRMC price and the amount of load hours reduces the 

profitability of conventional plants. To allow for comparison across flexibility options the results for 

expansion of interconnection capacity are added to the table again. 

Table 14 » Impacts of an increase in interconnection capacity, storage capacity or demand response  

Interconnection 
capacity (3.9GW) 

Storage capacity 
(2GW) 

Demand response 
(3GW) 

Average daily peak (GW) 

Average SRMC price

(€/MWh) 

Wind onshore 

Profitability 
(€/MW/year) 

Average CCGT 

Load hours  

Profitability 
(€/MW/year) 

Efficient CCGT 

Load hours  

Profitability 
(€/MW/year) 

Coal 

Load hours  

Profitability 
(€/MW/year) 

-1.7 

-1 

-2591 1) 

-13.4% 

-4420 

-6.6% 

-8711 

-1.5% 

-7723 

-1.2 

-0.2 

60,3 

0.3% 

-1238.4 

1.4% 

-684.4 

0.7% 

-32.5 

-1.1 

-0.05 

55,2 

0.6% 

-350.2 

0.5% 

-20.1 

0.1% 

81.5 

1)  The high reduction of wind profitability interconnection compared to storage and demand response is mainly an 

artefact of the interconnector analysis based on the 2012 profile instead of the 2010 profile. 

The degree to which these flexibility options are able to reduce peak demand (and therefore avoid having 

to use peaking plant capacity) depends on the detailed implementation of the flexibility option. All options 

Interactions between electricity market reforms and climate policies 

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reduce the average daily peak, but in the illustrated case of expanding interconnection capacity the total 

peak demand increases. This is a direct result of using the historic interconnection use profile in the 

modelling analysis. When zooming into peak generation needs we observe that on 95% of days the 

increased interconnection reduces the peak generation requirement. 

With respect to achieving key climate change objectives the main function of storage and demand 

response is to enable the penetration of higher amounts of renewable energy. The direct CO2 impact of 

storage and demand response is very limited and can go either way depending on the merit order effects. 

6.10  Concluding remarks 

Decarbonisation of the power sector based on the full range of low-carbon technologies available is one of 

the key elements of the UK's climate policies. At the same time, a large electricity market reform which 

introduces a capacity market as a key new element, has been set in motion. The analysis of the UK 

power market confirms that existing mid-merit plants are facing difficult times in the UK power market. 

In a wholesale market with price formation generated through the merit order, operating profits for 

existing plants other than gas-fired capacity are sufficient to keep them in the market but insufficient to 

recover capital costs (with the exception of nuclear capacity). Keeping all other things equal, the situation 

of mid-merit plants deteriorates if renewables are increased and hence running hours of non-renewable 

plants and wholesale prices decrease. 

The current market conditions clearly raise questions regarding capacity adequacy if operators would 

decide to take part of their capacity out of the market (or to not invest in replacement capacity if a large 

share of decommissioning of coal takes place). The modelling suggests that new gas plants do not 

sufficiently recover their annualised investment costs on the wholesale market in 2010 and 2020. On the 

other hand a number of counter-balancing elements come forward from the modelling. Fuel price 

increases as well as carbon price increases raise profitability. This also indicates that expectations matter 

for investments, an element which is only reflected to a limited extent in the modelling. 

The analysis also shows that higher carbon prices can already bring about a fuel switch on the UK market 

at present. At prices of €22/tCO2 the model shows some shift in load hours from coal-fired to gas-fired 

production. At prices of €34/tCO2 the shift is quite significant. This evidently results in higher profitability 

for gas-fired plants, which may have a positive impact on system adequacy. The overall system impact is 

greater, since other low-carbon and carbon-free electricity generation profits from higher wholesale 

prices. 

Accounting for ancillary services is quite important for both mid-merit and peaking plants operating under 

current market conditions, but total revenues from wholesale markets and balancing markets are not yet 

enough to make new investments in mid-merit and peaking plants profitable. The recent capacity auction 

resulted in a clearing price that is just enough to make up for this difference under today’s market 

conditions. The analysis also shows that new investments in coal-fired capacity in the UK market are very 

unlikely. With much greater capital costs, total revenues including capacity payments for coal-fired plants 

are insufficient to trigger new investments. The EPS de-facto also excludes new coal plants, since new 

Interactions between electricity market reforms and climate policies 

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coal production could only enter the market with CCS or biomass co-firing, which is not profitable under 

the modelled trend scenario conditions. 

Increases in interconnectivity, storage capacity and demand response can lower average daily peak 

demand and therefore lower average SRMC prices and the amount of load hours for conventional plants, 

while decreasing the need for peak capacity and hence for new supply investments. Storage capacity and 

demand response have lower negative impacts on profitability and the impacts are relatively small 

compared to other changes in the system. The direct CO2 impact of increased interconnectivity, storage 

and demand response is very limited and can go either way depending on the merit order effects. 

As in all modelling, the results should be treated with caution. The modelling results seem consistent over 

various sensitivity cases, but not all combinations of possible market evolutions have been assessed. For 

instance the modelling as such did not combine impacts of revenues from ancillary services, scarcity 

pricing and increasing carbon prices, or assess a combination of increased flexibilities and increasing 

carbon prices. 

In Chapter 5 we have discussed the functioning of the model and its limitations, specifically identifying 

the underestimation of plant revenues. In particular mid-merit and peaking plants could secure scarcity 

rents at times of high demand and low intermittent supply. A comparison of model results with historic 

price developments shows that this underestimation of revenues can be up to 17% of plant revenues, 

which may make the situation for mid-merit and peaking plants slightly less negative than the model 

results suggest. 

Interactions between electricity market reforms and climate policies 

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7 » Analysing the German electricity market 

This chapter contains an analysis of the electricity market in Germany, focusing on the relation between 

the fast increase of renewable electricity production, the proposed electricity market reforms and further 

discussions on the possible introduction of a capacity market, the operating profitability of the entire 

electricity system, and specifically the operating profitability of mid-merit generation capacity. The 

German situation is characterised by a renewable energy focused decarbonisation strategy and the 

interconnectivity of the German grid with other Member States. 

The chapter starts (Section 7.1) with a summary of the current electricity market situation in Germany 

and the main drivers of the electricity market reform. Sections 7.2 to 7.4 provide a quantitative analysis 

of the implications of different drivers on the German electricity market: increasing fuel prices and 

demand variation (Section 7.2), increase in carbon prices (Section 7.3) and an increasing share of 

renewables (section 7.4). The impacts on load hours and profitability of various plant types are assessed 

under these different conditions. In Section 7.5 we show that the additional revenues from ancillary 

services markets and sales of heat are significant. 

Following the challenges presented, we provide an overview of the recent and current discussions on 

reform of the German electricity market in Section 7.6. Sections 7.7 and 7.8 concentrate on the impact of 

introducing further flexibility on the German market by means of increased interconnection capacity, 

electricity storage and demand response. Finally in Section 7.9 we provide conclusions on the German 

electricity market. 

7.1 

The current market situation  

Recent projections show that Germany will fall short of reaching its goal to reduce its greenhouse gas 

emissions by 40% in the period 1990-2020. This target includes the emission reductions in the EU ETS. 

The Environment Ministry estimates that the shortfall will be 5 to 8 percentage points. The ambitious 

target and the shortfall discussion frequently trigger discussions about additional climate policies. 

In December 2014 the German cabinet adopted the Climate Action Programme 2020 to address this 

shortfall. The plan requires 78 million tonnes of greenhouse gas reductions of which 22 million tonnes 
must come from the power sector.21  

As part of its efforts to decarbonise power, the German government has also set a target of 80% of 

electricity production to come from renewable energy by 2050, which in the interim requires 35% of 

electricity generation to come from renewable sources by 2020 and 50% by 2030. 

Germany has experienced a strong growth in the production of electricity from intermittent renewable 

energy sources. This has led to the situation that on days with good wind conditions and a lot of sunshine 

solar and wind power account for over 60% of electricity production in Germany, there is a very low 

21 BMU, 2015: Minister Hendricks: Germany will reach its climate goal, press release from the German Ministry for the Environment, Nature 
Conservation, Building and Nuclear Safety, 3 December 2014 

Interactions between electricity market reforms and climate policies 

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dispatch for fossil fuelled power stations and sometimes even negative hourly prices in the whole Central 

West European Region (EC, 2013b). This is negatively impacting the profitability of fossil fuelled 

conventional power plants, especially for gas-fired capacity. Various companies have consequently 

announced plans to close large amounts of capacity. Moreover, plans for investments in new conventional 

power plants have been postponed or eliminated. These developments, combined with the decision to 

phase out 20,000 MW of nuclear energy by 2022 (“Atomausstieg”) and a further increase of 

(intermittent) renewable energy sources has triggered the discussion on EMRs to secure short and long-

term security of electricity supply in Germany. 

7.1.1  System adequacy on the German market 

Despite the high share of renewable electricity to date only a small number of issues related to system 

adequacy has occurred. This relatively stable situation is strongly influenced by the following 

circumstances and actions taken: 

1.  Germany’s power grid is one of the most reliable grids in Europe (CEER, 2015).22 The regulator 

has actively analysed grid strengthening needs to incorporate further growth of renewables. 

2.  The German portfolio of plants is quite diverse, with a large amount of plants that can operate in 

a flexible mode. Besides the traditional flex-power of gas and hydropower plants this includes a 

high share of nuclear plants and coal-fired plants that can provide some (limited) flexibility.  

3.  The lower marginal costs of renewables have pushed down wholesale market prices, which have 

increased the opportunities for electricity exports. Strengthening interconnection capacity has 

improved export opportunities. 

4.  Design and operation of ancillary markets have been improved to facilitate improved balancing. 

5.  Improved weather forecasting has improved the predictability of intermittent production. 

6.  Better system control software has improved system operation. 
7.  Solving the “50.2 hertz inverter problem”23 whereby the challenge of balancing the frequency of 

the system is made more difficult by significant deployment of distributed solar power, and the 

risks of system instability become greater. 

To facilitate the German Energiewende, further actions are being considered. A combination of further 

growth of renewables, falling electricity demand as a result of energy efficiency policy, the potential 

closing of capacity and the relative lack of new investment in baseload and dispatch-ready capacity in 
Germany24 is leading to increased worries about the balancing adequacy as well as the capacity adequacy 

of the German power system. 

Consequently Germany is considering various options for ensuring its security of supply, including the 

introduction of Capacity Remuneration Mechanisms (for further details see Section 7.5). Other options 

considered include: 

Note 5 »  22 CEER (2015): CEER Benchmarking Report 5.2 on the Continuity of Electricity Supply, Report C14-EQS-62-03, 12 February 2015 
Note 6 »  23 VDE (2015): http://www.vde.com/en/fnn/pages/50-2-hz.aspx 
24 Since 2010, intermittent capacity from wind and solar has increased significantly with solar capacity increasing from 18GW to 38GW and wind 
capacity increasing from 27GW to 35GW. However, capacity of base-load and mid-merit plants have been reduced, with 9.5GW less nuclear 
capacity, a small reduction in lignite capacity and a fall in hard coal capacity from 30GW to 28GW. There was a net increase in gas capacity of 
around 4.6GW between 2010 and 2014. 

Interactions between electricity market reforms and climate policies 

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 

 

Increased interconnection capacity and improvement of inland infrastructure. 

Improving overall energy efficiency by 20% in 2020 and by 50% in 2050; specific targets are set 

for the building sector (-80% in the period 2030-2050). This includes a policy package to support 

achieving these targets. 

 

Increased demand-side response is analysed as an option but current policies will not achieve 

such increases.   

  Since the 1st of May, 2014 storage of electricity is financially supported, though support for the 

purchase of solar storage systems. 

  A further restructuring of the renewable energy policy framework. 

7.1.2  Capacity mix and the changes in load hours 

On a sunny and windy day, wind and solar capacity can provide for over 60% of Germany’s electricity On 

a sunny and windy day, wind and solar capacity can provide for over 60% of Germany’s electricity 

production. The share of renewable electricity production, especially that of intermittent production, has 

been increasing steadily in recent years this remains the case, as is illustrated in Figure 26 below. As a 

result, the load hours of non-renewable electricity production continues to decrease. This is increasing 

the missing money problem for the fossil fuelled production capacity, as was already illustrated in Figure 

6, and which is consequently feeding the debate on the necessity of a capacity market. 

Figure 26 » Change in electricity production first eight months 2014 versus first eleven months 2013.  

Source: Burger, 2014b. 

Figure 27 illustrates the merit order as generated by the model with an average share of renewables over 

the year. In the actual model calculations the solar and wind energy profiles are modelled on an hourly 

basis, taking into account regional solar irradiance profiles and hourly wind profiles based on data from 

TSOs in West Europe. In Germany the average load factor of solar electricity is 7.3%, the average load 

factor of onshore wind is 16.5% and the average load factor for wind offshore is 36.2%. 

Interactions between electricity market reforms and climate policies 

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Figure 27 » Merit order for the German electricity market, 2010 scenario, with RES generation equivalent to 
average load factor 

RES @average 

load factor 

7.2 

Sensitivity Analysis 

In a first sensitivity analysis we analyse the impact of fuel price variations and variation in electricity 

demand compared to the 2010 market. The German market analysis graphs show the results for coal plants 

(lignite is excluded from the graphs), the CCGT category comprises newer combined cycle gas turbine 

plants and the gas category represents the older gas plant fleet (fleet characteristics are defined in Annex 

2). 

7.2.1  Sensitivity to fuel price variations 

As in the case for the UK market, we analyse the sensitivity to higher fuel prices in two different ways. In 

the first, we increase the prices of coal, lignite and gas. In the second, we only increase the prices of coal 

and lignite, hence improving the competitive position of gas plants versus the coal and lignite plants. 

Higher fuel prices result in higher electricity prices because the marginal system cost increases. Figure 28 

shows that this results in higher profitability for all producers, regardless of plant type. The increase in 

profitability is highest for plants that do not incur cost price increases, i.e. nuclear plants and renewable 

electricity plants. The increase is obviously higher when all fuel prices increase (chart on the left-hand 

side) than in the scenario where only coal and lignite prices increase (chart on the right-hand side). 

Similar to the impacts on the UK market, the situation with price increases for both coal/lignite and gas 

results in a stronger increase in coal plant profitability than the increase in profitability of the (gas-fired) 

CCGT plants. Again this results from the fact that at hours of high demand the increase in the margin of 

coal plants is much stronger than those for the increase in the margin for CCGTs, since the generation 

costs of CCGTs are closer to the marginal cost than those for coal-fired plants. In addition, coal plants 

typically make more running hours, so the electricity price increase adds to the plant revenue for more 

load hours than for a CCGT. 

Interactions between electricity market reforms and climate policies 

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When gas prices remain constant and only coal and lignite prices increase (the chart on the right hand 

side) a large switch occurs in the merit order. The load hours of gas plants strongly increase and these 

plants push some of the least efficient coal plants out of the merit order. 

Figure 28 » Increase in plant profitability as a result of increase in prices for coal, lignite and gas (chart on the 
left) or for coal and lignite prices (chart on the right)   

Fuel price increase factor compared to baseline 

Fuel price increase factor compared to baseline 

Table 15 illustrates the expected positive impact of an increase in coal prices on the power sector CO2 

emissions (for a constant capacity mix). 

Table 15 » Impact of fuel price increase on emissions related to fuel switching of the German power sector 

Share of renewable 
production 

Share of flexible 
gas generation 

CO2 emissions 
(g/kWh) 

CO2 emissions 
(Mton) 

Baseline scenario 
50% price increase - 
coal only 

18.7% 

18.7% 

8.9% 

15.4% 

491.0 

457.8 

271.4 

253.1 

Note: As modelled in the static dispatch model for a given (constant) power capacity mix. 

7.2.2  Sensitivity to demand variation 

Germany has set ambitious targets for improving energy efficiency and reducing electricity demand. If 

the targets were met this could keep the electricity demand curve flat for the next decade and it would 

reduce the need for new investments in electricity generation capacity. In a sensitivity case we analyse: 

 

 

the impacts of a 10% increase in electricity demand compared to the 2010 data, i.e. energy 

saving policies would be less successful than anticipated; 

a 10% decrease in energy demand, which is closer to the German national projections of even 

stronger success of energy savings policies. 

Interactions between electricity market reforms and climate policies 

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In both cases production capacity is kept constant. Figure 29 shows a similar development for the 

profitability increase of coal, nuclear and gas plants as a function of higher electricity demand. All of 

these plants see their load hours increase and benefit from a higher wholesale market price. The 

profitability increase for wind power plants is lower than for the other plant types since the wind power 

plants only profit 

Figure 29 » Impact of change in electricity demand on profitability of various plant types 

Table 16 shows the impact of changes in electricity demand on the decarbonisation of the power sector 

and the share of renewables in total production. The latter only varies with the variation in demand since 

the total amount of renewables remains constant. Higher demand levels increase the load hours of 

flexible gas generation, which results in higher CO2 emissions. With a higher share of gas-fired production 

the average emissions per kWh decrease. 

Table 16 » Impact of change in electricity demand on the path to achieving the main climate objectives 

Share of 
renewable 
production 

18.7% 
20.8% 
17.0% 

Baseline case 
90% demand 
110% demand 

Share of flexible 
gas generation 

CO2 emissions 
(g/kWh) 

CO2 emissions 
(Mton) 

8.9% 
4.0% 
14.4% 

491.0 
475.8  
498.6  

271.4 
236.7  
303.2  

7.3 

The impact of increasing CO2 prices 

As discussed in Chapter 2 the current prices of carbon on the European market are relatively low and 

have little impact on decisions for operation of existing power plants and investments in new power 

plants. However, analysts expect that the ongoing reform of the EU ETS (introduction of a market 

stability reserve) will increase prices to approximately €20/tCO2 by 2020 (PointCarbon Thomson Reuters, 

Interactions between electricity market reforms and climate policies 

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2014), while the European Commission’s Impact Assessment of the 2030 Climate and Energy 
Framework25 indicates that under conditions of the 2030 framework (40% GHG emission reductions) 

carbon prices of €40/tCO2 could be reached by 2030.  Market expectations about these future prices are 

arguably a more significant determinant of investment decisions than the current market price. 

In the model an increase in CO2 prices results, given a constant capacity mix, leads to an increase in the 

wholesale electricity price. It can potentially also change the merit order of plants. exposure some of the 

older coal plants are pushed out of the merit order by gas plants. 

Figure 30 shows that such a merit order impact occurs at a CO2 price as low as €22/tCO2; due to a higher 

CO2 price exposure some of the older coal plants are pushed out of the merit order by gas plants. 

Figure 30 » Impact of CO2 price increases on profitability of various plant types 

Doubling the CO2 price from €11/tCO2 to €22/tCO2 results in an increase in the average short-run 

marginal cost of the German electricity market from €48/MWh to €52/MWh. A further increase in the CO2 

price to €34/tCO2 results in an average price of €62/MWh. Such a high CO2 price further enhances fuel 

switching in the market: more gas plants are dispatched at the expense of coal plants. Profitability of 

renewable and nuclear plants strongly increases as a result of increasing wholesale electricity prices, but 

the dispatch of these plants is not affected. Higher CO2 prices result in gas production pushing out some 

of the coal production, reducing emissions from the power sector, as is illustrated in Table 17. 

25 http://ec.europa.eu/clima/policies/2030/documentation_en.htm 

Interactions between electricity market reforms and climate policies 

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Table 17 » Impact of CO2 prices on the contribution of fuel switching to the decarbonisation of the German power 
sector 26 

CO2 price 

Share of renewable 

Share of flexible 

CO2 emissions 

CO2 emissions 

(€/ton) 

production 

gas generation 

(g/kWh) 

11.2 

33.6 

18.7% 

18.7%  

8.9% 

12.8% 

491.0  

466.6  

(Mton) 

271.4  

258.0  

7.4  The impact of an increasing share of renewables 

The share of renewables in the German market is expected to continue its steep increase (see section 

7.1). In the modelling calculations an analysis is made of the impact of an increasing share of 

renewables, particularly on the profitability of each plant type and therefore the impact on the system as 

a whole. 

Figure 31 » Load hours per type of plant on the German market 

Note: The charts show the results for the scenarios with a lower share of renewables (49 GW in 2010; chart on the 

left) and a higher share increasing to 103 GW as projected in the EU Reference scenario 2013 for 2020 (chart on the 

right), keeping all other elements equal as in 2010. 

Figure 32 » Profitability of plant types for the German market 

Note 7 »  26 The analysis reflects a changing carbon price’s impact on dispatch for a given capacity mix. We are not modelling the impact of a carbon price on 

investment decisions. 

Interactions between electricity market reforms and climate policies 

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Notes:  1) the charts show the results for the scenarios with a lower share of renewables (49 GW in 2010; chart on 

the left) and a higher share increasing to 103 GW as projected in the EU Reference scenario 2013 for 2020, 

keeping all other elements equal as in 2010 (chart on the right). 

2) Data for nuclear, biomass and gas CHP are only partially shown as they fall out of the profitability range 

shown in the charts.  

Interactions between electricity market reforms and climate policies 

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Figure 33 » Profitability of plant types in the German market including annualised capital and interest 
repayments, but excluding feed-in-tariffs. 

Notes:  1) the charts show the results for the scenarios with a lower share of renewables (49 GW in 2010; chart on 

the left) and a higher share increasing to 103 GW as projected in the EU Reference scenario 2013 for 2020, 

keeping all other elements equal as in 2010 (chart on the right). 

2) the pictures show profitability with capital repayment for expected key technologies in the scenarios. Data 

for lignite are consequently excluded. Data for nuclear, biomass and gas CHP are only partially shown as they 

fall out of the profitability range shown in the charts.  

In the sensitivity with a higher share of renewables the average load hours for gas plants reduces from 

41% to 27%. In combination with the lowering of wholesale prices this strongly decreases the operating 

profitability of gas plants. The average coal load hours increase from 55% to 65%, which increases their 

profitability. The net impact on profitability, however, is still negative, as a result of the large reduction in 

the wholesale electricity price. The profitability of other plants is also reduced due to lower wholesale 

prices but the reduction is less since because operating hours remain constant. 

The model results show that while lignite plants remain profitable the operation of all gas and coal fired 

plants becomes unprofitable under these conditions, both including and excluding capital repayments. 

However, the results for this sensitivity analysis do not take into account that under such conditions some 

of the fossil plants – most likely gas fired plants – will be decommissioned. This will push up the average 

load hours of the remaining plants and therefore their profitability. 

The operating profitability of biomass and gas-CHP plants becomes negative and falls out of the range of 

the chart shown. In other words, these plants are making a loss of more than €100,000/MW/year. 

However, this sensitivity analysis does not include subsidy (feed-in-tariff) revenues to renewables 

(relevant for biomass) nor revenue from heat sales (relevant for gas-CHP plants). 

7.5 

Ancillary services and heat sales 

The targeted share of 80% renewable electricity by 2050 (although not modelled here) will have a large 

impact on the requirements for system adequacy, as well as on the technical and economic options 

available to provide such services. The previous sections analysed the German electricity market based 

on the assumption that plants obtain their income mainly from energy markets. These results provide a 

Interactions between electricity market reforms and climate policies 

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major underestimate of total revenues, since income from ancillary services and heat sales of CHP plants 

have not been taken into account. This section shows that these additional sources are significant, 

especially for the gas-fired production plants. 

7.5.1  Ancillary services offered on the German market 

The four German TSOs are a member of ENTSO-E, the European Network of Transmission System 

Operators for Electricity. Power system control is consequently conducted in line with the rules and 

agreements as agreed within ENTSO-E and as laid down in the UCTE operation handbook. In general 

three types of control power are used, which are called primary control, secondary control and tertiary 

control. 

Table 18 » Types of control power on the continental European market, with reserved capacity indications for 
Germany  

Primary control 

Secondary control 

30 s (100%), direct 
(continuously) 
UCTE  
Frequency deviation 
from 50 Hz (UCTE 
system) 

Based on local 
frequency measurement 

Synchronized 
generators, (industrial 
consumers) 

3000 MW in UCTE (600 
MW in Germany) 

5 min (100%), direct 
(continuously) 
Control area 

Balance of the control 
area 

Activation Centralized 
(TSO); active call 
through IT 
Synchronized 
generators, stand-by 
hydro plants, large 
consumers 
Decided by TSO (2500 
MW in Germany) 

Tertiary control 

(minute reserve) 
7-15 min (100%), 
director schedule 
Control area 
Frequency deviation 
Amount of SC+/- 
activated 
Centralized (TSO); 
active call through 
phone / IT 
Synchronized and fast-
starting standby 
generators, large 
consumers 
Decided by TSO (2500 
MW in Germany) 

Response Time 

System 

Control variable 

Activation 

Typical suppliers 

Reserved capacity 

Source: Hirth, 2013. 

7.5.2  Strong cooperation in balancing operation 

Each of the four German TSOs is responsible for balancing the electricity system in its own service area. 

In May 2010, the four TSOs joined forces to conduct all balancing operations in a single system control 

platform called Grid Control Cooperation (GCC). Subsequently, the TSOs from Austria, Belgium, the 

Czech Republic, Denmark, the Netherlands and Switzerland joined the cooperation, which was renamed 

as the International Grid Control Cooperation (IGCC). ENTSO-E and the participating TSOs frequently 

report on the netted imbalances and the resulting monetary savings resulting from the IGCC. In 

December 2014 ENTSO-E reported a cumulated total value of more than €140 million, as is shown in 

Figure 34 on the following page. 

Interactions between electricity market reforms and climate policies 

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Figure 34 » Cumulated Monetary Value of Netted Imbalances in the International Grid Control Cooperation (IGCC).  

Source: ENTSO-E (2014b). 

7.5.3  Maintaining the strength of the German system 

DENA (2014) has analysed the expected impacts of an increasing share of renewable supply on the 

German power system by 2030 and concluded that: 

1)  Sufficient technical solutions exist to keep the current high level of system security and 

reliability.  

2)  In the future decentralised energy units and operating equipment can and must provide ancillary 
service products at a far higher level, as conventional power plants which primarily meet our 
need for ancillary services today will have far shorter operating hours.  

3)  The requirements for using economically appropriate technical alternatives to provide ancillary 

service products must be created at an early stage and must be discussed as part of the 

Energiewende.  

The actions recommended by DENA were27: 

1)  The regulatory framework must be adapted to ensure that future renewable energy-based 

electricity generation systems, as well as large-scale batteries, are equipped to provide 

instantaneous reserves. 

2)  Changes to the balancing market should be analysed, including:  

a.  Changes to the characteristics of the balancing energy market, such as pre-qualification 

requirements, tender periods and lead times between the tender and provision period, to 

Note 8 »  27 These conclusions and recommendations are taken from DENA (2014). The text was shortened to allow for readability but the conclusions and 

recommendations as such were not altered. 

Interactions between electricity market reforms and climate policies 

 98 

 
 
 
 
allow new providers of balancing energy from decentralised energy units and flexible 

electricity loads to enter the market. 

b.  Developing solutions to permit coordination of increased provision of balancing energy 

via decentralised energy systems. 

c.  Determining the demand for balancing energy in a more dynamic way to allow a daily 

changing dimensioning of the balancing energy demand that results from the higher 

share of intermittent resources. 

3)  Grid connection codes and the technical capabilities of the systems to allow larger 

decentralised energy units should be revised, in particular to provide reactive power whether 

they are feeding active power or not. Furthermore, the option of demand-appropriate transfer of 

reactive power between the high and extra high voltage grid should be reviewed as an 

alternative to building reactive power compensators. 

4)  The existing grid re-establishment concepts based on black start capable conventional power 

plants should be retained and developed. Suitable instruments must be created to enable system 

operators to control the fluctuating generation capacity from renewable energy sources 

appropriately during re-establishment of the grid.  

5)  Coordination and suitable exchanges of information between the TSOs is required to 

allow the increased use of ancillary service products from decentralised energy units. Current 

responsibilities for system operators should remain and the existing cascade principle of passing 

on requirements and information between upstream and downstream system operators must be 

upgraded. In future, the distribution system operators will have additional responsibilities for 

data processing, simulation and management.  

6)  The identification and implementation of future-proof solutions must already start now, in order 

to ensure that they are available reliably by 2030.  

7)  The costs for maintaining and providing ancillary service products must be economically 

bearable. Costs for the system operators must be incorporated suitably in the regulatory 

framework. Costs for the operators of decentralised energy units and flexible loads should be 

covered by a suitable compensation system.  

7.5.4  Revenues from ancillary services  

The analysis in the previous sections looks at the revenues from the energy-only markets and the carbon 

market. Power plants can, however, obtain significant additional revenues from ancillary services, which 

may improve their competitive position substantially. 

In the model the following types of ancillary services are taken into account: 

  Frequency control: primary and secondary balancing power. In Germany also frequency 

dependent load shedding services are provided, but this is not included in the model. 

  Reserve: Minute Reserve. 

  System Security Services: Transmission Constraint Management and voltage regulation. In 

Germany also black start services are provided, but since these are only provided by dedicated 

units they are not included in the model. 

  Reactive Power: provision of reactive power. 

Interactions between electricity market reforms and climate policies 

 99 

 
 
 
 
Most of these ancillary services are provided by suppliers and therefore provide an additional source of 

revenue for production units. The detailed modelling assumptions on the revenues from ancillary services 

per plant type and per type of service are included in Annex 3, Section A3.3. 

Average CCGT frequency response revenues are estimated to be €5,200/MW/year. Currently, the annual 

ancillary service revenue for German power markets is estimated to be around €671m. In practice, 

ancillary service revenues for peaking plants (OCGT) from frequency response are likely to be 

substantially higher, but this is not captured in the available data. Figure 35 shows the impact of 

assumed ancillary services revenue on the profitability of different plant types. It should be noted that 

the revenue estimates shown are determined for average plant types, whereas in practice revenue 

estimates will be different for each plant. 

EBITDA (revenue - operational costs) 
EBITD (EBITD - capital costs) 

Figure 35 » Impact of ancillary services revenue on the profitability of different plant types, 2010 

 25
 60
 20
 40
 15

/

r
y
/
r
W
y
/
M
W
M
s
0
/
0
s
0
0
0
€
0

'

'

€

 20
 10

 5
 -
 -
-20
-5
-40
-10
-60

Peaking
Peaking

Gas
Gas

Coal old
Coal old

Wholesale

Wholesale

Wholesale + Ancillary Services
Wholesale + ancillary

Figure 35 shows that plant profitability for the more efficient gas plants increases by €10,000/MW/year to 

approximately 2,000/MW/year. Consequently, the additional revenues from ancillary services may be 

sufficient to keep these existing plants in the market. For less efficient plants, however, this is not the 

case and consequently there is a risk that some of these plants will be closed. The plant profitability of 

existing coal plants increases to approximately €22,700/MW/year.  

7.5.5  Revenue from heat sales 

The EU Reference scenario 2013 projects that there will be 18GW of CHP electrical capacity in 2010 and 

we estimate that around 4GW of this is power sector CHP, rather than industrial installations. Assuming 

the market price for heat is a mark-up on the gas price, reflecting the efficiency of traditional industrial 

boilers as the main source of heat supply that sets the market price, we estimate an annual revenue of 

around €950m for power sector CHP plants in 2010. Accounting for this, CHP plants in the modelling 

framework are profitable from an operational and investment perspective. 

Interactions between electricity market reforms and climate policies 

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7.6 

Reform of the German electricity market  

In 2012 Germany introduced a temporary measure to prevent operators from closing unprofitable power 

plants that are deemed to be system-relevant and, in 2013, the country adopted the Ordinance on 

Reserve Power Plants, which further specifies the provisions introduced in 2012. The ordinance 

represents a temporary regulation and shall expire in 2017, after which a decision on amendment of the 

regulatory framework for energy, including the Renewable Energy Sources Act (EEG), will be made. The 

ordinance lays downs rules for procuring reserve capacity from existing power plants, storing electricity 

and it provides for an annual review on the need for additional reserve power. In case additional reserve 

power is needed the TSO responsible for the area will publish the technical requirements and conclude 

contracts with interested parties, who are remunerated in accordance with the ordinance. In case new 

capacity is needed the responsible TSO is entitled to procure new reserve power, by issuing an invitation 

to tender. The ordinance further specifies the rules regarding closure of power plants. A shutdown has to 

be notified in case of plants with a capacity of more than 10 MW and can in certain limited cases even be 

prohibited. 

In recent years Germany has analysed various options for the introduction of a capacity mechanism, 

including: 

 

In spring 2012 a study commissioned by the German Federal Ministry of Economics concluded that 

in the long term the energy-only market faces challenges to securing supply. The study 

recommended the introduction of a system of security-of-supply contracts and advised against the 

establishment of a strategic reserve as this would result in inefficiencies in dispatch (EWI, 2012). 

 

In autumn 2012 a study commissioned by WWF analysed the introduction of a new market 

mechanism, explicitly taking into account the targets set for the energy transition and keeping the 

costs to consumers as low as possible. The study recommended to plan for a capacity market in 

which only existing plants with an annual capacity utilization of less than 2,000 hours would be 

eligible (Oeko-institut et al, 2012). 

 

In September 2013 the Federal Association of the Energy and Water Industry (BDEW) proposed 

the introduction of a decentralised capacity market mechanism, including trading of guaranteed 

capacity certificates. The proposed system included obligations for suppliers to hold sufficient 

capacity certificates in times of shortage to meet the demand of their customers. Certificates can 

be issued by power stations or storage operators, and can be substituted with demand-side 

management measures (BDEW, 2013). With the publication of this proposal the BDEW changed its 

position as they originally advocated a strategic reserve. 

 

In 2014 the German Ministry of Economic Affairs and Energy commissioned two parallel studies: 

the first on the functioning of the electricity only markets (EOM) and the second being an impact 

assessment of a proposed capacity mechanism. Both studies concluded that in principle the 

electricity-only market basically can secure electricity supply according to consumer preferences at 

lowest possible cost. To address potential imperfections the studies recommended some 

adjustments and clarifications to the current market framework, including: avoidance of implicit 

and explicit price caps for the electricity wholesale market price and therefore explicit acceptance 

of scarcity prices (“Peak Load Pricing”) and removal of barriers for the integration of demand 

Interactions between electricity market reforms and climate policies 

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flexibility and unconventional generation capacities that are currently not participating in the 

market (e.g. emergency generators) (Frontier, 2014) (R2B, 2014). 

The Ministry of Economic Affairs and Energy used the results from several of these studies in the 

preparation and production of the Green Paper (An Electricity Market for Germany’s Energy Transition) 

that was published in October 2014 (BMWE, 2014). The Green Paper analyses how to develop a future 

market design and regulatory framework for the electricity sector that ensures that the power supply is 

secure, cost-efficient and environmentally friendly. The Green Paper discusses: 
1)  No-regret  measures  for  the  secure,  cost-effective  and  environmentally  compatible  dispatch  to  all 

producers  and  consumers.  The  Green  Paper  states  that  these  no-regret  measures  should  be 

introduced  irrespective  of  whether  adequate  capacity  is  available  and  regardless  of  the  decision  on 

capacity markets. The most important list of no-regret measures includes: 

2)  Further developing the spot and balancing market by:  

 

Increasing the pace of market coupling of spot markets; 

  Harmonizing  the  balancing  markets  at  European  level  (within  the  framework  of  the  network 

codes); 

 

Improving competitive bidding conditions in balancing markets in order to strengthen competition 

and integrate “new electricity consumers”; 

 

Examining the possibility of a situation-based balancing capacity bidding process that depends on 

the  supply  of  wind  and  solar  energy  (e.g.  revision  of  the  prequalification  standards  for  offering 

balancing capacity so that wind farms, in particular, can provide negative balancing capacity). 

3)  Optimising  network  charges  and  state-imposed  price  components  to  make  flexible  consumer 

behaviour more attractive. 

4)  Expanding the network and optimising power grids by implementing grid expansion projects identified 

as necessary and confirmed by legislators, and examining whether it will be possible to activate back-

up power units for re-dispatch in order to reduce the need for a network reserve. 

5)  Establishing a strategic reserve. 

6)  Solutions for sufficient, cost-effective and environmentally friendly capacity maintenance. This part of 

the  Green  Paper  examines  whether  an  optimised  electricity  market  can  be  expected  to  maintain 

sufficient  capacity  to  guarantee  security  of  supply  or  whether  an  additional  capacity  market  is 

required. The Green Paper states that a fundamental policy decision is needed: are we going to move 

towards an Electricity market 2.0 or a capacity market?  

7)  Moving  towards  an  “Electricity  market  2.0”  assumes  that  pricing  remains  free  for  electricity.  This 

implies  that  price  peaks  needed  to  make  investment  in  power  plants economically  viable  are  not  in 

any way restricted, ruled out or mitigated by the prohibition of abusive practices under anti-trust law. 

8)  Moving  towards  a  capacity  market  assumes  that  even  an  optimised  electricity  market  does  not 

provide  sufficient  incentive  for  the  maintenance  of  capacity.  Three  options  for  the  introduction  of  a 

capacity market from the various studies listed above are analysed: 

9)  Central  comprehensive  capacity  markets;  a  central  authority  specifies  the  total  capacity  required, 

which is subsequently auctioned. If contracted, suppliers receive a uniform payment. The costs of the 

capacity market are added to the electricity price as a surcharge. 

Interactions between electricity market reforms and climate policies 

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10) Central focused capacity markets; similar to the above,  but only part of the  capacity  deemed  to be 

required  is  procured in  public  tendering  and  an  authority  decides  which  (type  of)  facilities  can  take 

part in the auctions. 

11) Decentralised capacity markets; the total capacity is not centrally specified, but a penalty payment is 

specified  instead,  implicitly  requiring  retailers  to  prove  that  they  have  contracted  sufficient  capacity 

through the purchase of capacity certificates which subsequently can be traded bilaterally. 

The Green Paper notes that central-focused capacity markets could be designed to promote flexible and 

low emissions capacities, while comprehensive and decentralised capacity markets could lock-in inflexible 

and high carbon capacity since they would also receive payment. 

The Green Paper states that, both in the case of an Electricity Market 2.0 and in case a capacity market, 

introduction an additional safeguard is needed in the transition period by maintaining reserve capacity. 

The Green Paper states that for this aim the Ordinance on Reserve Power Plants will to be extended to 

around 2022 and will be adapted towards a more regionally nuanced capacity reserve. 

The Green Paper also stresses the importance of intensifying European cooperation to make the 

electricity system more efficient and to strengthen security of supply. Possible options include working 

closely on this topic with neighbouring countries, supporting the development of network codes within the 

framework of ENTSOE and establishing a national legal framework in order to further integrate the 

German electricity market into the European internal electricity market.  

The Green Paper has resulted in a White Paper that was published in July 2015. The White Paper confirms 

the no-regret measures, including a further developed capacity reserve, will be pursued. It opts for the 

electricity market 2.0 option rather than capacity markets, although it does introduce a strategic reserve 

(which is a form of capacity remuneration mechanism). It also proposes new fields of cooperation for 

European electricity markets, backed up by a joint declaration by Germany and its neighbours on 

Regional Cooperation on Security of Electricity Supply in the Framework of the Internal Energy Market. 

Corresponding legislative proposals have been published in November 2015.  

Some form of a capacity remuneration mechanism is one of the possible means to address the German 

electricity market issues. Several other means also exist, each with its own impact and value for solving 

the different issues, as was discussed in Chapter 4. The following sections describe some of the low-

carbon flexibility options in the context of the German power market and the further measures 

considered. In addition a quantitative assessment is made on the potential impact of supporting these 

flexibility options. 

7.7 

Interconnection capacity 

The German electricity grid is strongly interconnected. Interconnections exist with Austria, the Czech 

Republic, Denmark, France, the Netherlands, Poland, Sweden and Switzerland. Germany has 

consequently played an important role in the regional electricity market for many years. It has historically 

always been a large exporter of electricity in winter and has imported electricity in summer. Since 2003 

Interactions between electricity market reforms and climate policies 

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Germany has been a continuous net exporter, with steadily increasing amounts of net export. After March 

2011, when the nuclear phase-out started, net exports dropped. However, since 2011 they have 

increased again, reaching record amounts both in 2012 and 2013. The export surplus was approximately 

33.8 TWh in 2013 (Burger, 2014b) and was the same order of magnitude in 2014. Interconnection 

capacity has also become an important facilitator for the balancing of the German grid and increasingly 

acts as storage for electricity from renewable sources, with electricity exported in the midst of the day 

when solar and wind are at their peak. Electricity is imported during mornings and evenings. 

To facilitate the Energiewende various extensions and new interconnectors are being planned. We discuss 

three of these below: expansion of interconnections with the Netherlands and with Poland, and the first 

direct connection between Norway and Germany. Following the descriptions of new interconnections, a 

quantitative assessment is made on the impacts of adding the 6GW of interconnection capacity to the 

German power system. 

7.7.1  Expanding interconnectivity to the Netherlands 

The Dutch and German TSOs are closely cooperating on the optimisation of the interconnectors between 

Germany and the Netherlands. The main drivers in both countries are grid security and grid supply 

availability. For the Netherlands an additional driver is further convergence of electricity prices between 

the two countries. For Germany an additional driver is to further enhance the possibilities to incorporate 

high amounts of solar and wind production. Current ongoing projects include a new interconnector 

between Doetinchem and Wesel of 1,500 MW (expected completion in 2017) and an upgrade of the 

Meeden-Diele interconnector of 500 MW (expected completion by 2018). In addition, further optimisation 

of the use of the existing grid is being analysed, which led to an additional 100 MW capacity from early 

2014 as a result of the optimisation of the Net Transfer Capacity calculations. 

7.7.2  Expanding interconnectivity to Poland 

Capacity expansion between Germany and Poland is included in Europe’s projects of common interest 

(PCI) to bring interconnectivity of all MS to at least 10%. For Poland this will bring a considerable 

expansion to its current low share of interconnection (3%). Two clusters of capacity expansion between 

Germany and Poland are included: 
(1) 

The  GerPol  power  bridge project  between  Eisenhüttenstadt  (DE)  and  Plewiska  (PL).  This  project 
consists  of  the  construction  of  a  new  AC  380  kV  double  circuit  connection,  construction  of  two 
new substations in Poland, strengthening of two internal lines in Poland and a connection with an 
existing substation. The project is planned for completion in 2022. 

(2) 

A  cluster  of  activities  to  upgrade  the  existing  interconnection  capacity  between  Vierraden  (DE) 
and  Krajnik  (PL)  from  220  kV  to  380  kV,  including  installation  of  Phase  Shifting  Transformers 
(PSTs)  on  this  upgraded  interconnection  as  well  as  on  the  existing  interconnection  between 
Mikulowa (PL) and Hagenwerder (DE). 

7.7.3  New direct interconnection with Norway 

The NordLink project will be the first direct interconnection between the German and Norwegian grids. 

The 623 km long high-voltage direct current cable will have a capacity of 1,400 MW. The final investment 
decision for this cable was made in February 2015.28 The interconnector is expected to provide benefits to 

28 Press release KfW IPEX-Bank, Green light for important electricity connection between Norway and Germany, 10 February 2015. 

Interactions between electricity market reforms and climate policies 

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both countries, similar to the benefits resulting from the NorNed connection between the Netherlands and 

Norway: 

  Surplus renewable electricity produced in Germany in periods with strong wind and solar radiation 
can be transmitted to Norway where it can be stored in water reservoirs with pumped storage. 
Germany can import cheaper, renewable Norwegian hydropower when German demand is high 
and production is low. 

  Surplus hydropower production in Norway in periods of heavy rainfall can be exported to Germany 

and beyond. In dry periods Norway can import (renewable) electricity from Germany. 

7.7.4  Quantifying the impacts of improved interconnectivity 

Figure 36 pictures the impact of an additional 6 GW interconnection capacity on the German electricity 

demand curve, showing a slight upward shift overall. 

Figure 36 » Illustrative impact of 6 GW additional interconnection capacity in the German market on the German 
demand curve  

Table 19 lists the impacts of increased interconnectivity on peak demand, the average electricity price 

and the profitability and load hours of four types of production plants. The modelling results show that 

the assumed 6 GW of additional interconnection capacity, all other things being equal, results in an 

increase of the average daily peak (+1.2 GW) as well as an increase in the SRMC price in Germany. The 

benefits for German producers can be large, since the new capacity increases net exports and therefore 

the number of operating hours. This increase is found both for renewable power production and for fossil-

fuelled power production. With a slightly higher price for a significantly higher amount of operating hours 

the total impact on profitability for all operators is high. 

Interactions between electricity market reforms and climate policies 

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Table 19 » Additional net impact of an increase in interconnection capacity  

Interconnection capacity (6GW)  

Average daily peak (GW) 

Average SRMC price

(€/MWh) 

Wind onshore 

Profitability (€/MW/year) 

Average CCGT 

Load hours  

Profitability (€/MW/year) 

Efficient CCGT 

Load hours  

Profitability (€/MW/year) 

Coal 

Load hours  

Profitability (€/MW/year) 

+1.2 

+0.9 

+1015.8  

+5.6% 

+4078.2 

+4.7% 

+5319.4 

+1.6% 

+4979,0 

7.8 

Electricity storage and demand response measures 

Electricity storage and demand-side management are seriously considered as market stability options in 

the German market. Solar storage systems have been financially supported since May 2014 and various 

demand-side management companies are offering DSR services. In February 2014 the largest DSR 

company in the US, EnerNoc, entered the European market by buying Germany’s leading DSR company 

Entelios, indicating that the German DSR market will serve as their stepping stone to the European 

market. Germany's secondary reserves market today already has a total size of more than 4,000 MW. A 

wide range of predictions for future DSR capacity exist, as well as for storage capacity. For both options 
the ranges provided vary from 2-10 GW in 2020.29 In this study we have analysed the impact of a 5 GW 

DSR capacity and a 5 GW storage capacity in 2020. This is shown in Figure 37. 

Figure 37 » Illustrative impact of a change in electricity storage capacity (left) and demand response measures 
(right) on the German electricity demand curve 

lists the impacts of increase storage and increased demand response on peak demand, the average 

electricity price and the profitability and load hours of four types of production plants. The modelling 

results show that the assumed 5 GW demand response reduces the average daily peak by 2.8 GW. The 

increase of storage capacity by the same amount (or 17.5 GWh of production capacity) induces an even 

29 See for example DENA (2010), EWI (2012), Lux Research (2012) and Gils (2014). 

Interactions between electricity market reforms and climate policies 

 106 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
larger reduction in the daily peak of 4.8 GW. Such reductions can reduce the need for peak generation 

capacity, therefore lowering peak prices on the market. To allow for comparison across flexibility options 

the results for expansion of interconnection capacity are added to the table again. 

Table 20 lists the impacts of increase storage and increased demand response on peak demand, the 

average electricity price and the profitability and load hours of four types of production plants. The 

modelling results show that the assumed 5 GW demand response reduces the average daily peak by 2.8 

GW. The increase of storage capacity by the same amount (or 17.5 GWh of production capacity) induces 

an even larger reduction in the daily peak of 4.8 GW. Such reductions can reduce the need for peak 

generation capacity, therefore lowering peak prices on the market. To allow for comparison across 

flexibility options the results for expansion of interconnection capacity are added to the table again. 

Table 20 » Impacts of an increase in interconnection capacity, storage capacity or demand response  

Interconnection 

Storage capacity 

Demand response 

capacity (6GW) 1) 

(5GW/17.5 GWh) 

(5GW) 

Average daily peak (GW) 

Average SRMC price

(€/MWh) 

Wind onshore 

1015.8  

Average CCGT 

5.6% 

4078.2 

Efficient CCGT 

4.7% 

Coal 

5319.4 

1.6% 

4979.0 

+1.2 

0.9 

-504.3 

-3.4% 

-3979.3 

1.8% 

-4074.6 

2.6% 

-2588.5 

-4.8 

-0.6 

-5.5 

0.9% 

-586.8 

0.6% 

-320.1 

0.0% 

-203.4 

-2.8 

-0.1 

-5.5 

0.9% 

-586.8 

0.6% 

-320.1 

0.0% 

-203.4 

1) Increased interconnection capacity increases Germany’s net exports and production. Higher generation in Germany 
results in an increase in the wholesale market price. Even if the absolute level of interconnection increase is not too 
large, it increases demand for most hours and therewith has a significant impact on prices and revenues.  

The modelling results show that the direct impact of peak shifting on CO2 emissions depends strongly on 

the generation mix and market conditions. In a system with low CO2 prices and base-load coal, such as 

currently in Germany, the result of peak shifting is a shift of peak generation from gas plants to base-

load generation from coal plants. Consequently the level of CO2 emissions increases. In a system where 

coal plants are not the base-load plant the impact of peak shifting would more likely be a shift of 

generation from less efficient plants to more efficient plants, with an accompanying decrease in CO2 

emissions. Vice versa, higher CO2 prices and their impact on marginal electricity prices would also 

contribute to increasing the economic value of storage and demand response. 

Two additional values of storage and DSR are not included in this analysis: 

Interactions between electricity market reforms and climate policies 

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1.  First, storage and DSR can be used to provide ancillary services and headroom for the electricity 

system. This will allow conventional plants to run more efficiently, with accompanying CO2 

emission reductions.  

2.  Second, especially storage, but also DSR to some extent, provides an opportunity to support the 

integration of high levels of (distributed) renewable electricity generation on the grid 

7.9 

Concluding remarks 

In line with its energy and climate policy objectives, the German power system is undergoing a significant 

transition towards decarbonisation, which is accompanied by an intense debate on corresponding 

electricity market reforms. The analysis of the German power market suggests that reduced electricity 

demand and a high penetration of intermittent renewables in the German electricity system are having a 

negative impact on the profitability of mid-merit plants. The dispatch modelling analysis suggests that 

increasing penetration of renewables is the main driver of reduced profitability of mid-merit plants on the 

wholesale market. Increasing carbon prices enhances fuel switching on the German market, with more 

gas plants being dispatched at the expense of coal plants. It has only moderately positive impacts on the 

profitability of gas plants, while the profitability of renewables strongly increases. Fuel switching towards 

gas would also be enhanced by an increase in coal and lignite prices, while increasing fuel prices across 

the board would increase profitability overall. 

The analysis also shows that accounting for ancillary services is important for considering the profitability 

of mid-merit plants and peaking plants, and tends to make efficient existing ones profitable. In the 

context of the German debate on electricity market reform, the results of the modelling suggest that 

there are questions ahead with regards to incentives for new investment in mid-merit plants that will be 

needed, and hence with regards to capacity adequacy if operators would decide to take part of their 

capacity out of the market. 

Incentives could be provided in the form of increasing ancillary service markets and scarcity rent that 

peaking and mid-merit plants can secure at times of high demand and low intermittent supply in an 

energy only market, and could be facilitated by higher carbon prices through a strengthened EU ETS, or 

capacity remuneration. But equally, in the wider European context, there is also an important role for 

increasing system flexibility through increasing interconnectivity. The need for mid-merit plants can be 

reduced by increased storage and demand response. If capacity remuneration mechanisms were to be 

chosen and not accompanied by a stronger carbon price, they risk incentivising the operation of coal and 

lignite over gas (to the extent that coal variable running costs are lower), with corresponding impacts on 

German CO2 emissions, although limited in the case of a capacity reserve. 

The main limitations of the modelling analysis are discussed in Chapter 5, but there is one limitation that 

could particularly affect these findings, that the scarcity rent that peaking and mid-merit plants can 

secure at times of high demand and low intermittent supply are under-represented in the model. 

Interactions between electricity market reforms and climate policies 

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8 » Analysing the Polish electricity market reform 

This chapter contains a brief analysis of the Polish electricity market, focusing on the proposed electricity 

market reforms.  

8.1 

Main drivers for the proposed electricity market reform 

The Polish electricity system is characterised by a very high share of coal-based power generation. 

Recently, also renewable power generation has started to increase, but still has a rather low market 

share. Polish electricity demand as well as peak demand is expected to increase strongly until 2030. 

Export and import capacities are expected to increase, and so is the share of intermittent production. All 

in all it is expected that net reserve margins will lower from 34% in 2010 to 15% in 2020 (increasing 

again to 21% by 2030). An important aspect in the Polish electricity system is the expected capacity 

problems. The larger part of the current installed capacity in the Polish power system was built in 

60/70/80-ties of the 20-th century. Consequently most of this capacity is already technically aged and 

many of these plants are candidates for modernisation or decommissioning in the coming years. The 

majority of the installations are coal and lignite power plants. PSE, the Polish TSO estimates that a total 

of up to 7,900 MW will be decommissioned until 2025, which is up to 20% of currently installed capacity. 

The amount expected to be decommissioned consists of: 

  2,300 MW until the end of 2015, as a direct effect of the LCP; 

  1,300 MW between 2016 and 2020 - mainly until the end of 2017; 

  4,300 GW between 2020 and 2025, mainly caused by plants exceeding their life span. 

In addition, investments in new production capacity are lagging behind. Polish sources explain this with 

low wholesale prices and uncertainty on EU policy regulation, especially with respect to the EU ETS and 

the uncertainties related to the continuation and possible further conditions of Article 10C of the EU ETS 

Directive which allows transitional free allocation to among others existing Polish power plants. PSE 

estimates approximately 4.5 GW of new capacity until 2020 (ENTSO-E, 2014). Polish stakeholders and 

regulatory bodies expect that the resulting net decrease of production capacity may be insufficient to 

meet increasing demand in the future. For the longer term new nuclear capacity is expected: the EU 

Reference scenario 2013 assumes in line with Polish plans at the time the start of 6.3 GW new nuclear 

capacity to start operation from 2025. Biomass and wind power capacity and production is also projected 

to increase strongly. 

Poland is currently revising its energy strategy and is considering various options to ensure security of its 

energy supply, among which a proposal for a capacity market (for more details see the following 

Section). In addition the following options are considered or under development: 

  Cold capacity reserve: From 2016 until 2023 units that do not fully meet the requirements under 

the IED, but do comply with requirements under the Large Combustion Plant (LCP) Directive, are 

allowed  to  operate  up  to  17,500  hours  (in  the  period  2016-2023).  The  Polish  TSO  will  pay  for 

keeping  this  so-called  ‘Cold  capacity  reserve’  operating  to  meet  electricity  demand  (Ministry  of 

Economy, 2013). 

Interactions between electricity market reforms and climate policies 

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  Demand  side  reduction:  In  March  2013  the  TSO  signed  two  contracts  with  large  electricity 

consumers.  In  case  of  a  threat  of  capacity  deficit  in  the  system  these  large  consumers  are 

required  to  reduce  their  demand.  This  so-called  the  ‘nega-watts’  instrument  is  being  further 

developed and continued in order to ensure 200 MW demand reduction if required. 

  New  interconnection  capacity:  Poland’s  current  level  of  interconnection  is  relatively  low,  around 

2%.  This  is  significantly  below  the  Barcelona  target  of  10%  for  the  year  2020.  New 

interconnection capacity is being realized between Poland and Lithuania and between Poland and 

Sweden  (700  MW).  Further  new  investments  to  increase  interconnection  capacity  are  planned, 

including connections with Germany, the Czech Republic and Slovakia. The total technical import 

capacity  is  expected  to  increase  from  820  MW  in  2014  to  4,420  MWe  in  2030.  Total  technical 

export capacity is expected to increase from 500/1,000 MW to 5,200 MW (ENTSO-E, 2014). 

 

PSE,  the  Polish  TSO,  plans  to  commission  the  building  of  hundreds  of  kilometres  of  new 

transmission lines in the next few years to ensure better balancing of demand and supply in the 

coming year.  

8.2 

Quantitative analysis of the current situation 

The Polish power sector is dominated by hard coal and lignite production capacity. Part of this capacity is 

CHP delivering heat to district heating facilities and therewith is treated as must-run in the model. Given 

the priority dispatch for renewables the production of renewable units is also treated as must-run, i.e. 

these units are dispatched prior to other units. 38 shows the dispatch curve and merit order for the year 

2010, without the production of intermittent renewables as generated by the model. Figure 39 shows the 

short-run marginal cost curve based on the price assumptions made. 

We conclude that due to insufficient detail for the model input the model is not able to grasp the market 

dynamics well. The model especially underestimates the (potential) use of gas-fired capacity. The key 

data missing are detailed plant level information, i.e. efficiencies and cost data at plant level. Based on 

available wholesale market prices and guesstimates on lignite prices an initial modelling analysis has 

been made, but the lack of exact data results in large uncertainties for the costs of coal plant operation. 

Given the very high dominance of coal plants in the Polish market this again results in the fact that 

uncertainties on the small amount of (potential) gas-fired production in this specific model lead to high 

inaccuracies in the dispatch calculation. We conclude that based on the current dataset the model used in 

this study cannot be used for detailed analysis of the proposed capacity market or other types of market 

interventions. 

Interactions between electricity market reforms and climate policies 

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Figure 38 » Merit order for the 2010 Polish power market, excluding intermittent renewable production as 
generated by the model 

Figure 39 » Short-run marginal cost curve for the 2010 Polish power market, excluding intermittent renewable 
production as generated by the model 

Figure 40 provides the load generation curve for the Polish electricity sector in the year 2010 based 

capacities reported under the EU Reference scenario 2013.  

The EU reference scenario 2013 as well as the TSO prognoses indicate an expected higher scarcity of 

electricity on the market and therewith an increase in the wholesale market price. This can be expected 

to result in an increased profitability for most production units and hence to mitigate capacity adequacy 

related issues. 

Interactions between electricity market reforms and climate policies 

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Figure 40 » Load generation curve for Poland for the year 2010 

8.3 

The capacity market under discussion 

Poland currently has a reserve service that resembles a strategic reserve. Cold intervention reserve refers 

to payments to the TSO for 

  A ‘cold intervention reserve’ in which producers are paid to keep units available at ‘ready-for-

operation’ mode. This can be provided by capacity that is planned for decommissioning. PSE 

estimates a required 1,000 MW of cold intervention reserve. To date 454 MW has been 

contracted.  

  An Operating Power Reserve (OPR) which shall apply when the power reserve on the Polish 

market falls below 18% of peak demand. The OPR can provide payments to ensure that 

generators maintain a reserve generation capacity 

Future options for capacity mechanism are currently under discussion in Poland, aiming to support 

investments in new capacity, especially coal and gas power plants. A concept proposal is being developed 

by the Department of Energy in the Ministry of Economy, based on a draft proposal developed by the 

sector representative TGPE. In the development of this proposal the options considered and analysed 

include: 

  Remuneration for power capacity including auctions for new capacities organised by the Energy 

Regulatory Office. 

  Contract for Difference (CFD), including contracts stipulating that the seller will pay to the buyer 

the difference between the current value of an asset and its value at contract time. 

In both cases, centralized and decentralized approaches could be applied. Details of the proposed 

capacity market have not been decided upon, but the following information was obtained (Dabrowski, 

2014): If a capacity market would be established, it is expected to start 2018-2020, not earlier. The first 

plans are expected to be announced in 2015. 

 

Two proposals are being developed: 1) a centralised system with the TSO as a single buyer, 2) a 

decentralised system in which the DSOs would be buying capacity. In both options capacity 

availability would be bought for 4-years ahead. 

Interactions between electricity market reforms and climate policies 

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 

The proposed system will be technology neutral (i.e. access to all types of flexible capacity), but as 

in the UK it will include availability factors per technology, based on historic data. 

  Demand-side, foreign capacity and domestic capacity was said to be included in both proposed 

systems with equal access to the capacity market 

 

It is not yet decided if the capacity market solutions would be dedicated to only existing utilities or 

to new capacities only. 

 

Possible interrelations with the domestic electricity market are carefully considered, as there is a 

threat that the market can become regulated after the capacity market is established. 

The Polish power sector is said to prefer the system modelled along the UK capacity market in which the 

Polish TSO would be the single buyer for flexibility on the Polish market.  

Interactions between electricity market reforms and climate policies 

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9 » Analysing the French electricity market reform 

This chapter includes a brief analysis of the French electricity market, focusing on the proposed electricity 

proposed electricity market reforms. The French market was not selected for quantitative analysis as the 

French power system and its current challenges are very country specific (e.g. a high share of nuclear 

capacity and a high share of electric heating) which would provide limited insights for the broader EU 

perspective. Moreover, illustrative quantitative analysis of the impact of introducing a French capacity 

mechanism on the EU internal energy market has been performed as part of an earlier study for the 

European Commission, DG Energy (Tennbakk, 2013). 

9.1 

Main drivers for the electricity market reform 

The primary concern in the French electricity market is the rapid growth of peak demand. This is to a 

large extent due to the high penetration rate of electrical heating in the residential and tertiary sector. 

Peak demand has increased by 36% between 2001 and 2012. 

In 2012, the sensitivity (or elasticity) of electricity demand to temperatures was estimated at 2,300 MW 

per °C. The temperature gradient is expected to reach 2,600 MW per °C in 2018 despite energy efficiency 

policies and measures. In April 2010, a parliamentary report (Poignant – Sido, 2010) on the management 

of peak demand in the electricity sector made a number of proposals including the valorisation of demand 

response, the introduction of a capacity obligation for suppliers and the creation of a capacity market. A 

number of demand side management initiatives have progressively developed despite the lack of a legal 

framework. To enhance further demand response in the French electricity market, establishing a capacity 

market to give value to demand response was deemed necessary. The parliamentary report concludes 

that in France, energy-only markets are considered insufficient to foster the development of demand 

response, both in terms of price and volume. 

On the supply side, a conjunction of short and long-term drivers is expected to cause a reduction of the 

total installed reliable capacity. A number of oil-fired and coal-fired units are being closed following EU 

environmental Directives (large combustion plant directive and industrial emissions directive). Adverse 

market conditions are leading to the closure or mothballing of CCGTs. Finally, the economic crisis is 

creating a business environment that is unfavourable to new capacity investments. French generating 

companies pointed to difficulties in recovering fixed costs through energy-only markets in a context of 

increased penetration of renewable energies and advanced integration of European power markets 

(market coupling). 

Following the Poignant-Sido report, the concept of capacity mechanism was introduced in the general 

electricity Law (NOME) voted in December 2010. The objective of the NOME Law is broader: to reform 

the organisation of French electricity markets and tariffs. The principle of a capacity obligation imposed 

on every supplier in order to guarantee the security of supply of the French electricity system was 

adopted. The Ministry of Energy then commissioned RTE, the French TSO, to design the capacity 

mechanism and launch a broad stakeholder consultation. In October 2011, RTE published a report 

proposing the creation of a capacity market. 

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9.2 

The adopted decentralised capacity market 

Following the publication of the Decree that created the French Capacity Mechanism in December 2012, 

the French TSO RTE published a report with the details of the proposed mechanism, including the rules 

and parameters needed to calculate capacity obligations, dispositions on penalty settlement, certification 

methodology, etcetera in September 2013. After a stakeholder consultation the proposal was updated 

and sent to the French government in April 2014. The governmental decree for the implementation of the 

capacity mechanism was signed on January 22, 2015. The French Capacity Mechanism will become 

effective as of January 1, 2017. 

The French Capacity Mechanism includes: 

  A capacity obligation on all suppliers active in the French electricity market. 

 

The obligation will correspond to the 10 to 15 days of the year when demand is at its highest, 

generally during the coldest months of the winter. 

 

The capacity obligation of a given supplier will correspond to the total consumption of its 

customers during a standard winter cold spell and will be calculated based on the real 

consumption of these customers plus a reserve margin. The formula to determine the capacity 

obligation will be published by RTE 4 years ahead of the delivery date. 

  All capacity owners are required to have their production capacity and demand 

response potential certified. Certification is based on the ability to reduce loss of load during 

winter cold spells. In order to obtain certificates, capacity owners need to guarantee that their 

production facilities (or load reduction potential) will be available during pre-defined peak hours. 

  A market for transferable and tradable certificates will be established to allow suppliers 

to buy or sell capacity. This market is independent from the wholesale energy market and owning 

a capacity certificate does not give any right to the corresponding energy. The price of capacity 

certificates will be determined by the supply and demand of certificates. 

 

Trading on this capacity market will be continuous and start 4 years ahead of delivery. The price 

of capacity will reveal the value of security of supply. The price will drop to zero if there is no 

security of supply risk. 

  Access to the capacity market is equal for all technologies and generation and demand-

response are treated equally. All generation technologies, regardless of their baseload or peak 

load characteristics, can generate capacity certificates. New and existing power plants are treated 

similar. 

  Demand-response capacity can be proposed directly in the capacity market by (large) consumers 

or aggregators provided their DR Capacities have been certified. Small capacity owners will 

benefit from specific certification methods, so that certification costs remain bearable. 

 

Energy suppliers, which are subject to a capacity obligation, can use demand response to reduce 

the level of their obligation (implicit participation) or to generate tradable certificates (explicit 

participation). A system is in place to avoid double counting of DR capacities proposed by a 

supplier. 

  Suppliers are subject to penalties if the load demand of their (French) customers during peak 

hours is not covered by a comparable amount of capacity certificates. 

Interactions between electricity market reforms and climate policies 

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  Capacity located abroad is included in the system only on an implicit basis. The capacity 

mechanism itself is not open to foreign capacity. However, RTE has repeatedly mentioned that 

explicit cross-border participation in the French capacity market is the target model but that this 

would be conditional to the participation of foreign capacities to the French Balancing Market. 

 

The positive contribution of cross-border interconnections to the security of supply is taken 

into account in an indirect manner, by defining a lower capacity obligation and smaller 

strategic reserves. 

  A last resort balancing measure (or “dispositif de bouclage”) has been added to the capacity 

market in order to cope with extreme situations and high imbalance risks. 

The GHG emission impacts of the adopted CRM are expected to be quite limited in absolute terms, since 

the fast majority of the French electricity production is carbon free (close to 92% in 2013). However, 

since the majority of peak demand is provided by fossil-fuelled capacity the relative impacts on GHG 

emissions from the power sector could still be significant. This since the peak load production units 

profiting from the capacity market could see their plant economics increase and more easily provide 

(small amounts of) additional power production at relatively low costs and therewith see their load hours 

increased compared to the current (mostly carbon free) base load production units. A potential increase 

in French GHG emissions is also identified by (Tennbakk, 2013) when analysing the impact of a CRM and 

concluding this could lead to increased export from French peak load production units. 

Interactions between electricity market reforms and climate policies 

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10 »  Analysing the Italian electricity market             

reform 

This chapter includes a brief analysis of the Italian electricity market, focusing on the proposed electricity 

market reforms. The Italian market was not selected for quantitative analysis since the possibilities for 

introducing further flexibility measures on the Italian market, and the impacts of such measures will be 

strongly influenced by the connection capacities between the Italian regions. Consequently an analysis on 

flexibility on the Italian market should in our view be analyses on the basis of a regional electricity 

market model and not on the basis of a national electricity market model as was developed for this study. 

10.1  Main drivers for the proposed electricity market reform 

After the blackouts experienced in the Italian electricity system in 2003, the programmable thermal 

capacity experienced a strong growth, especially for CCGT plants. In the period 2003-2008 approximately 

15 GWe of new thermal production capacity was installed. Since 2008, the use of intermittent renewable 

electricity, mainly PV and onshore wind has grown significantly in Italy. In 2008-2012 a total of 20 GWe 

additional capacity was installed. These developments, as well as a reduction in electricity demand of 

approximately 7% in the period 2008-2013 as a result of the economic crisis, has created a situation of 

overcapacity on the Italian power market (Terna, 2014b). 

Priority dispatch for renewable electricity has reduced the load hours for conventional fossil fuelled power 

plants and resulted in a decrease of the electricity wholesale price. In the period 2008-2013 the pool 

price on the Italian market decreased from €86.99/MWh to €63/MWh (SEN, 2013). Consequently the 

profitability of existing power plants was strongly reduced and new investments were less attractive. 

Market reports from the year 2013 indicate that 12 plants with a total capacity of 3.2 GWe were switched 

off in 2012 and an additional five plants would follow in 2013 (700 MW) and 2014 (600 MW) (ICES, 

2013). In 2014 ENEL announced shutting down 13 GW of coal-fired capacity in Italy by 2020 and 

cancelled two planned coal plants. The 2015 business plan confirmed the company’s plants to gradually 

phase-out further investments in coal-fired capacity.  

Despite a situation of overcapacity on the market, Italy imported 13.6% of its total demand in 2013 (44 

TWh), mainly from France and Switzerland. This was a result of low import prices from nuclear power. 

Exports are still low and the current interconnection capacity is considered insufficient for a higher 

integration in the Internal Electricity Market. Italy also faces a growing situation of unbalance between 

local supply and demand. This is especially caused by the fact that most renewable energy investments 

are done in the southern regions, while the largest demand is located in the north. In 2012, 12 out of 20 

Italian regions in Italy recorded a production deficit compared to consumption, whereas the entire 

country rather has a consumption deficit. This has created congestion problems and a substantial price 

differential among Italian zones. 

Interactions between electricity market reforms and climate policies 

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10.2  The proposed capacity market 

In 2004 Italy introduced a capacity payment mechanism within a broader reorganisation of the Italian 

electricity sector. The Italian regulator AEEG indicates the following limitations to this mechanism (AEEG, 

2014): 

  Difficulties for generators to plan investments ahead due to the short-term character of the 

system. 

  A low participation rate of producers due to low remunerations. 

 

Large uncertainty on the availability of capacity as a result of low penalty levels, which 

complicates the TSO’s balancing tasks.  

A new Capacity Mechanism was approved in June 2014. In 2011 AEEG defined the criteria and conditions 

for the new CRM, after which the TSO Terna published a proposal. Following a broad public consultation 

AEEG approved Terna’s proposed system. In June 2014 the Italian Ministry of Economic Development 

approved the model. The new system was planned to start in 2017, but Terna has proposed to start the 

first auctions by September 2015, so that first results could be delivered in 2017. Until the date of 

implementation the current capacity payment system will remain in place. The new mechanism includes 

the following elements: 

  A shift from capacity payment to a “reliability option capacity market” mechanism. 

 

The system will be based on reliability options traded through yearly auctions/bidding on a 

market organized by Terna (TSO). Participation on this market will be voluntary. 

  During those auctions power producers will be able to sell options to cover the required back-up 

capacity set by Terna. The planning period for contracted capacity is 4 years and the delivery 

period will be at least 3 years. 

  Bidders will be obliged to deliver electricity once the electricity price exceeds a certain 

predetermined price (strike price) and otherwise, they will have to pay the difference between the 

actual price and the strike price. As long as the electricity price is lower than the strike price 

operators will have freedom to manage their generation capacities. 

 

The mechanisms is accessible for new (planned or under construction) and existing installations 

(generators and loads), but it limited to programmable capacities (fossil fuelled, biomass, solar 

thermoelectric, pumped storage, conventional hydro, etc.) that are not subject to any type of 

investment incentive scheme and that are not subject to any dismantling measures approved by 

competent authorities. 

 

The plants accessible to the Capacity Market are selected on the basis of their reliability. Plants 

will receive a “basic” or “top up” remuneration. The basic remuneration is set in advance, based 

on forecasts of supply and demand for each hour of the following day. The top-up remuneration 

is attributed if: i) the weighted average market price is less than 20% of a reference price defined 

by the regulator and if ii) the plant is located in an area characterized by low prices. 

  Additional requirements can be set on the location of delivery and the definition of the strike 

price: i) the location has to be the grid area where the resource is located to give proper 

locational signals and ii) the strike price corresponds to the standard variable cost related to 

efficient and effective plants. 

Interactions between electricity market reforms and climate policies 

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Depending on the exact design choices made and the capacity market remuneration levels paid the 

proposed CRM can have considerable impacts on national GHG emissions as it most likely will mainly 

support domestic fossil-fuelled capacity with corresponding emissions. 

Interactions between electricity market reforms and climate policies 

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11 » 

Lessons learned on the main research 

questions 

This chapter addresses the main research questions using the results from the qualitative and 

quantitative analysis. It derives key lessons learned at the overall EU level. 

What problems are faced by the electricity sector and how do they relate to the transition 

towards a decarbonised electricity sector? 

The decarbonisation of the power sector is one of the main elements in Europe’s energy and climate 

policy. It brings about a growing share of intermittent energy and decentralised generation. The current 

European electricity markets, however, were not designed for systems with such high renewable shares 

and consequently system balancing is becoming more challenging. 

Europe still faces many challenges to the completion of its internal electricity market. Large differences 

exist in regulation, the quality of national grids, the operation of wholesale and balancing markets and 

interconnections. However, these different electricity markets share common characteristics such as 

increasing shares of renewable energy and decreasing wholesale prices. The growing share of renewables 

results in less dispatch opportunities for existing plants, lower wholesale market electricity prices and 

more price volatility. This situation causes negative impacts on the expected revenues of fossil-fuelled 

power generation. Gas-fired production units in particular cannot recover their operational costs in 

current electricity markets; with the risk to a (temporary) closure of existing installations and therefore a 

risk to system adequacy. Low wholesale prices also hamper future investments and therefore pose a risk 

to capacity adequacy. The challenges have been further exacerbated by the economic crisis that has 

lowered electricity demand and brought about high overcapacity in various markets. Thus in the current 

markets many operators are faced with a profitability problem (or what is often called “missing money 

problem”): the revenues generated from wholesale markets alone are insufficient to recoup their 

investment costs and in some cases even their operating costs. Consequently these markets have a high 

risk of closing existing capacity and halting new investment. Related system adequacy and capacity 

adequacy issues have led to discussions on electricity market reforms and capacity remuneration 

mechanisms to address a risk to the security of energy supply. 

The exact nature of energy supply security risks differ among countries. In some countries the risk refers 

to capacity adequacy: revenues in the current electricity-only markets are insufficient to trigger new 

investments and therefore future production capacity may be insufficient to meet future demand. This is 

for example the main element of market reform discussions in the UK and Poland. In other countries an 

additional risk affecting system adequacy is identified: existing mid-merit capacity may be closed and the 

remaining flexible capacity would be insufficient to balance rapid growth and integration of intermittent 

renewables. This issue is at the core of the discussions (among others) in Germany, Italy and Spain. The 

total mid-merit capacity, however, is decreasing or at risk of decreasing for various reasons. This includes 

not only the “missing money problem”, but also the fact that many of these plants are ageing or less 

efficient, and need to make choices between refurbishment or closure, in part also due to the Large 

Combustion Plant Directive (LCP) and the Industrial Emissions Directive (IED). 

Interactions between electricity market reforms and climate policies 

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The growth in renewable capacity and the closure of ageing power plants contribute to the further 

decarbonisation of the electricity sector. However, since coal prices are relatively low and gas prices are 

relatively high, the declining profitability is much more prominent for gas-fired power plants than for 

coal-fired plants. Increased competition between the coal-fired and gas-fired mid-merit capacity at 

current fuel prices favours mostly coal-fired capacity. This results in gas-fired capacity being more at risk 

of closure than coal-fired capacity, creating opportunities for remaining plants to increase their load 

hours. This situation could have a negative impact on the decarbonisation of the electricity sector, both in 

terms of a shift from gas-fired to coal-fired operating hours as well as in terms of having less flexible gas-

fired capacity available to support the further growth of renewable electricity. 

The modelling results confirm the profitability problem for gas-fired plants in the UK and in Germany 

under current conditions. The results identify that the total revenues obtained on the wholesale market 

are insufficient to recover operating costs for most gas-fired capacity. Revenues from ancillary services 

and balancing markets provide a significant additional source of income, especially for mid-merit flexible 

production units. The calculations show that adding revenue from ancillary services to the plant revenues 

brings most existing plants close to break-even. However, the markets currently do not provide sufficient 

income to make new capacity investments profitable.  

How would the problem evolve in case of further decarbonisation of the EU power sector? 

Current climate and energy policies, including the further enhancement laid out in the EU Roadmap for 

moving to a low-carbon economy in 2050 and the 2030 framework for climate and energy policies, are 

expected to bring about a significantly higher share of renewables on to European electricity markets and 

are expected to bring significantly higher carbon prices. 

A further increasing share of renewable electricity production could worsen the "missing money" problem: 

the load hours of coal and – especially – gas-fired plants are further decreased and the wholesale price 

lowers. 

Sufficiently high carbon prices could strongly influence operational as well as investment decisions on the 

European electricity market. Higher carbon prices could close the financial gap for power plant operators, 

especially for gas-fired power plant operators, as they would increase wholesale electricity market prices, 

and thereby the potential revenue for all operators. 

High carbon prices could result in a shift in the merit order, with carbon intensive production units being 

pushed out of the market by low-carbon and carbon-free production units. For example, coal-fired 

production would move up in the merit order and gas-fired production would move down, triggering a 

switch from coal to gas. Modelling results show that such a merit order impact could occur at a CO2 price 

as low as €22/tCO2, both for the UK and the German markets. A further increase to €34/tCO2 in the UK 

market results in a clear switch in the position of coal plants and efficient CCGTs in the merit order. The 

resulting strong increase in load hours of gas plants gives a boost to their profitability. Likewise the 

profitability of coal plants significantly drops. The overall system impacts are even larger since higher CO2 

prices result in higher wholesale electricity prices, which pushes up the profitability of other plants 

dispatched.  Moreover, with high carbon prices investors will more likely refrain from investing in new 

Interactions between electricity market reforms and climate policies 

 121 

 
 
 
 
 
 
 
carbon-intensive power production units, shifting investments towards low-carbon electricity production 

technologies such as nuclear energy, fossil-fuelled power with CCS and renewable energy. 

Higher carbon prices could result in an increase of the profitability of carbon-free power plants, but also 

for low-carbon gas plants. Since also mid-merit and peaking plants may profit from this it may improve 

system adequacy. If carbon prices would be sufficiently high to trigger new investments they would also 

support capacity adequacy. 

Will strengthened energy-only markets (including ancillary services and carbon prices) be able 

to provide the right incentives for new investments?  

The debate on the European market centres on whether market interventions are needed to ensure 

sufficient system adequacy as well as sufficient capacity adequacy. Times of scarcity lead to higher prices 

and/or more frequent occurrences of price spikes. Such a situation will result in additional revenues for 

power plant operators and could provide sufficient incentives to support both system adequacy and 

capacity adequacy. The question, however, is to what extent more frequent occurrences of high prices 

and/or price spikes will be accepted by various stakeholders. Part II of the German Green Paper on the 

Electricity Market Reform explicitly refers to this aspect by identifying that fundamental choices are 

needed on the national future electricity market. The Paper also establishes that a credible alternative to 

a Capacity Remuneration Mechanisms (CRM) is an “Electricity market 2.0” in which price peaks, needed 

to make investment in power plants economically viable, are not in any way restricted, ruled out or 

mitigated. The UK Energy Market Reform states that very high electricity prices would be necessary to 

bring forward enough generation to meet demand at all times. 

The qualitative assessment identified various other options that can be applied to strengthen the current 

energy-only markets, including ending of regulated prices, coupling of wholesale markets and balancing 

markets, improved operation of balancing markets, international market coupling and expansion of 

interconnection capacity, introduction of balancing at local level, and expanding market access to smaller 

renewable electricity generation units, other distributed generation and market aggregators that bundle 

demand-side and/or smaller supply-side flexibility options. 

The purpose-built model was applied to quantify the impact of introducing such flexibility options on 

various plant types. Further analysis was conducted to draw conclusions of the impact on energy and 

climate objectives. The model results provide some first order indications on the impacts of improving 

some of these options, i.e. strengthened interconnections, enhanced demand management and increased 

electricity storage. Further in-depth analysis is recommended to understand the full potential of these 

options, and their interactions with carbon prices. For example, higher carbon prices might under certain 

circumstances provide increased economic incentives for such flexibility options, by increasing peak 

prices. Experience shows that most of these options do not only depend on the economic incentives from 

wholesale market prices but also require additional support, for example in terms of development in the 

organization of the market (actively worked on by parties such as ACER and ENTSO-E), by strengthening 

international market cooperation or by adapting market entry rules (for example for smaller and/or new 

market players). 

Interactions between electricity market reforms and climate policies 

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The quantitative and qualitative analyses conclude that increased flexibility is needed to ensure sufficient 

system and capacity adequacy in the future electricity market. Moreover, increased flexibility is an 

essential element to ensure that targets on decarbonisation of the power sector and the continued growth 

of the share of renewables in the power market are achieved. The qualitative analysis furthermore 

concludes that the basis of flexibility markets would need to include a combination of various flexibility 

options such as increased interconnection capacity, stimulation of demand response and providing energy 

storage, but also indicates that where needed this can include strengthening or introducing capacity 

markets. 

Also other measures could significantly mitigate the problems. These measures include high energy 

efficiency (reducing local supply scarcity such as in Italy and lowering the need for new investments), 

changes in renewable support policies (resulting among others things in improved system balancing and 

no payments in times of negative prices) and an increased shift to locally produced energy sources 

(lowering system adequacy problems). 

What additional capacity remuneration measures are currently applied, or debated, in 

European markets to face system and capacity adequacy challenges? 

In Europe the need for system adequacy and capacity adequacy is not contested, but differences of 

opinion exist about the extent to which the two are needed in specific markets and the means of how to 

achieve them. A large part of the debate concentrates on the need for so-called capacity remuneration 

mechanisms (CRMs) as complementing the energy-only markets and the ancillary services markets.  The 

proposed CRMs may provide additional incentives or sources of income for capacity, but, by the nature of 

their functioning, can also lead to reduced peak electricity market prices and therefore reduced revenue 

of existing plants that are unable to obtain capacity payments. 

Various design choices exist about what flexibility options would be supported by each CRM; however, 

current (proposed) CRMs mainly seem to focus on supporting supply-side flexibility. Proposed CRMs can 

be classified into volume-based mechanisms (strategic reserve, capacity obligation, capacity auction and 

reliability option) and price-based mechanisms (capacity payment). CRMs are to a large extent tailored to 

the specific market situation in each country, and they may combine elements from the different types of 

mechanisms. 

Capacity payments and strategic reserves are the most known options. The price-based capacity 

payment is a fixed payment provided in addition to a generator’s revenue from the regular energy-only 

market. The payment is provided by a regulatory body to keep certain existing capacity on the market or 

to incentivise new investment. The capacity payments system is used in (among others) Ireland, Italy, 

Spain and Romania. In the strategic reserve the TSO contracts targeted long-term reserve capacity via a 

tendering procedure to ensure access to so-called strategic reserves that serve as a back-up. This is 

currently used in (among others) Finland and Sweden, and is a key element of the German White Paper 

on the future design of the German electricity market. The capacity obligation is a decentralised approach 

in which an obligation is imposed on large consumers and on large suppliers to contract a certain level of 

capacity linked to their future consumption or supply respectively. Such a CRM has been adopted in 

France (including a market for capacity certificates) and Greece. Capacity auctions rely on voluntary 

participation via an auction instead of obligations and have been adopted in the UK and are planned in 

Interactions between electricity market reforms and climate policies 

 123 

 
 
 
 
 
 
Spain, Ireland and Italy. A reliability option CRM is a variant of the capacity auction system in which 

capacity contracts offered to generators have the form of a one-way call option. This mechanism was 

proposed in Italy. 

Most (proposed) CRMs focus on supporting future conventional capacity and pay relatively little attention 

to other flexibility options such as enhanced demand response, electricity saving, increased 

interconnection capacity, improved operation of balancing markets or enhanced ancillary services. Also 

the wider EMRs pay more attention to supporting conventional capacity than to other flexibility options. A 

narrow focus on enhancing supply capacity would risk increasing the share of oversupply on the market 

and/or the inefficient use of part of the production portfolio, risking possible further declining margins for 

some operators. The implied possible decreases in peak prices also reduce wholesale market incentives 

for other flexibility options. 

How do the (proposed) electricity market reforms and capacity remuneration mechanisms in 

the five countries analysed address the problems identified? 

The five countries analysed are considering different options for electricity market reforms including some 

form of CRM. Most electricity market reforms (EMRs) include a reference to the transition of the 

electricity sector to a higher share of renewables and/or to a low-carbon electricity supply. Specifically 
four out of the five30 (proposed) EMRs analysed in this study are said to support the increasing need for 

flexible capacity that is required to support the integration of an increasing share of renewables in the 

electricity system. Most systems refer to a selection of other flexibility options as being eligible for the 

CRM, but details are not worked out at a similar level to support future flexible capacity, or entry barriers 

exist that limit their access to the CRM. All countries analysed have continued plans to strengthen their 

(use of existing) interconnection capacity, although ENTSO-E (2014) reports that among others Poland 

(2% interconnectivity in 2014), the UK (6%) and Italy (7%) are currently still significantly below their 

targets. 

The UK capacity market is part of a wider electricity market reform and is the only capacity market 

analysed that has actually started. The model calculations have confirmed that there is currently a 

"missing money" problem concerning the profitability of new investments. The capacity market was 

designed to ensure security of electricity supply; specifically incentivising investments for new capacity 

and supporting capacity required to back up more intermittent and inflexible low-carbon generation 

sources. Capacity agreements will be auctioned annually. Demand-side options and storage in principle 

have equal access opportunities to be awarded but as pointed out by the Parliament’s Energy & Climate 

Change Select Committee the complex process and the relatively short contract length of capacity 

agreements is a disadvantage to smaller market players. Interconnection capacity was not eligible for the 

first UK capacity market auction but is said to be eligible from the second auction. The first auction 

resulted in clearing price of £19.4/kW/yr and a selection of mostly gas-fired and nuclear capacity. Two 

additional balancing reserves were introduced to target DSR, storage and power plants that are deemed 

necessary for reserve power and that would otherwise be closed or mothballed (assumed to be mainly 

gas-fired capacity). The model calculations on the UK market show that in that market the capacity 

payment may trigger some new investments in peaking plants and mid-merit plants, while revenues are 

not sufficient to make investments in new coal plants profitable. 

30 The exception is the French capacity market which was mainly designed to address the rapid growth of peak demand on the French market. 

Interactions between electricity market reforms and climate policies 

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Germany currently addresses system adequacy not by means of a market-wide capacity market; instead 

it has chosen a targeted capacity mechanism, introducing a cold reserve as safeguard. After some years 

of discussion, a Green Paper was issued in October 2014 identifying the need to adapt the market design 

in order to provide system adequacy as well as capacity adequacy in the future market with a growing 

share of intermittent renewable production. The Green Paper identifies and discusses several options for 

the organisation of the future electricity market, including several capacity market options, and concludes 

that a capacity reserve is needed, irrespective of the choice of future electricity market structure. The 

Green Paper also discusses several flexibility options other than a CRM that should be introduced, 

defining these as ‘no-regret measures’ that should be introduced irrespective of whether adequate 

capacity is available. The White Paper of July 2015 concludes that an energy-only market in combination 

with a capacity reserve for times when market forces fail to balance demand and supply would be the 

best way forward. The study calculations show that keeping all of the mid-merit capacity in the German 

market could be achieved by increasing payments for ancillary services to around €40/kW/year, a value 

that is lower than current frequency response service payments as part of the balancing mechanisms in 

the UK. 

The French capacity market will become effective on January 1st, 2017 (it is at the moment subject to 

ongoing investigation on State Aid by the European Commission). The capacity market was designed to 

address the fast growth in peak demand. Decarbonisation of the power sector is addressed since peak 

demand is mainly provided by natural gas, coal and fuel oil. The capacity market design takes into 

account the need to support demand response. The agreed capacity market will include a capacity 

obligation for all suppliers, including both demand and supply flexibility options and including all 

technologies. All capacity owners must have their production capacity and demand response potential 

certified, based on the ability to reduce loss of load during pre-defined peak hours. Certificates obtained 

can be traded on a certificate market and penalties will apply if a loss of load reduction cannot be 

provided. 

Poland currently has a cold intervention reserve and an operating power reserve service which can apply 

under certain conditions. It has identified two options for its envisaged capacity market, modelled along 

the UK and French examples. In the former option, said to be preferred by the Polish power sector, the 

Polish TSO would be the single buyer for flexibility on the Polish market. Poland envisages introduction of 

a capacity market to address the expected capacity gap. The Polish power producers expect that the CRM 

would also address the profitability problem. The envisaged capacity market is said to include all 

flexibility options, but discussions so far mainly concentrate on bringing additional incentives for existing 

supply-side capacity. The Polish government expects the CRM to start in 2018-2020. In addition, Poland 

had earlier introduced the concept of NegaWatts in which the Polish TSO closes contracts with large 

consumers for the option to temporarily curtail their demand at times of risks of system unbalance. 

Italy has decided to replace its current capacity payment system by a reliability option capacity market 

by 2017. The new system was proposed in order to trigger sufficient investments in new capacity, which 

the current capacity payment system does not achieve. The reliability capacity market will be a voluntary 

market in which power producers can sell their capacity options to cover the back-up capacity required by 

the TSO. Participation is limited to so-called programmable capacities (supply options that can be 

Interactions between electricity market reforms and climate policies 

 125 

 
 
 
 
 
switched on and off) that are not subject to any type of investment incentive scheme and that are not 

subject to any dismantling measures approved by competent authorities. 

How could the (proposed) capacity markets influence the decarbonisation of the power 

sector?  

In most current discussions capacity markets are considered to influence decision making on maintaining 

existing capacity as well as on investment in new capacity, especially plants providing firm capacity. As 

such it could also impact the decarbonisation of the power sector when influencing dispatch (and 

therefore the emissions associated with the plants that are dispatched) and investment (and therefore 

future emissions). The actual impact will depend on the specific design of the capacity market, the 

capacity mix on the specific market, and the supporting policies. This combination will determine whether 

lower-carbon options will displace more carbon-intensive options or the other way around. 

The five (proposed) capacity markets analysed could have the following impacts and risks to the 

decarbonisation of the power sector: 

 

The proposed UK electricity market reforms could lock existing and new gas-fired capacity in the 

market for a long period of time. A similar risk could hold for existing coal-fired capacity. For new 

coal-fired capacity, which is not economically viable even with the capacity market under current 

UK market conditions, there is no risk of lock in. Furthermore it would technically not be possible 

given that the UK energy market reforms include an emissions performance standard which de-

facto blocks new coal-fired capacity to be brought to the market. The lock-in of fossil capacity 

would slow down the development of low-carbon options - both on the demand and supply sides – 

required to improve capacity adequacy. Based on only the first auctioning some risks can be 

highlighted: only 0.35% of the awarded capacity agreements are demand-side responses, 5.5% 

are storage, 1.4% are hydro-power capacity and 16% are nuclear capacity. The remaining share of 

capacity (76.8%) is biomass and fossil-fuelled production capacity.31 

 

Final decisions for the German electricity market have not yet been made, but the proposal as 

formulated in the White Paper does not include a market-wide capacity market, but a targeted 

capacity mechanism (strategic reserve). If a capacity market would be established, it could entail 

similar risks as identified for the UK market. Moreover, a capacity market in Germany might also 

risk locking in existing coal-fired plants, with lower efficiency and higher carbon emissions than 

other supply options.  

 

The limitation to programmable capacities in the new Italian capacity market holds a risk to the 

decarbonisation of the power sector as it will set other flexibility options at a competitive 

disadvantage compared to supply options, including carbon emitting technologies. Also this 

capacity market could lock-in specific types of plants and, depending on the carbon intensity of 

production from these plants, the impact on the decarbonisation of the sector could be positive or 

negative. 

31 The total share of biomass and coal-fired capacity is 18.7%. No split-is provided between the share of coal and biomass, most likely as some of 
the awarded capacity is co-firing of biomass in coal-fired plants. 

Interactions between electricity market reforms and climate policies 

 126 

 
 
 
 
 
 

The envisaged capacity market could have a significant negative impact on the decarbonisation of 

the Polish electricity sector since the capacity market could prolong the lifetime of existing, less 

efficient power stations that would otherwise be closed or mothballed and could risk stimulating 

investments in higher carbon production instead of lower-carbon production and/or other supply 

(for example imports) or demand-side options. Details of the envisaged capacity market, however, 

are not yet revealed so it is unclear whether these potential negative impacts would actually occur. 

 

The impact of the proposed capacity market on the decarbonisation of the French electricity 

sector will be very different to that in other countries, given France’s current high share of 

carbon-free power production (92% in 2013) and the fact that thermal plants are mostly used as 

semi-base or peak load whereas nuclear and run-of-river hydro plants are used in a baseload 

mode. The main risk to decarbonisation would be that the capacity market would incentivise 

thermal plants to such an extent that they could offer baseload capacity at prices that are 

competitive to the current baseload plants. If that would be the case then carbon-free production 

would be pushed out by production with carbon emissions. It is, however, not very likely that the 

incentives from the capacity market would be sufficient to reach such a competitive position so 

those risks are assumed to be small.32 

32 However, the decentralised obligation based design of the French capacity market might risk posing a barrier of entry for independent capacity 
providers and might impact the choice between different low-carbon technologies. 

Interactions between electricity market reforms and climate policies 

 127 

 
 
 
12 »  Conclusions and further work 

The study confirms that there are challenges for the current configuration of electricity systems and the 

current organisation of electricity markets in the countries analysed. For example, the growing share of 

renewables and the declining margins for established forms of generation may result in system and 

capacity adequacy problems. 

The qualitative analysis has shown that the interaction of electricity market reforms and climate policies 

is complex and multifaceted. It is not straightforward to answer if strengthened energy-only markets 

(including ancillary services and carbon prices) will be able to provide sufficient incentives for new 

investments. Different national markets are faced by different types of problems. Therefore a good 

problem and system assessment based on sufficiently detailed data is necessary, but the data are not 

always available. 

A purpose-built model was developed to further analyse the impact of variations and design options on 

the electricity market. It combines a dispatch model based on short-run marginal costs with a financial 

revenue model based on current variable and O&M costs and revenues and annualised capital costs. The 

model provides results on plant profitability, electricity price developments and dispatch hours, leading to 

first-order conclusions on the revenues from the energy-only market. In a next step further potential 

revenues from ancillary services have been determined on the basis of expense data and known revenue 

streams in current existing markets. The model was also applied to quantify the impact of higher carbon 

prices and of introducing flexibility options on various plant types and the electricity system as a whole. 

Finally, conclusions have been drawn on the resulting impact of market developments on the key energy 

and climate policy objectives analysed in this study. 

The quantitative analysis does not aim to give exact predictions of market prices or individual plant level 

valuations, notably because it did not take into consideration investment incentives from price peaks, but 

can inform on the overall economic performance of technologies and give first indications to what extent 

the considered market reforms may impact on achieving key objectives or bringing in further risks to 

achieving these objectives. 

The quantitative analysis confirms the profitability problem for gas producers in current markets. It also 

cannot exclude future problems to operate profitably if revenues would only be generated through 

wholesale markets with price formation based on the merit order. With regard to future trends, the 

analysis indicates that higher shares of renewables could further accentuate problems with profitability, 

while higher carbon prices reduce them. However, the potential incentive effects from price peaks to 

flexible forms of generation have not been fully modelled. The model calculations show that higher 

carbon prices can be an effective option that combines the needs for system adequacy with facilitating 

further growth of renewables. Also revenues from ancillary services and balancing markets, on top of 

revenues from wholesale markets, clearly have a positive impact on profitability and, as such, system 

and capacity adequacy. Nevertheless some model results indicate that risks for investment incentives 

may remain under certain market conditions. 

Interactions between electricity market reforms and climate policies 

 128 

 
 
  
 
 
 
 
The current debate on strengthening European power markets has a strong focus on introduction of 

capacity markets to strengthen investment incentives in assets providing firm production capacity. This 

focus is too narrow and risks negative impacts on decarbonisation, as well as locking out other flexibility 

options that may be vital for the longer-term organisation of the power sector to ensure sufficient system 

and capacity adequacy and facilitate the decarbonisation of the power sector and the continued growth of 

the share of renewables. Further efforts can be made to strengthen energy markets, including through 

carbon markets, as well as to strengthen flexibility via other options than supply-side flexibility. In the 

study the full extent of additional flexibility services or scarcity pricing was not included in the scope of 

analysis and consequently firm conclusions could not be drawn. Further model elaboration and 

corresponding analysis is recommended to understand the full opportunities of improved system 

balancing, and interactions with decarbonisation policies. 

Interactions between electricity market reforms and climate policies 

 129 

 
 
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Tennbakk (2013): Tenbakk, Dr. B., et al, Capacity Mechanisms in individual Markets within the IEM, 

report for the European Commission, DG Energy, June 2013. 

Tennet (2014): The Netherlands benefits from closer cooperation with German energy market, news 

published 16 January 2014, available at http://www.tennet.eu/nl/en/news/article/the-netherlands-

benefits-from-closer-cooperation-with-german-energy-market.html 

 

Terna  (2014b):  Terna  Strategic  Plan  2014-2018,  downloaded  from  www.slideshare.et/ternaspa/fy2-

13-and-20142018-strategic-plan--march-25-2014 

  Wärtsilä (2014): Combustion Engine vs Gas Turbine: Ramp Rate, available at 

http://www.wartsila.com/en/power-plants/learning-center/overview/combustion-engine-vs-gas-
turbine-ramp-rate, accessed June 2nd, 2014. 

Interactions between electricity market reforms and climate policies 

 132 

 
 
 
 
 
Annex 1: Qualitative direct impact analysis  

The tables included in this Annex provide an analysis on the main direct influences of the 7 types of 

market factors identified that impact the electricity market. The tables show the direct influence of a 

market factor on each of the four electricity system impact indicators distinguished (system adequacy, 

capacity adequacy, decarbonisation of the electricity sector and the share of renewables). The tables 

provide the direction of the impact and do not aim to indicate the size of the impact, nor do they aim to 

provide a full analysis of all potential impacts. The information in these tables is complemented by the 

quantitative analysis conducted with the purpose-built tool, leading to a more in-depth understanding of 

the full set of impacts. 

The tables include:  

 

 

 

 

 

 

 

Table 21: Impact analysis of business operation factors 

Table 22: Impact analysis of business finance factors 

Table 23: Impact analysis of market demand factors 

Table 24: Impact analysis of market design factors 

Table 25: Impact analysis of exogenous market factors 

Table 26: Impact analysis of EU supporting policies 

Table 27: Impact analysis of financial market response factors (intermediate indicators) 

Interactions between electricity market reforms and climate policies 

 133 

 
 
 
 
 
 
Table 21 » Impact analysis of business operation factors on the four main EU energy and climate policy 
objectives  

Influencin
g factor 
Business operational factors 

System adequacy  Capacity adequacy 

Decarbonisation 
electricity sector 

Growing share 
of renewables 

Improved 
operation 
of nuclear 
power 
plants 

Positive impact 
when these nuclear 
power plants 
operate as base 
load 

Positive impact if it results in 
larger available generation 
capacity. 
[Potential negative impact if 
nuclear power plants are 
phased out and no other 
actions are taken to improve 
capacity adequacy] 

Maintaining 
coal-fired 
production 
capacity 

Maintaining 
gas-fired 
production 
capacity 

Positive impact in 
system balancing, 
especially in case 
of large fluctua-
tions and/or high 
share of intermit-
tent capacity  

Positive impact in 
the balancing of 
systems, especially 
in case of large 
demand 
fluctuations and/or 
high share of 
intermittent 
capacity  

Positive impact. As it 
provides a larger capacity 
base 

Positive impact. As it 
provides a larger capacity 
base 

Maintaining 
storage 
capacity 

Positive impact in 
the balancing of 
systems 

Positive impact because it 
reduces the need of reserve 
margin. 

Positive impact if the 
improved operation of 
nuclear power plants 
displaces fossil-fuelled 
generation. 
[Potential negative 
impact if nuclear 
power plants are 
phased out and (part 
of) production is 
taken up by existing 
fossil-fuel based 
capacity] 

Negative impact, 
though possibility of 
co-firing biomass may 
lead to partial 
decarbonisation  

Negative impact 
unless the gas plants 
are replacing plants 
with higher intensity 
of emissions (for 
example coal-fired 
plants). [potential 
positive indirect 
impact when 
facilitating higher 
integration of 
renewables] 
Positive impact as it 
may prevent the 
operation of fossil fuel 
fired plants during 
peak hours  

Negative impact 
in cases where 
renewables do not 
have priority 
dispatch and 
would need to 
compete against 
nuclear electricity. 
No apparent 
impact in case of 
priority dispatch 
for renewables. 

Potential negative 
impact where 
renewables do not 
have priority of 
dispatch and 
compete against 
coal-fired plants  

Negative impact, 
unless this 
capacity is 
maintained to 
stabilise system 
adequacy to 
facilitate an 
increasing share 
of renewables 

Positive impact 
when the storage 
is achieved with 
the use of 
renewables 

Improved 
operation 
of non-
intermit-
tent 
renewables 
capacity 

Improved 
operation 
of intermit-
tent 
renewables 
capacity 

Positive impact as 
it contributes to 
the balancing of 
systems 

Potential negative 
impact as a larger 
share of 
intermittent 
production may 
affect system 
balancing 

Positive impact as this 
capacity is non-intermittent 

Positive impact due to 
potential larger supply 
from renewables at 
the expense of fossil 
fuel based production  

Positive impact 
due to potential 
larger supply from 
renewables  

Potential negative impact. A 
larger share of intermittent 
production may reduce 
wholesale prices and can 
reduce the load hours of 
mid-merit and peaking gas 
units. This could increase the 
"missing money problem" 

Positive impact when 
displacing fossil 
fuelled production 
capacity (especially 
where they have 
priority of dispatch) 

Positive impact 
due to potential 
larger supply from 
renewables 
(especially where 
they have priority 
of dispatch) 

Interactions between electricity market reforms and climate policies 

 134 

 
 
 
and therewith may result in 
the shutdown of these plants  

Table 22 » Impact analysis of business finance factors on the four main EU energy and climate policy 
objectives  

Influencing 
factor 

System 
adequacy 

Capacity 
adequacy 

Business financial factors 

Decarbonisation 
electricity 
sector 

Growing share of 
renewables 

Improved 
economics 
of fossil-
based 
capacity 

Positive impact 
as improved 
economics of 
existing fossil-
based capacity 
may help 
maintaining this 
capacity for 
system 
balancing.  

Positive impact 
when improved 
economics help 
maintaining the 
fossil fuel based 
production 
capacity 

Negative impact if 
improved 
economics results 
in larger use of 
this capacity, 
especially in case 
of coal-fired plants 

Improved 
economics 
of storage 
capacity 

Positive impact. 
Storage systems 
contribute to 
system 
adequacy 

Positive impact. 
Storage systems  
reduce the need 
of extra reserve 
margin 

Improved 
economics 
of 
renewable-
based 
capacity 

Potential 
negative impact 
when it results 
in a larger share 
of  intermittent 
supply and no 
other actions for 
securing system 
adequacy are 
taken 

Potential 
negative impact. 
as fossil fuel 
based capacity 
may be pushed 
away in the 
merit order; this 
may result in 
lower income for 
existing reserve 
margin units 
that may end up 
shutting down 

Positive impact as 
it helps 
maintaining 
storage capacity 
and reducing the 
production from 
fossil fuel fired 
plants 

Positive impact as 
it may increase 
the supply share 
from renewables 
at expense of 
production from 
fossil fuel fired 
plants  

Potential negative 
impact for renewables 
with higher marginal 
costs in case these 
would not have priority 
dispatch.      – Neutral 
impact in case of priority 
dis-patch for 
renewables. 

Positive side-effect in 
case of maintaining coal 
plants that would be 
growing its share of 
biomass co-firing   

Positive impact as it 
contributes to a larger 
share of supply from 
renewables 

Positive impact as it 
may increase the supply 
share from renewables 

Interactions between electricity market reforms and climate policies 

 135 

 
 
 
 
Table 23 » Impact analysis of market demand factors on the four main EU energy and climate policy objectives  

Influencin
g factor 

System 
adequacy 

Market demand factors 

Capacity adequacy 

Decarbonisati
on electricity 
sector 

Growing 
share of 
renewables 

Change in 
electricity 
demand 

- Negative 
impact in case of 
sudden growth 
of electricity 
demand as it 
may cause 
severe stability 
problems. 
Impact is 
worsened when 
the unexpected 
growth of 
demand 
coincides with a 
strong growth in 
intermittent 
production 

- Negative 
impact in case of 
a change of 
expectations 
(from high to low 
demand) as it 
may aggravate 
the "missing 
money problem" 

Change in 
electricity 
demand 

- Negative 
impact in case of 
sudden growth 
of electricity 
demand as it 
may cause 
severe stability 
problems. 
Impact is 
worsened when 
the unexpected 
growth of 
demand 
coincides with a 
strong growth in 
intermittent 
production 

Table 24 » Impact analysis of market design factors on the four main EU energy and climate policy objectives 

Influencing 
factor 

System 
adequacy 

Capacity 
adequacy 

Market design factors 

Decarbonisation 
electricity 
sector 

Growing 
share of 
renewables 

Retail price 
regulation 

Merit order 
rules 

Negative 
impact when 
price caps limit 
the possibility 
of cost recovery 
by the flexible 
and peaking 
units that are 
needed to 
balance the 
system 

Potential 
negative 
impact; merit 
order rules may 
limit the 
possibility of 
cost recovery 
by flexible and 
peaking units 
that are needed 
for balancing 
the system 

Negative impact 
when price is 
influenced by 
market 
interventions. 
These 
interventions 
increase the 
"missing money 
problem" and 
affect decisions 
on new needed 
investments 

Potential negative 
impact; low 
electricity prices 
do not promote 
demand-side 
response. This 
may cause that  
fossil fuel fired 
plants down in the 
merit order 
operate to cover 
extra electricity 
demand 

Potential 
negative impact 
when merit 
order rules 
produce 
inadequate 
investment 
signals 

Positive impact 
when merit order 
rules favours the 
operation of low 
carbon generation 
capacity 

Potential 
negative impact; 
low electricity 
prices do not 
promote 
demand-side 
response. This 
may cause that 
fossil fuel fired 
plants down in 
the merit order 
operate to cover 
extra electricity 
demand 

Positive impact 
when merit 
order rules 
favour the 
operation of 
renewable 
capacity (for 
example with 
priority of 
dispatch) 

Interactions between electricity market reforms and climate policies 

 136 

 
 
 
Table 25 » Impact analysis of exogenous market factors on the four main EU energy and climate policy 
objectives 

Influencing 
factor 

System 
adequacy 

Capacity 
adequacy 

Decarbonisation 
electricity sector 

Growing share of  

renewables 

Exogenous market factors 

Economic 
growth  

Increase in 
fuel prices  

Increase in 
carbon 
prices 

Similar 
impact as for 
electricity 
demand; 
economic 
growth 
directly 
affects 
electricity 
demand 

Negative 
impact on the 
economics of 
fossil fuel 
power plants, 
which may 
lead to early 
retiring. In 
case of 
retiring 
flexible, mid-
merit  
capacity this 
will 
negatively 
impact 
system 
adequacy  

Potential 
indirect 
positive 
impact; high 
carbon prices 
may seriously 
affect the 
economic 
competitiven
ess of coal-
fired power 
plants, which 
will benefit 
the economic 
feasibility of 
flexible plants 

The same as 
for electricity 
demand; 
economic 
growth directly 
affects 
electricity 
demand 

Negative 
impact as 
changes in fuel 
prices are 
difficult to 
predict, 
therefore a 
source of 
uncertainty for 
new 
investments 

Potential 
positive 
impact; while 
higher carbon 
prices may 
seriously affect 
the economic 
competitivenes
s of new coal-
fired power 
plants, other 
flexible power 
plants suitable 
for margin 
reserve (and 
less carbon 

The same as for 
electricity demand; 
economic growth 
directly affects 
electr. demand 

The same as for 
electricity demand; 
economic growth directly 
affects electricity 
demand 

Positive impact as 
it improves the 
competitive 
position of non-
fossil fuel plants, 
i.e. low-carbon 
capacity 

Potential negative 
impact when 
increased gas 
prices would result 
in a switch from 
gas to coal 

Positive impact at it 
improves the competitive 
position of renewables 
against fossil fuelled 
plants.  

Potential positive side 
effect for biomass when  
coal prices are low and 
improve the economics 
of biomass co-firing in 
coal-fired power plants 

Positive impact 
when carbon prices 
reach a level that 
impacts the 
operation of coal-
fired plants and 
increases the 
revenues of less 
carbon intensive 
plants 

Positive impact, as high 
carbon prices could 
further promote the 
switch and investments 
from carbon intensive 
capacity to renewables 

Interactions between electricity market reforms and climate policies 

 137 

 
 
 
 
intensive) may 
see their 
revenues 
increase. 

Positive 
financing 
impact for all 
inframarginal 
low-carbon 
capacity 

Positive impact 
from cross-
border trade as 
the reserve 
margin is 
shared 

suitable for 
balancing the 
system (e.g. 
gas-fired 
power plants) 

Positive 
impact as 
resources for 
system 
balancing are 
shared 
between 
countries and 
the risks of 
intermittency 
due to 
weather 
conditions are 
mitigated 

Increase in 
import/-
export 
capacity 

Potential positive 
impact from 
possibility to 
increase 
import/export of 
electricity produced 
in less carbon 
intensive plants 
abroad  

Positive impact from 
increased possibility to 
import/export higher 
share of electricity 
produced from 
renewables, with low 
marginal costs. 
Import/exports also 
decrease the risks of 
intermittency due to 
weather conditions 

Interactions between electricity market reforms and climate policies 

 138 

 
 
 
Table 26 » Impact analysis of EU supporting policies on the four main EU energy and climate policy objectives 

Influencing 
factor 

System adequacy 

Capacity adequacy 

Decarbonisation 
electricity sector 

Growing share of 
renewables 

EU supporting policies 

Strengthening 
renewable 
electricity policy 

Strengthening 
energy efficiency 
policy 

Potential negative 
impact. 

Renewable electricity 
policy supports the 
competitiveness of 
renewables in general, 
including the intermittent 
ones. A higher share of 
intermittent capacity 
may negatively impact 
system adequacy 

Potential negative 
impact. Energy efficiency 
reduces electricity 
demand and it may 
therefore reduce 
revenues for gas-fired 
power plants that 
operate to balance 
systems. Quantitative 
analysis is required 
though to determine the 
level of impact as lower 
electricity demand also 
requires less balancing 
needs   

Potential negative 
impact if the support 
to renewable 
electricity jeopardises 
investments for 
granting capacity 
adequacy in the 
system. Quantitative 
analysis is required to 
further check the 
impacts of a specific 
policy 

When policy is 
successful and 
demand is lowered this 
could have positive as 
well as negative 
impacts. 

Negative: lower 
demand may 
aggravate the “missing 
money problem” in 
current plants that 
operate as reserve 
margin and puts them 
into risk of shutdown.  

Negative: lower 
demand may affect 
the economic 
feasibility of future 
investments that are 
needed for capacity 
adequacy.  

Positive: lower 
demand reduces need 
for new capacity 

Strengthening  
the EU ETS  

Potential indirect positive 
impact when EU ETS 
results in higher carbon 
prices. See impacts of 
"Increase in carbon 
prices"  

Potential positive 
impacts when EU ETS 
results in higher 
carbon prices. See 
impacts of “Increase in 
carbon prices”. 

Positive impact 
when policy is 
successful. 
Renewable energy 
effectively replaces 
higher carbon 
options 

Positive impact 
when policy is 
successful. Lower 
electricity demand 
may result in less 
electricity 
production from 
fossil fuel fired 
plants, especially 
where renewables 
have priority of 
dispatch.  

- Potential indirect 
negative impact 
when lower demand 
leads to lower 
electricity prices. 
Low-carbon 
technologies with 
higher financing 
needs could 
therefore be 
negatively affected. 

Positive impact 
when EU ETS results 
in a level of carbon 
prices that impacts 
the operation of 
coal-fired plants and 
increases the 
revenues of less 
carbon intensive 
plants 

Positive impact when 
policy is successful 

Positive impact when 
policy is successful. 
Lower electricity demand 
may result in a larger 
share of renewables, 
especially where they 
have priority of dispatch.  

Positive impact when EU 
ETS results in higher 
carbon prices that could 
further promote the 
switch from carbon 
intensive capacity to 
renewables  

Interactions between electricity market reforms and climate policies 

 139 

 
 
 
 
Table 27 » Impact analysis of financial market response factors (intermediate factors) on the four main EU energy and 

climate policy objectives 

Influencing 
factor 

System 
adequacy 

Capacity 
adequacy 

Financial market response factors 

Decarbonisation 
electricity 
sector 

Growing 
share of 
renewables 

Increase in 
wholesale 
electricity 
price 

Positive 
impact. 
Higher 
wholesale 
electricity 
prices 
reduce the 
economic 
pressure on 
fossil fuel 
fired plants 
that mainly 
operate to 
balance the 
system 

Positive impact. 
Higher 
wholesale 
electricity 
prices reduce 
the possibility 
of shut-down or 
mothballing 
fossil fuel fired 
plants 
(especially gas-
fired plants) 
that are needed 
as reserve 
margin 

Impacts will 
largely depend on 
the existence of 
support 
mechanisms for 
low carbon 
technologies (e.g. 
subsidies, 
premiums, feed-
in tariffs, etc.). 
Quantitative 
analysis is 
required to 
further determine 
impacts on a 
specific system 

Investments 
in new fossil 
fuel 
capacity, 
import and 
storage 
capacity 

Positive 
impact as 
this type of 
investments 
contribute to 
the 
balancing of 
systems 

Positive impact 
as this type of 
investments 
improve 
capacity 
adequacy  

Impacts depend 
on what specific 
investments are 
made. New fossil 
fuel capacity will 
have a negative 
impact, storage 
capacity will have 
a positive impact. 
Imports would 
require 
quantitative 
analysis to 
determine if 
impacts are 
positive or 
negative 

Impacts will 
largely depend 
on the 
existence of 
support 
mechanisms 
for renewables 
(e.g. 
subsidies, 
premiums, 
feed-in tariffs, 
etc.). 
Quantitative 
analysis is 
required to 
further 
determine 
impacts on a 
specific system  

Impacts 
depend on 
what specific 
investments 
are made. New 
fossil fuel 
capacity will 
have a 
negative 
impact, 
storage 
capacity will 
have a positive 
impact. 
Imports would 
require 
quantitative 
analysis to 
determine if 
impacts are 
positive or 
negative 

Interactions between electricity market reforms and climate policies 

 140 

 
 
 
Annex 2: Model inputs 

This Annex contains further details to the description of inputs for the purpose-built tool introduced in 

Chapter 5 ». As explained in this Chapter, the model is an optimisation model consisting of two modules: 

a dispatch module, based on a static merit order of the electricity market, and a financial analysis 

module. The dispatch calculation is based on short-run marginal cost bidding and uses the demand profile 

of a country, the generation capacity breakdown, cost and performance of technologies and the data 

around wind and solar availability. It estimates the run hours of each plant, the electricity-only revenues 

of each plant and the periods lacking flexible operating plants. These intermediate outputs are used to 

perform the general financial analysis of plant investment incentives, analysing the impact on the plant 

economics, the resulting incentives for investment decisions and therewith the future generation mix, and 

the impact on the decarbonisation of the electricity sector and the share of renewables in the electricity 

supply mix. 

The main model inputs and assumptions include: 

  Demand is an exogenous factor to the model based on existing scenarios and inelastic to price 

fluctuations. The model uses an hourly demand profile; 

  Supply: Where available, plants are modelled according to their actual plant data such as starting 

year of operation, lifetime, efficiency, investment costs per MW and operational costs per MW and 

per MWh. Plants are modelled in a static way. Production-based dynamic aspects are not included 

in the model. This includes ramp rates, minimum up and down time, part load efficiency derating 

(i.e. efficiencies that are lower at low production rates) and minimum stable generation; 

  Network: The network capacity modelled is based on the ENTSO-E ten-year development plans. 

Transmission limits such as location and congestion are not explicitly modelled. Network stability 

issues - such as whether sufficient spare capacity in flexible generation is available for frequency 

support - is not modelled, but conclusions on this are drawn on the basis of the model outputs (i.e. 

some model outputs will reveal a system that in the real market would be deemed insufficient); 

 

Flexibility: The impact of demand-side flexibility services (e.g. demand response) and 

interconnectors are taken into account in the demand scenarios. 

A2.1  Choice of baseline scenario 
The choice of baseline scenario is an important starting point in the specification of model inputs. Broadly 

speaking, three main options were considered as that starting point: 

1.  National energy and climate scenarios developed by government institutes of the EU Member 

States; 

2.  The EU energy policy scenarios developed with the PRIMES model (EU Reference scenario 2013); 

3.  The energy demand scenarios used by ENTSO-E in their Ten Year Development Plan. 

Interactions between electricity market reforms and climate policies 

 141 

 
 
 
 
 
To determine the preferred choice of scenario for this study we analysed the scenarios based on the 

following questions: 

  Consistency: Is the projection set determined on a consistent basis across Member States, so that 

input assumptions and data cut-off points are the same? 

  National relevance: Is the projection set relevant to the national situation? Does it explain the 

rationale behind scenario assumptions, specifically behind the electricity market reforms? 

 

Input data sufficiency: Are there enough data in the projection set to inform the model analysis? 

  New build capacity: Does the projection set offer a split between existing capacity and new build 

capacity, rather than just providing total capacity in a given year? 

  Ease of data collection: How easy is it to collate and use the data? 

 

Frequency (time step): Does the projection set include annual projections or at least five-yearly 

projections? Are projections available for the years 2020 and 2030? 

  Other factors: Are there other factors which lend preference to a particular set of projections? 

Some countries have several different national scenarios, specified by different national government 

institutes or agencies. A selection of these scenarios for Germany and the UK, and a comparison between 

these scenarios is included in One of the main drawbacks of most scenarios was that insufficient 

distinction was made between existing plants and new plants that are assumed to be built during the 

projection period. This was considered a major drawback since one of the key questions in the study is 

whether the electricity market provides sufficient incentives for new investments. To determine this 

accurately it is necessary to have a solid estimate of which existing production plants are assumed to 

stay in business and which are assumed to be closed and/or mothballed. As a result of this drawback, the 

EU Reference scenario developed with the PRIMES model was considered the most appropriate starting 

point. Other benefits of using these scenarios include the comparability across Member States and the 

availability of at least five-year interval projections. Some national scenarios provided more detailed 

estimates but unfortunately these were not available for all countries included in the study. 

The major caveat of using EU-level projections is that they sometimes show large differences when 

compared to the national projections. In these situations sensitivity analysis around these differences can 

help understand the impact of the different starting assumptions. 

, Table 29 and Table 30 below. One of the main drawbacks of most scenarios was that insufficient 

distinction was made between existing plants and new plants that are assumed to be built during the 

projection period. This was considered a major drawback since one of the key questions in the study is 

whether the electricity market provides sufficient incentives for new investments. To determine this 

accurately it is necessary to have a solid estimate of which existing production plants are assumed to 

stay in business and which are assumed to be closed and/or mothballed. As a result of this drawback, the 

EU Reference scenario developed with the PRIMES model was considered the most appropriate starting 

point. Other benefits of using these scenarios include the comparability across Member States and the 

availability of at least five-year interval projections. Some national scenarios provided more detailed 

estimates but unfortunately these were not available for all countries included in the study. 

Interactions between electricity market reforms and climate policies 

 142 

 
 
 
 
 
 
The major caveat of using EU-level projections is that they sometimes show large differences when 

compared to the national projections. In these situations sensitivity analysis around these differences can 

help understand the impact of the different starting assumptions. 

Table 28 » Evaluating different options for selection of the baseline scenario 

Criteria 

National 
(2020/2030) 

EU Reference scenario 2013 
(2020) 

ENTSO – E 
(EU 2020) 

Consistency 

Inconsistent 

Consistent 

National 
relevance 

Input data 
sufficiency 

Most relevant 

Least relevant 

Variable: Good to 
poor 

Very good 

New capacity 
build 

Not trivial to 
determine 

Part of projection 

Difficult and variable 

Collected 

Consistent 

Medium 
relevance 

Good 

No 

Collected but 
definitions not 
always clear 

Variable, some 
annual some static 
for 2020/30 

Varies, but often 
includes consistent 
demand data 

Five yearly 

Static 2020 

Future electricity cost provided. 
Consistent demand data. Wide 
range of other input data, e.g. 
fuel prices, carbon prices 

Additional system 
data, but limited 
demand data 

Ease of data 
collection 

Frequency 
(time step) 

Other factors 

Table 29 » Scenario input comparison for Germany 
Capacity type 

UK – DECC (2020) 

Coal 

Gas 

Nuclear 

15.0 

34.8 

10.7 

EU Reference 
scenario 2013 
(2020) 
7.2 

48.9 

3.7 

UK – ENTSO E 
(conservative ; 2020) 

19.8 

35.3 

9.5 

Renewables 

37.8 (no further detail) 

49.0 (6 technologies) 

28.0 (5 technologies) 

Interactions between electricity market reforms and climate policies 

 143 

 
 
 
 
 
 
 
 
 
 
 
Interconnector 

Pumped storage 

5.5 

2.8 

Peaking 

CHP 

CCS 

Total 

Not stated 

Not stated 

0.6 

Not stated 

Not stated 

Not stated 

7.2 Gwe 

Not stated 

5.2 

Not clearly stated 

Not stated 

Not stated 

Not stated 

93.4 (net) 

107.8 (incl. interconnector)  108.8 

Table 30 » Scenario input comparison for the United Kingdom 

Capacity type 

DE – TSO (2020) 

EU Reference 
scenario 2013 
(2020) 

DE – ENTSO E 
(conservative 2020) 

Coal 

Gas 

Nuclear 

43.6 

31.9 

0.0 

Renewables 

138.7 

Interconnector 

Not stated 

Pumped storage 

10.9 

Peaking 

CHP 

CCS 

Total 

Not stated 

Not stated 

Not stated 

230.9 

45.0 

29.4 

6.8 

103.2 

Not stated 

Not stated 

Not stated 

7.2 

Not stated 

192.9 

38.2 

32.5 

8.1 

128.2 

30.5 

Not clearly stated 

Not stated 

Not stated 

Not stated 

236.7 

A2.2  Demand and generation profiles 
The hourly demand profiles used in the model are based on historic hourly consumption profiles and 

projected annual consumption over the forecast period. Based on linear scaling on an hourly basis, this 
results in a total gross demand profile for each year.33 

The next set of input data include the interconnector capacities and the fraction available for reserve, the 

historic use profile for imports and exports via the interconnectors, the demand response capacities and 

the pumped hydro storage capacity. 

The generation profile produced by the model distinguishes various plant types. The fossil-fuelled plant types included 
are: coal plants (current, new, future, CCS), lignite plants (current), conventional gas, CCGT (current, new, 
future, CCS), OCGT and nuclear plants. For renewable electricity generation the plant types included are: wind 
onshore, wind offshore, photovoltaic, solar concentrated power, geothermal electricity and electricity from 
biomass. Co-firing of biomass in coal-fired power plants in the model is included in this latter category.34  

33 This assumption is justified by the purpose of using this model not for identifying balancing or dispatch at a specific moment in time, but rather 
over an entire year. 
34 Technically and operationally this is a very different option but in the modelling it is included in the category large scale biomass plants. 
Separate modelling of dedicated large-scale biomass plants and co-firing of biomass in coal fired power plants would include slightly different 
efficiency factors but the separate modelling would not materially impact overall results. Consequently this was not included in the modelling. 

Interactions between electricity market reforms and climate policies 

 144 

 
 
 
 
 
 
 
 
 
 
Table 31 lists the input data required on an annual basis for each of these plant types. Where further 

detailed data are available the modelling is carried out at individual plant level, each with its own 

technical specification and cost data. 

Table 31 » Model input data per type of plant 

Fossil-fuelled plant types 

Non-intermittent 
renewable electricity plant 
types 

Intermittent 
renewable electricity 
plant types 

• 

Net capacity (MW) 

Fixed OPEX costs (€/MW) 

Capacity in historic year 

Hourly load profile 
historic years (or for PV 
irradiation profile) 

Projected future 
capacity (MW) 

Net efficiency (MWh out / 

• 
MWh in) 

• 

• 

Fuel type 

Fixed OPEX costs (€/MW) 

Variable OPEX costs (€/MWh) 

Investment costs (€/MW) 

Economic lifetime and age of 
existing plants (years) 

Availability 

Capacity credit (Required rate 
of return or borrowing rate in 
%, including risk premium) 

Variable OPEX costs 

• 
(€/MWh) 

• 

Investment costs (€/MW) 

Economic lifetime and age 

• 
of existing plants (years) 

Must run load profile (%) 

• 
and run hours 

Availability (planned and 

• 
unplanned outages, % of annual 
load hours) 

Capacity credit (required rate of 

Interactions between electricity market reforms and climate policies 

 145 

 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
Fossil-fuelled plant types 

return or borrowing rate in %, 
including risk premium) 

Non-intermittent 
renewable electricity plant 
types 

Intermittent 
renewable electricity 
plant types 

A2.3  Detailed modelling assumptions: fuel prices and plant data 
Table 32 provides the assumed costs of input sources in €/MWh 

Table 32 » Costs of input (fuel) source (in €/MWh) 
Input (fuel) source  2010  2020  2030  Source 
22.30  36.20  38.00  PRIMES* 
Gas 
35.29  52.10  54.80  PRIMES 
9.40  13.30  14.10  PRIMES 

Oil 
Coal 

Lignite 
Nuclear 

Biomass 
CO2 

7.80 
5.11 

8.32 
5.11 

8.51  PRIMES 
5.11  Mott McDonald  

9.40  12.90  13.30  2013 Argus pellet price (€130/tonne, 5 MWh/ton) 
11.20  10.00  35.00  PRIMES 

*: PRIMES refers to the PRIMES modelling assumptions as included in the EU Reference scenario 2013. 

The 18 tables on the following pages provide detailed plant input data for respectively the UK, Germany 

and Poland, for the years 2010, 2020 and 2030. 

Interactions between electricity market reforms and climate policies 

 146 

 
 
 
 
  
Table 33 » Detailed plant input data for the UK, 2010 – part I 
Efficiency 
Technolog / 

Efficiency 

Must 

fuel 

run 

(max) 

(min) 

Availability 

Variable operating cost 

(€/MWh) 

Peaking oil 

Gas 

Gas old 

Coal old 

Nuclear old 

Biomass 

Gas CHP 

CoalCCS 

Nuclear new 

GasCCS 

Coal 

Hydro 

Solar 

Wind - onshore 

Wind - offshore 

0 

0 

0 

0 

1 

0 

1 

0 

1 

0 

0 

0 

0 

0 

0 

0,39 

0,58 

0,37 

0,45 

100% 

95% 

0,45 

0,40 

95% 

0,09 

0,74 

0,74 

0,40 

0,36 

72% 

1,23 

1,00 

1,00 

78% 

0,36 

0,32 

76% 

0,39 

0,38 

70% 

3,08 

5,41 

0,74 

0,39 

0,33 

90% 

2,79 

1,00 

1,00 

89% 

0,52 

0,45 

1,00 

1,00 

1,00 

1,00 

0,50 

0,41 

1,00 

1,00 

1,00 

1,00 

93% 

93% 

98% 

100% 

98% 

96% 

3,08 

1,89 

1,23 

0,00 

0,00 

3,69 

0,00 

Source 

[1] 

[1] 

Consultant assumptions (based on market 

data) 

[1], [5], availability benchmarked to 

historic data  

[2], [5], availability benchmarked to 

historic data 

[3] 

[1], availability: benchmarked to historic 

data 

Consultant assumptions (based on market 

data) 

[2], [5], availability benchmarked to 

historic data 

[1] 

[1] 

[4] 

[3] 

[3] 

[4] 

Interactions between electricity market reforms and climate policies 

 147 

 
 
 
 
Table 34 » Detailed plant input data for the UK, 2010 – part II 

Fixed operating cost (€/MW/year) 

Capex (€/MW) 

Capacity  

Technology 

Low 

Medium 

High 

Low 

Medium 

High 

Peaking oil 

€ 14.718 

€ 17.562 

€ 20.607 

€ 29.095 

€ 33.549 

€ 37.246 

Gas 

Gas old 

Coal old 

€ 31.732 

€ 37.869 

€ 44.280 

€ 58.404 

€ 64.219 

€ 69.684 

€ 31.732 

€ 37.869 

€ 44.280 

€ 31.934 

€ 51.553 

€ 71.479 

Nuclear old 

€ 80.502 

€ 95.262 

€ 110.022 

Biomass 

Gas CHP 

CoalCCS 

€ 118.080 

€ 118.080 

€ 138.006 

€ 214.257 

€ 268.991 

€ 471.177 

€ 37.600 

€ 67.481 

€ 97.631 

€ 61.586 

€ 68.775 

€ 77.132 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

Nuclear new 

€ 80.502 

€ 95.262 

€ 110.022 

€ 325.291 

€ 359.364 

€ 405.403 

GasCCS 

€ 33.767 

€ 41.933 

€ 49.768 

€ 110.690 

€ 130.064 

€ 152.463 

Coal 

Hydro 

Solar 

€ 31.934 

€ 51.553 

€ 71.479 

€ 30.554 

€ 68.746 

€ 84.023 

€ 144.711 

€ 230.559 

€ 285.625 

€ 20.115 

€ 26.862 

€ 34.755 

€ 211.024 

€ 305.326 

€ 420.922 

Wind - onshore 

€ 18.450 

€ 18.450 

€ 18.450 

€ 142.798 

€ 166.765 

€ 204.135 

Wind - offshore 

€ 87.330 

€ 87.330 

€ 87.330 

€ 298.109 

€ 326.564 

€ 390.101 

GW 

10,50 

17,00 

16,00 

24,00 

10,00 

2,00 

4,00 

0,00 

0,00 

0,00 

0,00 

1,60 

0,08 

3,86 

1,34 

Interactions between electricity market reforms and climate policies 

 148 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 35 » Detailed plant input data for the UK, 2020 – part I 

Technology/fuel  Must run 

Efficiency 

Efficiency 

(max) 

(min) 

Availability  Variable operating cost (€/MWh) 

Peaking oil 

Gas 

Gas old 

Coal old 

Nuclear old 

Biomass 

Gas CHP 

CoalCCS 

Nuclear new 

GasCCS 

Coal 

Hydro 

Solar 

Wind – onshore 

Wind – offshore 

0 

0 

0 

0 

1 

0 

1 

0 

1 

0 

0 

0 

0 

0 

0 

0,39 

0,60 

0,45 

0,40 

1,00 

0,36 

0,39 

0,39 

1,00 

0,52 

0,45 

1,00 

1,00 

1,00 

1,00 

0,37 

0,45 

0,40 

0,36 

1,00 

0,32 

0,38 

0,33 

1,00 

0,50 

0,41 

1,00 

1,00 

1,00 

1,00 

100% 

95% 

95% 

76% 

80% 

76% 

70% 

90% 

89% 

93% 

93% 

98% 

100% 

98% 

96% 

0,09 

0,74 

0,74 

1,23 

3,08 

5,41 

0,74 

2,79 

3,08 

1,89 

1,23 

0,00 

0,00 

3,69 

0,00 

Interactions between electricity market reforms and climate policies 

 149 

 
 
 
 
Table 36 » Detailed plant input data for the UK, 2020 – part II 

Fixed operating cost (€/MW/year) 

Capex (€/MW) 

Capacity  

Technology 

Low 

Medium 

High 

Low 

Medium 

High 

Peaking oil 

€ 14.718 

€ 17.562 

€ 20.607 

€ 29.095 

€ 33.549 

€ 37.246 

Gas 

Gas old 

Coal old 

€ 31.732 

€ 37.869 

€ 44.280 

€ 58.404 

€ 64.219 

€ 69.684 

€ 31.732 

€ 37.869 

€ 44.280 

€ 31.934 

€ 51.553 

€ 71.479 

Nuclear old 

€ 80.502 

€ 95.262 

€ 110.022 

Biomass 

Gas CHP 

CoalCCS 

€ 113.098 

€ 113.098 

€ 132.183 

€ 205.217 

€ 257.641 

€ 451.296 

€ 37.600 

€ 67.481 

€ 97.631 

€ 61.586 

€ 68.775 

€ 77.132 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

Nuclear new 

€ 80.502 

€ 95.262 

€ 110.022 

€ 325.291 

€ 359.364 

€ 405.403 

GasCCS 

€ 33.767 

€ 41.933 

€ 49.768 

€ 110.690 

€ 130.064 

€ 152.463 

Coal 

Hydro 

Solar 

€ 31.934 

€ 51.553 

€ 71.479 

€ 30.554 

€ 68.746 

€ 84.023 

€ 144.711 

€ 230.559 

€ 285.625 

€ 15.676 

€ 20.934 

€ 27.085 

€ 164.453 

€ 237.944 

€ 328.029 

GW 

6,25 

24,00 

14,00 

6,75 

4,00 

2,75 

6,00 

0,50 

0,00 

0,00 

0,00 

1,62 

6,00 

Wind - onshore 

€ 17.795 

€ 17.795 

€ 17.795 

€ 137.728 

€ 160.844 

€ 196.888 

18,29 

Wind - offshore  € 60.696 

€ 60.696 

€ 60.696 

€ 207.190 

€ 226.967 

€ 271.126 

20,34 

Interactions between electricity market reforms and climate policies 

 150 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 37 » Detailed plant input data for the UK, 2030 – part I 

Technology/fuel  Must run 

Efficiency 
(max) 

Efficiency 
(min) 

Availability 

Variable 
operating cost 
(€/MWh) 

Peaking oil 

Gas 

Gas old 

Coal old 

Nuclear old 

Biomass 

Gas CHP 

CoalCCS 

Nuclear new 

GasCCS 

Coal 

Hydro 

Solar 

Wind - onshore 

Wind - offshore 

0 

0 

0 

0 

1 

0 

1 

0 

1 

0 

0 

0 

0 

0 

0 

0,39 

0,62 

0,45 

0,40 

1,00 

0,36 

0,39 

0,39 

1,00 

0,52 

0,45 

1,00 

1,00 

1,00 

1,00 

0,37 

0,45 

0,41 

0,36 

1,00 

0,32 

0,38 

0,33 

1,00 

0,50 

0,41 

1,00 

1,00 

1,00 

1,00 

100% 

95% 

95% 

78% 

80% 

76% 

70% 

90% 

89% 

89% 

93% 

98% 

100% 

98% 

96% 

0,09 

0,74 

0,74 

1,23 

3,08 

5,41 

0,74 

2,79 

3,08 

1,89 

1,23 

0,00 

0,00 

3,69 

0,00 

Interactions between electricity market reforms and climate policies 

 151 

 
 
 
Table 38 » Detailed plant input data for the UK, 2030 – part II 

Fixed operating cost (€/MW/year) 

Capex (€/MW) 

Capacity  

Technology 

Low 

Medium 

High 

Low 

Medium 

High 

Peaking oil 

€ 14.718 

€ 17.562 

€ 20.607 

€ 29.095 

€ 33.549 

€ 37.246 

Gas 

Gas old 

Coal old 

€ 31.732 

€ 37.869 

€ 44.280 

€ 58.404 

€ 64.219 

€ 69.684 

€ 31.732 

€ 37.869 

€ 44.280 

€ 31.934 

€ 51.553 

€ 71.479 

Nuclear old 

€ 80.502 

€ 95.262 

€ 110.022 

Biomass 

Gas CHP 

CoalCCS 

€ 106.123 

€ 106.123 

€ 124.031 

€ 192.560 

€ 241.751 

€ 423.463 

€ 37.600 

€ 67.481 

€ 97.631 

€ 61.586 

€ 68.775 

€ 77.132 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

Nuclear new 

€ 80.502 

€ 95.262 

€ 110.022 

€ 325.291 

€ 359.364 

€ 405.403 

GasCCS 

€ 33.767 

€ 41.933 

€ 49.768 

€ 110.690 

€ 130.064 

€ 152.463 

Coal 

Hydro 

Solar 

€ 31.934 

€ 51.553 

€ 71.479 

€ 30.554 

€ 68.746 

€ 84.023 

€ 144.711 

€ 230.559 

€ 285.625 

€ 11.930 

€ 15.932 

€ 20.613 

€ 125.159 

€ 181.090 

€ 249.650 

Wind - onshore 

€ 17.686 

€ 17.686 

€ 17.686 

€ 136.883 

€ 159.858 

€ 195.680 

Wind - offshore 

€ 48.659 

€ 48.659 

€ 48.659 

€ 166.102 

€ 181.956 

€ 217.358 

GW 

6,00 

24,00 

11,00 

3,75 

2,00 

2,75 

6,00 

0,50 

3,00 

0,00 

0,00 

1,62 

8,85 

26,14 

24,58 

Interactions between electricity market reforms and climate policies 

 152 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 39 » Detailed plant input data for Germany, 2010 – part I 
Efficiency 

Efficiency 

Technology/fuel  Must run 

Peaking 

Gas new 

Gas existing 

Coal existing 

Nuclear existing 

Biomass 

Gas CHP 

Coal 

CoalCCS 

Nuclear new 

Lignite 

Hydro 

Solar 

Wind - onshore 

Wind - offshore 

0 

0 

0 

0 

1 

1 

1 

0 

0 

1 

0 

0 

0 

0 

0 

(max) 

(min) 

0,39 

0,58 

0,45 

0,40 

1,00 

0,36 

0,39 

0,45 

0,39 

1,00 

0,42 

1,00 

1,00 

1,00 

1,00 

0,37 

0,45 

0,40 

0,34 

1,00 

0,32 

0,38 

0,45 

0,33 

1,00 

0,35 

1,00 

1,00 

1,00 

1,00 

Availability  Variable operating cost (€/MWh) 

100% 

95% 

95% 

78% 

78% 

90% 

70% 

80% 

90% 

89% 

78% 

98% 

100% 

98% 

96% 

0,09 

0,74 

0,74 

1,23 

3,08 

5,41 

0,74 

1,23 

2,79 

3,08 

1,23 

0,00 

0,00 

3,69 

0,00 

Interactions between electricity market reforms and climate policies 

 153 

 
 
 
 
Table 40 » Detailed plant input data for Germany, 2010 – part II 

Fixed operating cost (€/MW/year) 

Capex (€/MW) 

Capacity  

Technology 

Low 

Medium 

High 

Low 

Medium 

High 

Peaking 

Gas new 

€ 14.718 

€ 17.562 

€ 20.607 

€ 29.095 

€ 33.549 

€ 37.246 

€ 31.732 

€ 37.869 

€ 44.280 

€ 58.404 

€ 64.219 

€ 69.684 

Gas existing 

€ 31.732 

€ 37.869 

€ 44.280 

Coal existing 

€ 31.934 

€ 51.553 

€ 71.479 

Nuclear existing 

€ 80.502 

€ 95.262 

€ 110.022 

Biomass 

Gas CHP 

Coal 

€ 118.080 

€ 118.080 

€ 138.006 

€ 214.257 

€ 268.991 

€ 471.177 

€ 37.600 

€ 67.481 

€ 97.631 

€ 61.586 

€ 68.775 

€ 77.132 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

CoalCCS 

€ 80.502 

€ 95.262 

€ 110.022 

€ 325.291 

€ 359.364 

€ 405.403 

Nuclear new 

€ 33.767 

€ 41.933 

€ 49.768 

€ 110.690 

€ 130.064 

€ 152.463 

GW 

7,25 

13,00 

12,00 

27,00 

20,00 

4,25 

4,00 

0,00 

0,00 

0,00 

19,50 

Lignite 

Hydro 

Solar 

€ 31.934 

€ 51.553 

€ 71.479 

€ 30.554 

€ 68.746 

€ 84.023 

€ 144.711 

€ 230.559 

€ 285.625 

4,26 

€ 20.115 

€ 26.862 

€ 34.755 

€ 211.024 

€ 305.326 

€ 420.922 

17,32 

Wind - onshore 

€ 18.450 

€ 18.450 

€ 18.450 

€ 142.798 

€ 166.765 

€ 204.135 

27,10 

Wind - offshore 

€ 87.330 

€ 87.330 

€ 87.330 

€ 298.109 

€ 326.564 

€ 390.101 

0,09 

Interactions between electricity market reforms and climate policies 

 154 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Table 41 » Detailed plant input data for Germany, 2020 – part I 

Technology/fuel  Must run 

Efficiency 
(max) 

Efficiency 
(min) 

Availability 

Variable 
operating cost 
(€/MWh) 

Peaking 

Gas new 

Gas existing 

Coal existing 

Biomass 

Coal CHP 

Coal 

Nuclear new 

Nuclear existing 

CoalCCS 

GasCCS 

Hydro 

Solar 

Wind - onshore 

Wind - offshore 

0 

0 

0 

0 

1 

1 

0 

1 

1 

0 

0 

0 

0 

0 

0 

0,36 

0,54 

0,50 

0,38 

0,36 

0,33 

0,42 

1,00 

1,00 

0,39 

0,52 

1,00 

1,00 

1,00 

1,00 

0,25 

0,50 

0,48 

0,32 

0,32 

0,30 

0,42 

1,00 

1,00 

0,33 

0,50 

1,00 

1,00 

1,00 

1,00 

100% 

95% 

95% 

78% 

90% 

70% 

80% 

89% 

82% 

90% 

93% 

98% 

100% 

98% 

96% 

0,09 

0,74 

0,74 

1,23 

5,41 

1,23 

1,23 

3,08 

3,08 

2,79 

1,89 

0,00 

0,00 

3,69 

0,00 

Interactions between electricity market reforms and climate policies 

 155 

 
 
 
 
Table 42 » Detailed plant input data for Germany, 2020 – part II 

Fixed operating cost (€/MW/year) 

Capex (€/MW) 

Capacity  

Technology 

Low 

Medium 

High 

Low 

Medium 

High 

Peaking 

Gas new 

€ 14.718 

€ 17.562 

€ 20.607 

€ 29.095 

€ 33.549 

€ 37.246 

€ 31.732 

€ 37.869 

€ 44.280 

€ 58.404 

€ 64.219 

€ 69.684 

Gas existing 

€ 31.732 

€ 37.869 

€ 44.280 

Coal existing 

€ 31.934 

€ 51.553 

€ 71.479 

€ 0 

€ 0 

€ 0 

€ 0 

€ 0 

€ 0 

Biomass 

Coal CHP 

Coal 

€ 118.080 

€ 118.080 

€ 138.006 

€ 214.257 

€ 268.991 

€ 471.177 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

€ 31.934 

€ 51.553 

€ 71.479 

€ 161.787 

€ 162.853 

€ 349.366 

Nuclear new 

€ 33.767 

€ 41.933 

€ 49.768 

€ 110.690 

€ 130.064 

€ 152.463 

Nuclear existing 

€ 80.502 

€ 95.262 

€ 110.022 

€ 0 

€ 0 

€ 0 

CoalCCS 

GasCCS 

Hydro 

Solar 

€ 80.502 

€ 95.262 

€ 110.022 

€ 325.291 

€ 359.364 

€ 405.403 

€ 30.554 

€ 68.746 

€ 84.023 

€ 144.711 

€ 230.559 

€ 285.625 

€ 20.115 

€ 26.862 

€ 34.755 

€ 211.024 

€ 305.326 

€ 420.922 

Wind - onshore 

€ 18.450 

€ 18.450 

€ 18.450 

€ 142.798 

€ 166.765 

€ 204.135 

Wind - offshore 

€ 87.330 

€ 87.330 

€ 87.330 

€ 298.109 

€ 326.564 

€ 390.101 

GW 

0,25 

0,50 

2,20 

17,25 

0,50 

8,00 

0,00 

0,00 

0,00 

0,00 

0,00 

1,02 

0,00 

1,18 

0,00 

Interactions between electricity market reforms and climate policies 

 156 

 
 
 
 
 
 
 
 
 
Sources: 

1.  Parsons Brinckerhoff, Electricity Generation Cost Model - 2012 Update of Non-renewable 

Technologies for DECC, 2012 

2.  Parsons Brinckerhoff, Electricity Generation Cost Model - 2013 Update of Non-renewable 

Technologies for DECC, 2013 

3.  Parsons Brinckerhoff, Electricity Generation Cost Model - 2013 Update of Renewable Technologies 

for DECC, 2013 

4.  ARUP, review of the generation costs and deployment potential of renewable electricity 

technologies in the UK for DECC, 2011 

5.  Mott MacDonald, UK Electricity Generation Costs update, 2010 

Technology cost learning rate projections: IEA, World Energy Outlook 
Future technology efficiency projections: IEA, World Energy Outlook 

 
 
  Historic fleet efficiencies: Ecofys 2014; international comparison fossil power efficiency 
 

Technologies, installed capacities: EU Reference scenario 2013 

The technology specific economic lifetimes are summarised in Table 43. 

Table 43 » Technology specific economic lifetimes per plant type assumed in the model 
Technology 
Coal 
Gas 
Wind 
Biomass 
Nuclear 
Solar 
Hydro 

Economic lifetime (years) 
30 
25 
24 
25 
6 
25 
41 

A2.4  Detailed modelling assumptions: ancillary services 
The modelling assumptions on the revenue from ancillary services in the UK are based on data from 

OFGEM and the National Grid. Figure 41 shows that reserve and frequency response together represent 

about half of the total balancing costs in a year. The transmission constraint management costs vary 

strongly over the years, depending on outages, generation and new reinforcements. 

Interactions between electricity market reforms and climate policies 

 157 

 
 
 
 
 
 
Figure 41 » UK balancing cost and breakdown by main services. Source: OFGEM/National Grid 

Data from the National Grid and from Elexon, the Balancing and Settlement Code Company are used to determine a 
breakdown of the balancing costs by type of plant and type of service35. Figure 42 on the following page shows the 
data for the year 2013/2014. Data for the year 2010 - the base year of the modelling calculations – was not available.  

Figure 43 shows the average balancing costs per unit of installed capacity per year. 

Figure 42 » Ancillary services revenue on the UK market per plant type as assumed in the model 

Note 9 »  See National Grid at http://www2.nationalgrid.com/uk/services/ and Elexon balancing mechanism reports at http://www.bmreports.com/  

Interactions between electricity market reforms and climate policies 

 158 

 
 
 
 
 
 
 
 
 
Figure 43 » Ancillary services revenue on the UK market per unit of capacity per year as assumed in the model 

Further modelling assumptions used to determine the breakdown over plant types include: 

  Hydro, OCGT and peaking plants mainly provide reserve services 

  CCGTs provide both reserve and response services, supplemented by some reactive power and 

system services 

  Coal plants provide mainly frequency response 

 

The breakdown of constraint management costs is assumed to be similar to the aggregate 

breakdown of STOR, frequency response and reactive power 

 

Frequency response services are provided by the same types of plants as STOR providers, 

excluding embedded and demand side providers 

Total revenues from ancillary services on the German market are based on the detailed data per type of 

service from the UK, information on the total revenue from ancillary services in Germany and our 

understanding of the extent to which only some technologies can provide some of the services. The 

resulting assumptions on the ancillary service revenue on the German market in 2013/14 are shown in 

Table 44. 

Interactions between electricity market reforms and climate policies 

 159 

 
 
 
 
 
 
 
 
 
 
 
Table 44 » Estimated ancillary service revenue by technology for the German market 

Ancillary service 

Wind 

Coal 

CCGT  OCGT 

Peaking 
plant 

Reserve Services (euro /MW/yr) 

Frequency Response (euro /MW/yr) 

System Services (euro /MW/yr) 

0 

0 

0 

30 

1,676 

2,362 

2,933 

5,967 

5,196 

1,288 

998 

869 

215 

Reactive Power (euro /MW/yr) 

3,012 

15 

1,228 

745 

Constraint management (euro 
/MW/yr) 

289 

547 

903 

0 

99 

17 

0 

0 

Total (euro/MW/yr) 

3,302 

7,557 

9,873 

4,609 

3,049 

Interactions between electricity market reforms and climate policies 

 160 

 
 
  
 
Annex 3: Model outputs 

This Annex contains further details to the description of outputs of the purpose-built tool introduced in 

Chapter 5 ». The model provides the following main outputs: 

1.  Profitability of each technology type, under various scenario conditions. The main output factors 

presented include: 

a.  System profitability - to indicate whether in a specific case the overall system would be loss-

making, which is not a viable situation in the long run.  

b.  Peak, mid-merit, intermittent and base-load profitability - to assess the profitability of the 

various market strategies. 

c.  Distribution curve of individual technology profitability - to assess the range of profitability; 

the system might be profitable, but the majority of technologies loss-making, countered by 

one or two highly profitable technologies. 

2.  The electricity price: 

a.  Average annual price 

b.  Price volatility 

3.  The number of dispatched hours for each type of plant and the number of hours when dispatched 

flexible capacity falls below a threshold limit - this provides a first order insight regarding changes 

in system reliability. 

4.  The total amount of CO2 emissions and CO2 emission intensities for the total system and per plant 

type 

A3.1  Determining the demand and supply curve 
In the first step the model determines the hourly demand curve, the merit order of the various plant 

types and the generation curve. This is illustrated in Figure 44 and Figure 45. 

Figure 44 » Merit order generated by the model 

All renewable generation (not in this graph) is placed at the start of the merit order since the marginal 

costs are close to zero. Next, nuclear power and must-run production units are placed in the merit order. 

These are considered price takers; these plants will anyway run according to the planned production 

Interactions between electricity market reforms and climate policies 

 161 

 
 
 
 
 
hours. The further plants are ranked according to their marginal costs; the sum of fuel costs, CO2 prices 

and variable O&M costs.  

Figure 45 » Electricity generation profile generated by the model 

A3.2  Determining wholesale electricity prices and plant profitability 
In the next step the model determines the wholesale electricity price on the basis of short-run marginal 

cost (SRMC) dispatching. Figure 46 shows the model’s estimated SRMC curve on the basis of the demand 

profile and generation profile generated for the UK for 2012, in comparison with the actual wholesale 

market price on the UK 2012 day-ahead market. We conclude that the model provides a reasonable first 

order estimate of the electricity wholesale price, but underestimates the price for high demand periods 

when prices are set by peak capacity. The extent of this underestimation is obtained by comparing the 

model results for 2010 with historic market prices: 

  Average for all hours in the year: prices are 7% underestimated  

  Average for 60% highest demand hours in the year: prices are 11% underestimated 

  Average for 30% highest demand hours in the year: prices are 17% underestimated 

This divergence for higher demands is in line with the adopted approach, which excludes strategic and 

scarcity pricing. The underestimation of prices likely results in an underestimation of plant profitability 

and therewith of total system profitability. Since this underestimation is made in all scenarios it does not 

result in a large impact in the comparison of scenario results. 

Interactions between electricity market reforms and climate policies 

 162 

 
 
 
 
 
Figure 46 » Wholesale electricity price curve generated by the model in comparison with actual historic price curve 

On the basis of the SRMC curve and the operational costs by plant type the model determines the 

profitability for each plant type. Figure 47 shows the profitability of various assets in the UK market in 

2010. The profitability calculation assumes that current plants are already depreciated and therefore 

would only need to recoup fixed operational costs, while new plants would also need to recoup 

investment costs. The calculations exclude taxation costs and are based on annualised costs for the year 

2010. This does not include forward expectation of electricity price developments. 

Figure 47 » Profitability of different plant types as generated by the model 

The model calculations show that in the 2010 UK scenario (based on EU reference 2013) the revenues 

from many assets were not sufficient to recoup fixed costs or provide any incentive for new investments. 

On the basis of these results a potential risk is identified that existing gas plants (labelled in the figure as 

‘Gas old’) would be decommissioned. The model results also show that in the given system insufficient 

incentives exist for investments in new gas plants (labelled in the figure as ‘Gas’), based on their 

annualised profitability. In this market existing nuclear plants are the most profitable type of plants and 

existing coal plants will make either a small profit or a small loss, depending on their efficiency and 

operating hours. It should be noted that subsidies, ancillary services revenues and capacity market 

Interactions between electricity market reforms and climate policies 

 163 

 
 
 
 
 
 
 
remuneration are not included in this calculation. Hence, the results pictured for wind power show that in 

the 2010 UK market subsidies were required to obtain a profitable business case. 

A3.3  Detailed result tables 

Table 45» Main model results for the UK electricity market 

Gas production (TWh) 

Coal production (TWh) 

Nuclear production (TWh) 

Renewables production (TWh) 

Emissions (Mton) 

Emissions (g/kWh) 

Average SRMC (€/MWh) 

Weighted average SRMC 
(€/MWh)36 

2010 

 120  

 141  

 65  

 29  

 173  

 488  

 53  

 54  

2020 

 140  

 44  

 27  

 127  

 91  

 262  

 75  

 77  

2030 

 139  

 26  

 36  

 158  

 73  

 198  

 88  

 90  

Table 46 » Main model sensitivities for the UK electricity market, compared to 2010 scenario baseline   

CO2 
emissions 
(g/kWh) 

Gas consump-
tion (TWh) 

Coal Consump-
tion (TWh) 

Scenario 

Baseline 

High share renewables 

Gas & coal price   x 1.5 

Coal price x 1.5 

CO2 price (€34/t) 

Demand x 0.9 

Demand x 1.1 

488 

-137 

0 

-46 

-33 

4 

-5 

Interconnector capacity (+3.9GW) 

-21 

Demand response (+3GW) 

Storage capacity (+2GW/7 GWh) 

0 

1 

Carbon Floor Price (18£ in 2020) 

-227 

2020 CPF - 30£ 

-228 

252 

-137 

0 

56 

38 

-65 

69 

-29 

-1 

-3 

36 

36 

371 

-69 

0 

-78 

-55 

-11 

6 

-6 

0 

3 

-261 

-262 

Alternative decomm & invest. 
scenario* (2020 baseline) 
* 9 GW of coal capacity planned to be decommissioned is not decommissioned and the planned 7 GW 
investments in new CCGT do not go ahead 

126 

-88 

76 

36 Average SRMC weighted by generation volume 

Interactions between electricity market reforms and climate policies 

 164 

 
 
 
 
 
 
 
Table 47 » Main model results for the German electricity market 

Gas production (TWh) 

Coal production (TWh) 

Lignite production (TWh) 

Nuclear production (TWh) 

Renewables production (TWh) 

Emissions (Mton) 

Emissions (g/kWh) 

Average SRMC (€/MWh) 

2010 

 74  

 141  

 126  

 130  

 103  

 271  

 491  

 48  

Weighted average SRMC (€/MWh) 

 50  

Table 48 » Main model results for the German electricity market, compared to 2010 scenario baseline 

Scenario 

Baseline 

High share renewables 

Gas & coal price   x 1.5 

Coal price x 1.5 

CO2 price (€34/t) 

Demand x 0.9 

Demand x 1.1 

Interconnector capacity 
(+6GW) 

Demand response (+5GW) 

Storage capacity 
(+5GW/17.5 GWh) 

CO2 emissions 
(g/kWh) 

Gas consumption 
(TWh) 

Coal Consumption 
(TWh) 

491 

-91 

-2 

-33 

-24 

-15 

8 

7 

0 

3 

162 

-69 

0 

68 

39 

-60 

76 

9 

0 

-9 

723 

-114 

-3 

-3 

-66 

-71 

46 

7 

0 

11 

Interactions between electricity market reforms and climate policies 

 165 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interactions between electricity market reforms and climate policies 

 166 

 
 
 
 
 
 
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doi:10.2834/28107