Europaudvalget 2016
KOM (2016) 0752
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EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 385 final
COMMISSION STAFF WORKING DOCUMENT
Accompanying the document
REPORT FROM THE COMMISSION
Final Report of the Sector Inquiry on Capacity Mechanisms
{COM(2016) 752 final}
EN
EN
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Table of Contents
1.
Introduction ......................................................................................................................... 5
1.1
1.2
1.3
1.4
1.5
2.
Concerns about the security of electricity supply ........................................................ 5
The Energy Union and the Market Design Initiative .................................................. 5
The Energy and Environmental Aid Guidelines.......................................................... 6
The sector inquiry: what has the Commission done so far? ........................................ 7
Set-up of the Staff Working Document ....................................................................... 8
Increased generation adequacy concerns .......................................................................... 10
2.1
The electricity sector in transition ............................................................................. 10
The liberalisation of electricity markets ............................................................. 10
Decarbonisation policies .................................................................................... 12
Concerns about security of supply ..................................................................... 13
2.1.1
2.1.2
2.1.3
2.2
Incentives for future investment in generation .......................................................... 24
Expectations about future development of generation and demand .................. 25
Market and regulatory failures undermining incentives to invest ...................... 27
Conclusions on the lack of optimal incentives to invest .................................... 39
2.2.1
2.2.2
2.2.3
2.3
What is being done to alleviate imperfections of EU electricity markets? ............... 39
Improving the functioning of the electricity market .......................................... 40
Addressing residual market failures with a capacity mechanism ...................... 47
2.3.1
2.3.2
3.
Member State interventions: overview and classification ................................................ 50
3.1
Types of capacity mechanisms .................................................................................. 50
Targeted mechanisms ......................................................................................... 50
Market-wide mechanisms .................................................................................. 51
3.1.1
3.1.2
3.2
Capacity mechanisms in place in the 11 Member States........................................... 52
Tender for new capacity ..................................................................................... 55
Strategic reserve ................................................................................................. 57
Interruptibility schemes ...................................................................................... 60
Targeted capacity payments ............................................................................... 61
Central buyer ...................................................................................................... 63
De-central obligation .......................................................................................... 65
Market wide capacity payments ......................................................................... 66
3.2.1
3.2.2
3.2.3
3.2.4
3.2.5
3.2.6
3.2.7
3.3
4.
Conclusions ............................................................................................................... 67
Adequacy Assessments and Reliability Standards ........................................................... 68
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4.1
4.2
Introduction ............................................................................................................... 68
Findings of the sector inquiry .................................................................................... 68
Reliability incidents are rare .............................................................................. 68
More adequacy problems are expected in the future.......................................... 69
Member States carry out increasingly advanced adequacy assessments ........... 71
Member State practice in setting reliability standards ....................................... 73
4.2.1
4.2.2
4.2.3
4.2.4
4.3
Assessment ................................................................................................................ 77
The absence of a common approach in assessing adequacy .............................. 77
Reliability standards are not used to ensure appropriate intervention ............... 80
4.3.1
4.3.2
4.4
5.
Conclusions ............................................................................................................... 80
Design features of capacity mechanisms .......................................................................... 82
5.1
5.2
Introduction ............................................................................................................... 82
Eligibility ................................................................................................................... 82
Eligibility criteria in capacity mechanisms ........................................................ 82
Findings of the sector inquiry on eligibility ....................................................... 83
Issues encountered in relation to eligibility...................................................... 104
Conclusions on eligibility................................................................................. 111
5.2.1
5.2.2
5.2.3
5.2.4
5.3
Allocation Process ................................................................................................... 112
The role of the allocation process in capacity mechanisms ............................. 112
Findings of the sector inquiry on administrative allocation processes............. 112
Findings of the sector inquiry on competitive allocation processes................. 116
Issues encountered in relation to allocation processes ..................................... 119
Conclusions on allocation processes ................................................................ 123
5.3.1
5.3.2
5.3.3
5.3.4
5.3.5
5.4
The capacity product: obligations and penalties...................................................... 124
Capacity products ............................................................................................. 124
Findings of the sector inquiry........................................................................... 125
Issues identified ................................................................................................ 132
Conclusions ...................................................................................................... 138
5.4.1
5.4.2
5.4.3
5.4.4
6.
Assessment of the various types of capacity mechanisms .............................................. 140
6.1
6.2
Necessity for intervention through a capacity mechanism ...................................... 141
Appropriateness and market impacts for each type of mechanism ......................... 142
Tenders for new capacity ................................................................................. 142
Strategic reserves.............................................................................................. 145
Interruptibility schemes .................................................................................... 149
3
6.2.1
6.2.2
6.2.3
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6.2.4
6.2.5
6.2.6
6.2.7
6.3
Targeted capacity payments ............................................................................. 152
Central buyer mechanisms ............................................................................... 154
De-central obligation ........................................................................................ 157
Market-wide capacity payments....................................................................... 160
Choosing the right type of capacity mechanism ...................................................... 161
The main adequacy problems ........................................................................... 162
Long term concerns .......................................................................................... 163
Temporary concerns ......................................................................................... 163
Locational concerns.......................................................................................... 164
Concerns related to the responsive of the demand side ................................... 165
Capacity payments are unlikely to be the most appropriate option ................. 166
6.3.1
6.3.2
6.3.3
6.3.4
6.3.5
6.3.6
6.4
6.5
6.6
Minimising the cost of capacity mechanisms .......................................................... 166
Capacity mechanisms and the decarbonisation objective........................................ 167
Conclusions ............................................................................................................. 168
Annex 1: Overview of respondents ........................................................................................ 171
Annex 2: The participation of interconnectors and foreign capacity providers in capacity
mechanisms ............................................................................................................................ 177
Annex 3: Summary of Replies of the Public Consultation and Questionnaires to public bodies
following the publication of the interim report ...................................................................... 208
Annex 4: References .............................................................................................................. 212
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1.
1.1
(1)
I
NTRODUCTION
Concerns about the security of electricity supply
Europe's electricity sector is experiencing a period of unprecedented transition.
Liberalisation and decarbonisation have profoundly changed the way electricity is
generated, traded and consumed in the Union, pursuing a more sustainable and at the
same time affordable electricity market. Renewable energy sources have grown
rapidly and 10% of total electricity is now sourced from variable renewable
electricity, such as wind or solar.
The large-scale roll-out of renewables combined with the overall decline in demand
have curbed the profitability of conventional generators and reduced incentives to
maintain existing power plants or invest in new ones. In many Member States, these
developments have been accompanied by increased concerns about security of supply.
Member States are concerned that the electricity market will not produce the
investment signals needed to ensure an electricity generation mix that is able to meet
demand at all times.
Some Member States have reacted by taking measures designed to support investment
in the additional capacity that they deem necessary to ensure an acceptable level of
security of supply. These capacity mechanisms pay providers of existing and/or new
capacity for making it available.
When introduced prematurely, without proper problem identification or in an
uncoordinated manner, and without taking into account the contribution of cross-
border resources, there is a risk that capacity mechanisms distort cross-border
electricity trade and competition. For example, they may reward new investments only
in certain types of generation or exclude demand response. They may also encourage
investment within national borders when it would be more efficient to reinforce
interconnection and import electricity when needed.
1.2
The Energy Union and the Market Design Initiative
(2)
(3)
(4)
(5)
Concerns about the security of electricity supply have been raised by the Commission
in the framework of the Energy Union.
1
Under the internal market dimension of the
Energy Union, the Commission envisages to take action in the broader area of
electricity market design and security of electricity supply both of which are related to
generation adequacy. More specifically, the Energy Union strategy states that the
Commission will establish an objective, EU-wide, fact-based security of supply
1
Communication from the Commission, 'A Framework Strategy for a Resilient Energy Union with a Forward-Looking
Climate Change Policy', COM(2015)80 final.
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assessment addressing the situation in Member States. This will take into account
cross-border flows, variable renewable production, demand response and storage
possibilities.
(6)
To obtain stakeholders' views on these ideas, the Commission launched public
consultations, firstly, on a new energy market design
2
and, secondly, on a review of
the Directive concerning measures to safeguard security of electricity supply.3
Together with this report, the Commission also proposes legislative changes to the
energy market design in order to improve the functioning of the internal energy
market.
This sector inquiry aims to contribute to the Commission's Energy Union agenda and
the development of a new market design that is fit for the future by assessing to what
extent capacity mechanisms are appropriate instruments to ensure sufficient electricity
supply whilst at the same time minimising the distortion of competition or trade in the
internal electricity market.
1.3
(8)
The Energy and Environmental Aid Guidelines
(7)
The Guidelines on State aid for environmental protection and energy 2014 – 2020
('EEAG')
4
include specific rules for assessing capacity mechanisms. The Commission
has already applied these rules to i.a. capacity mechanisms notified by the United
Kingdom
5
and France
6
.
The sector inquiry is not intended to provide a State aid assessment of the existing or
planned capacity mechanisms in the Member States included in it. The compliance of
those mechanisms with State aid rules is carried out exclusively in the context of State
aid decisions.
The present report rather aims to gather and present information on the functioning of
capacity mechanisms and draw tentative conclusions which will help with the
application of EEAG. The interim report and a previous version of this Staff Working
(9)
(10)
2
3
4
5
6
COM(2015)340 final.
https://ec.europa.eu/energy/sites/ener/files/documents/DG%20ENER_ConsultationPaperSoSelectricity14July.pdf.
Guidelines on State aid for environmental protection and energy 2014-2020 (EEAG) (OJ C 200 of 28.06.2014, p. 1).
Commission decision C (2014) 5083 final of 23.7.2014 in Case SA.35980 (2014/N-2) – United Kingdom - Electricity
market reform – Capacity market. The public version of the decision is available at:
http://ec.europa.eu/competition/state_aid/cases/253240/253240_1579271_165_2.pdf.
The Commission opened formal investigations into the French country-wide capacity mechanism (SA.39621) and the
tender for a gas-fired power plant in Brittany (SA.40454) on 13 November 2015. See:
http://europa.eu/rapid/press-
release_IP-15-6077_en.htm.
The Commission's decision on the country-wide capacity mechanism is publicly available
(in French) at:
http://ec.europa.eu/competition/state_aid/cases/261326/261326_1711140_20_2.pdf
and for the tender
for a gas-fired power plant in Brittany at:
http://ec.europa.eu/competition/state_aid/cases/261325/261325_1711139_35_3.pdf.
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Document were put forward for public consultation on 13 April 2016 to test certain
findings and tentative conclusions as established in the first phase of the investigation.
(11)
The information gathered in the sector inquiry has enabled the Commission to
understand better:
whether, and to what extent, it is necessary that Member States grant State aid
to ensure security of electricity supply;
what types of capacity mechanisms are most suitable to ensure security of
electricity supply, and under which conditions capacity mechanisms risk
distorting competition between capacity providers
7
and cross-border trade;
how capacity mechanisms can complement the Single Market for energy rather
than undermining its functioning;
how capacity mechanisms for security of supply interact with the
decarbonisation objectives
8
; and
how compliance with State aid rules can be ensured when Member States
design and implement capacity mechanisms.
(12)
To that end, the Commission has, as a first step, examined the reasons behind the
introduction of capacity mechanisms and their design features. It has examined a
number of existing mechanisms as well as a number of mechanisms that Member
States plan to put in place. The Commission has looked at those mechanisms in the
wider market context including in particular the growing share of renewable energy.
1.4
The sector inquiry: what has the Commission done so far?
(13)
In order to prepare the interim report, the Commission sent out in spring 2015 detailed
questionnaires to over 200 public bodies, energy regulators, transmission system
operators ('TSOs') and market participants commercially active on any of the eleven
markets under assessment: Belgium, Croatia, Denmark, France, Germany, Ireland,
Italy, Poland, Portugal, Spain and Sweden. The Commission selected these eleven
Member States because they have either introduced or are considering introducing one
or more capacity mechanisms. The combination of Member States was also chosen to
constitute a representative sample of the different types of capacity mechanism being
7
8
For instance between power generators and demand response operators.
For instance by excluding certain technologies, such as lignite (see SWD, chapter 5.2.2.1, page 64) and in accordance
with point 220 of the EEAG.
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developed in Europe. The Commission received in total 124 replies. An overview of
the number of replies per Member State and a breakdown by respondent is provided in
Annex 1.
(14)
Following the public consultation, the Commission received replies from 114
stakeholders from 19 Member States plus Norway and Switzerland. This number
includes replies from 62 associations and 20 public bodies. A breakdown of the replies
is provided in Annex 1.
On 15 June 2016, the Commission also organised a workshop with Member States to
present the findings of the interim report. A particular focus of the workshop was on
the issue of cross-border participation in capacity mechanisms. In addition, bilateral
meetings have been held with several stakeholders to deepen the understanding of
specific issues. Finally, the Commission has made use of a wide array of public
sources of information as well as specialist literature and publications on the topic.
1.5
(16)
Set-up of the Staff Working Document
(15)
It is the aim of this Staff Working Document to present the findings of the sector
inquiry and to draw conclusions regarding the current practice applied by Member
States when contemplating, adopting and operating a capacity mechanism. These
findings and conclusions may be interpreted as guidance provided by the Commission
as to its future assessment of capacity mechanisms under the State aid rules.
The present final report follows the same structure as the interim report. It updates the
information of the interim report and elaborates on certain issues that have received
particular attention in the public consultation or recent case practice. Chapter 2
presents an overview of the state of the electricity market in the EU as a whole and in
particular in the eleven Member States under scrutiny. It explains why many Member
States are concerned about the continued capability of their electricity system to meet
demand at all times and are therefore using or considering to introduce capacity
mechanisms. It subsequently assesses what drives investments in generation capacity
and describes the market and regulatory failures that impact investment decisions in
the electricity market. A number of market improvements are discussed as means to
address the identified failures, whereby it is recognised that residual failures may
persist.
In subsequent chapters the ability of capacity mechanisms to address these residual
market and regulatory failures is analysed. Chapter 3 provides taxonomy of capacity
mechanisms and categorises the capacity mechanisms that have been encountered in
the eleven Member States subject to the sector inquiry. Chapter 4 provides an
overview of the ways in which Member States assess their generation adequacy and
the role of reliability standards in that assessment. Chapter 5 presents in a high level of
detail the preliminary findings of the sector inquiry vis-à-vis the design features of the
8
(17)
(18)
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different capacity mechanisms, organised in three categories: eligibility, the allocation
process and the capacity product. This chapter has been complemented by a
discussion on the mitigation of market power within capacity mechanisms. On the
basis of the findings presented in the previous chapters, Chapter 6 draws tentative
conclusions regarding the suitability of each type of capacity mechanism to address
generation adequacy concerns.
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2.
(19)
I
NCREASED GENERATION ADEQUACY CONCERNS
Generation adequacy concerns arise in the context of the transition of Europe's
electricity sector from national centrally-managed systems based on conventional fuel
to a liberalised and competitive system with substantial shares of variable renewables.
This chapter assesses the changes in the sector so far and presents expected future
developments. The chapter also describes the reasons why the eleven Member States
of the sector inquiry have implemented or are planning a capacity mechanism. Finally,
it underlines the importance of ensuring that the introduction of a capacity mechanism
does not replace market reforms that are better suited to address to core of the
problem.
2.1
The electricity sector in transition
2.1.1
(20)
The liberalisation of electricity markets
Liberalisation and the creation of Single Market for energy have been at the heart of
EU energy policy since the early 1990s. The Third Energy Package
9
, adopted in 2009,
has resulted in the complete unbundling of the supply and generation arms of
vertically integrated undertakings from their transmission activities, thus creating fully
independent transmission system operators (TSOs) and paving the way for
competition to occur in the generation and supply segments of the sector.
In the last decade competitive wholesale markets have appeared in a large majority of
Member States and cross-border trade has intensified significantly. The
implementation of market coupling
10
has enabled an optimal use of interconnection
capacities, ensuring that electricity automatically flows from areas of low prices to
areas of high prices, and the most efficient plants run not just nationally but in entire
regions. Harmonised trading rules for trading in regions comprising several Member
States
11
have fundamentally changed the business models of generators and suppliers
alike. They increasingly take into account cross-border flows and hedge their positions
long term, for instance by closing long term contracts and/or buying transmission
rights, and optimize their positions in the day-ahead and increasingly in even shorter
term intraday markets.
(21)
9
10
11
Directive 2009/72/EC concerning common rules for the
Single Market for
electricity, Directive 2009/73/EC
concerning common rules for the
Single Market for
natural gas, Regulation (EC) No 714/2009 on conditions for
access to the network for cross-border exchanges in electricity, Regulation (EC) No 715/2009 on conditions for access
to the natural gas transmission networks and Regulation (EC) No 713/2009 of the European Parliament and of the
Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators.
The term market coupling refers to the implicit allocation of both the electricity and the available interconnection
capacity at the same time, instead of separately via explicit auctions.
See e.g. the organisation of trading with “capacity calculation regions” of several Member States (Commission
Regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion
management, OJ L 197, 25.7.2015, p. 24–72).
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(22)
Liberalisation has implied a transition from central planning of investments in
generation and capacity towards decentralised decision-making. On the one hand,
investment decisions on generation capacity and on transmission capacity are no
longer taken jointly. On the other hand, investment decisions in generation capacity
are taken autonomously by private undertakings operating in electricity generation.
This shift, together with the new organisation of the relation between generators and
TSOs through unbundling, requires an adaptation of previous adequacy planning
mechanisms, and a robust framework for regulatory supervision of generation
adequacy, including a clear definition of the roles of the different actors in adequacy
planning. Otherwise, the uncertainty about when and where investments in generation
capacity will take place could be uncomfortable for TSOs from a technical
perspective, but also policy makers who bear the ultimate political responsibility for
secure electricity supplies. These considerations are particularly relevant given that
Europe's generation fleet is ageing, potentially creating a need for investments in
generation capacity.
Installed generation capacity has substantially increased over the last two decades, as
a result of investments by both incumbent generators and new entrants. These
investments focused notably on wind and solar technologies, but also on combustible
fuel technologies, especially gas.
(23)
Figure 1: Evolution of installed generation capacity by technology in the EU28 as a
whole
12
Source: European Commission based on Eurostat data
12
Category "Other combustible" is the result of subtracting "Gas turbines" and "Combined cycle" from the category
"Combustible fuels" in Eurostat database on "Infrastructure Electricity Annual data" [nrg_113a].
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2.1.2
(24)
Decarbonisation policies
The energy sector is a large contributor to the EU's carbon footprint but also
contributes in a variety of ways to realise emission reductions. Power companies and
industrial installations in the EU are covered under the EU Emissions Trading System
(ETS), which puts a price on carbon, ensuring that the costs of fossil fuels reflect their
carbon intensity. The ETS is a market based system, in which power companies can
choose whether to buy allowances on the market or to reduce emissions. As the
overall limit on the number of allowances declines and technologies for
decarbonisation are further developed, this provides a stronger incentive to reduce
emissions at a low cost. Additionally, the political determination to encourage
renewable generation through support schemes, resulting in national renewables
targets and the Renewable Energy Directive
13
, has contributed to an impressive
growth in the share of renewables in the EU's energy mix. The increasing maturity and
decreasing investment costs of these generation technologies (the 'learning curve' of
renewables), as well as the expectations of sustained increasing demand for electricity
prior to the economic crisis, have further stimulated the development of RES. By
2013, 26% of the EU's electricity is generated from renewables and about 10% of total
electricity is sourced from intermittent renewable electricity, whose availability
essentially depends on variable factors outside the control of the plant operator, like
the weather conditions in the case of wind and solar.
14
Figure 2: Evolution of wind and solar generation capacity by Member State
Source: European Commission based on Eurostat data
(25)
In most of the eleven Member States covered by this inquiry the generation mix now
consists of substantial shares of variable renewable energy sources (RES). Wind and
solar generation technologies have achieved the largest shares of installed capacity in
13
14
Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on the promotion of the use of
energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC.
European Commission, Renewable energy progress report {SWD(2015) 117 final}.
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Denmark (40%), Germany (38%), Spain (28%) and Portugal (25%). The shares of
variable RES are expected to increase further, in particular as some Member States are
still making progress and increase the share of renewables in their country in order to
reach their 2020 targets.
Figure 3: Installed generation capacity by technology (in %) in each of the 11 MS in
2014
Source: European Commission based on Eurostat data
(26)
The significant increase in renewables has important side-effects for security of
electricity supply. The relatively unpredictable nature of certain variable renewable
sources such as wind and solar makes the electricity system more difficult to manage
for TSOs. Moreover, due to their low marginal costs, RES reduce the running hours of
conventional generation. This effect has been reinforced by further decarbonisation
and environmental policies, including at European level, such as the European-wide
Emissions Trading System, the Energy Efficiency Directive
15
, the Large Combustion
Plant Directive
16
, and the Industrial Emissions Directive
17
.
Concerns about security of supply
Security of supply is one of the three core objectives of EU energy policy. In the
electricity sector, security of supply has a short term and a long term dimension. In the
short term, it is important that the TSO, who is responsible for system security in real
time, has sufficient instruments at its disposal to ensure balance between demand and
supply. In the long run, the electricity system needs to be fit to provide sufficient
electricity to meet demand at all times and in all parts of the system.
2.1.3
(27)
15
16
17
Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy efficiency,
amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC.
Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants.
Directive 2010/75/EU of the European Parliament and the Council on industrial emissions.
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(28)
This section discusses the impact that recent developments in European electricity
markets, mainly driven by the liberalisation and decarbonisation objectives, but also
the economic crisis, are having on the long term adequacy of generation capacity and
security of supply. It assesses the question from three angles: how has the relation
between demand and generation capacity developed, how have utilisation rates of
power plants evolved, and how has the profitability of conventional plants been
affected.
2.1.3.1 Margins between generation capacity and demand have widened
(29)
Total installed generation capacity in the EU-28 has increased by more than 30%
since 2000, reaching a total of more than 1 TW in 2013. This has been a gradual
increase, with the steepest growth starting in the years immediately before the
economic crisis and continuing until 2011. The fact that the growth in total installed
capacity continued to increase during the first years of the economic downturn is
related both to the lag between investment decisions and new generation plants
entering operation and to the continued support schemes, especially for renewables.
While installed generation capacity has increased in all the 11 Member States
investigated in this inquiry, the growth has not been evenly distributed, as shown in
Figure 4.
Figure 4: Evolution of installed generation capacity in each of the 11 MS
Source: European Commission based on Eurostat data
(30)
Contrary to the inertia observed in the evolution of installed generation capacity, the
production and demand of electricity was rapidly impacted by the start of the
economic crisis. Production grew steeply by about 15% between 2000 and 2007,
before starting to decrease during the economic downturn. Between 2008 and 2013,
annual electricity generation in the EU decreased by 5%.
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Figure 5: Evolution of generated electricity in the EU28 as a whole
Source: Eurostat
(31)
The downward trend of demand for electricity has been observed in most Member
States, but with differences across them as well as with some exceptions. In Poland for
example, average demand for electricity continued to grow during the entire period
2000-2013, which is consistent with the mild impact of the crisis on the Polish
economy. In both France and Germany average electricity demand remained broadly
stable during the years of the economic crisis. Average electricity demand dropped
significantly in most other Member States, including Belgium, Croatia, Denmark,
Ireland, Italy, Portugal and Spain.
Figure 6: Evolution of final demand for electricity in each of the 11 Member States
Source: European Commission based on Eurostat data
(32)
Similar trends have been observed for the peak demand, defined as the highest yearly
demand level, of electricity in the Member States covered in the inquiry.
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Figure 7: Evolution of peak demand for electricity in each of the 11 Member States
18
Source: European Commission based on replies to sector inquiry
(33)
The constant increase in total generation capacity since 2000 coupled with the
decrease in average demand since 2008 has widened the margin between average
demand and installed capacity since the beginning of the economic crisis.
Figure 8: Evolution of average demand and generation capacity for the EU28 as a whole
Source: Eurostat
(34)
The margin between average or peak demand and total installed capacity varies across
the 11 Member States. In 2013, the margin was largest in Denmark, Spain, Italy and
Portugal. At the opposite end, it was smallest in Belgium, Croatia, Poland and
Sweden.
18
This graph is based on figures provided by the Member States in the context of the sector inquiry. The figures provided
by Germany were not specific enough to allow for inclusion in this graph.
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Figure 9: Indexed peak demand and generation capacity in each of the 11 Member
States in 2014
Source: Eurostat and European Commission based on replies to the sector inquiry
(35)
Increasing gaps between peak demand and potential supplies may appear to
demonstrate that there is overcapacity in the market. However, that conclusion would
be too simplistic. Resilient electricity systems typically require a supply buffer above
predicted peak demand to protect themselves against unpredicted potential increases
in peak demand, disruptions to supply (e.g. planned and unplanned maintenance of
generation units), or interruptions in the availability of transmission infrastructure.
More importantly, the aggregation of the maximum installed capacity does not take
into account that each technology has a different level of availability and
intermittency, which means that different generation mixes may require different
margins between installed generation capacity and peak or average demand. Finally, a
simple capacity margin often does not include the potential contribution of imports
through interconnectors or the flexibility of the demand-side.
2.1.3.2 Capacity utilisation of conventional generation has decreased
(36)
The contribution of each technology to the effective generation of electricity does not
match the share of each technology in the installed capacity mix. While in 2013
nuclear represented 13% of total installed capacity in the EU28, it produced 27% of
all the electricity generated. This illustrates the fact that nuclear generation units
typically run continuously most of the time during the year.
The opposite applies to hydro, wind and solar: in 2013 they represented 20%, 12%
and 7% of total installed capacity respectively, but contributed just 13%, 7% and 3%
to effective electricity generation. This illustrates the variable nature of these
renewable technologies, which despite their low running costs cannot always generate
due to their dependency on weather conditions.
(37)
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Figure 10: Capacity and generation mix in the EU28 in 2014
Source: European Commission based on Eurostat data
(38)
The deviations between the share of installed capacity of each generation technology
and the share of electricity generated by each technology indicate different levels of
capacity utilisation across technologies. One possible measure of capacity utilisation
is the ratio between the average generation per hour and the installed capacity for each
technology. Figure 11 shows this measure of capacity utilisation for the EU28 by
generation technology.
As expected, nuclear exhibits the highest level of capacity utilisation, stable above
80% since 2000. Capacity utilisation of hydro has also remained broadly stable
throughout the period, albeit at a much lower 30%. Wind and solar have gradually
increased their levels of capacity utilisation over the last years, attaining 23% and 12%
levels respectively in 2013. Of particular interest is the evolution of the capacity
utilisation of combustible fuels, which has significantly decreased since 2005, from
50% to 40%. Hence, the increasing weight of intermittent wind and solar in the
generation mix over the last decade has been accompanied by a lower level of
capacity utilisation for combustible fuel technologies, in particular gas.
(39)
Figure 11: Evolution of capacity utilisation ratio by technology in the EU28 as a whole
Source:European Commission based on Eurostat data
(40)
The correlation between wind and solar penetration and the drop in the capacity
utilisation of combustible fuels can be further illustrated by the evidence from cross-
18
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country data. Those Member States where wind and solar have exhibited a larger
increase in their contribution to electricity generation tend to be also the countries
with the largest drop in the level of capacity utilisation of combustible fuels. Hence,
over the period 2000-2013 in the EU28, there has been a negative correlation between
the increase in the share of electricity generated from wind and solar and the drop in
the capacity utilisation of combustible fuels. A correlation however does not
necessarily imply a causal relationship. The decrease in the utilisation of combustible
fuels is likely to have multiple causes, including for instance the decrease in the
demand for electricity, which tends to affect relatively more flexible technologies with
higher operational costs.
Figure 12: Relation between renewable generation penetration and capacity utilisation
of combustible fuels
Source: European Commission based on Eurostat data
2.1.3.3 Profitability levels for conventional generation have been eroded
(41)
Wholesale electricity prices have shown both significant volatility and common trends
across Member States. Figure 13 depicts the evolution of monthly average spot
electricity prices in France and Germany. In both Member States, spot prices describe
an upward trend in the pre-crisis years and until 2010, while a downwards trend is
observed since 2011.
19
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Figure 13: Evolution of spot electricity prices in France and Germany
Source: European Commission on the basis of Power Exchanges data
(42)
Figure 14 shows similar trends for a price index constructed on the basis of a larger set
of European spot electricity markets.
Figure 14: Evolution of Platts' Pan European Price Index
Source: Platts
(43)
The drop in electricity prices over the last 5 years is the result of a variety of
developments, which includes the lower demand for electricity, the increasing
proportion of renewable technologies with low marginal costs and the increasing
margin between generation capacity and demand.
Lower electricity prices imply lower levels of profitability for generation technologies
whose costs and capacity utilisation have remained largely stable, for instance nuclear
generation. In the case of coal- and gas-fired plants, profitability depends on
electricity prices and capacity utilisation, but also on the development of fuel prices.
(44)
20
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The clean spark spread and the clean dark spread
19
provide an indication of average
profit margins for gas- and coal-based generation, net of EU ETS carbon prices.
Figure 15 shows the evolution of these two indicators in Germany and the United
Kingdom. In both Member States, the clean spark and dark spreads show an erosion of
profitability levels of gas-based generation relative to coal-based generation,
especially between 2012 and 2014. Recent data for 2015 seems to indicate that this
trend might be reverting to some extent.
Figure 15: Evolution of clean gas spark and coal dark in Germany and United Kingdom
Source: Platts global commodity prices, to add: assumption on efficiency of gas fired
(45)
The decrease of EU ETS prices since 2008, and especially since 2011, as shown in
Figure 16, has reduced overall emission-related costs for combustion technologies.
The relative impact has been more favourable for coal-based generation than for gas,
due to the higher carbon emissions of the former.
19
The clean spark spread and the clean dark spread are indicators of the relative profitability of gas and coal. The
Commission has used data from Platts in Figure 15. Platts defines its spark spreads as indicative prices giving the
average difference between the cost of gas and the equivalent price of electricity on any given day. Its dark spreads are
indicative prices giving the average difference between the cost of coal and the equivalent price of electricity on any
given day. More information on which UK and German gas, power and coal prices were used is provided here:
https://www.platts.com/IM.Platts.Content/methodologyreferences/methodologyspecs/european_power_methodology.p
df.
21
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Figure 16: Evolution of EU ETS carbon price
Source: European Commission, based on ICE data
(46)
Additional factors that might have contributed to the increase in the relative
profitability of coal-fired power plants vis-à-vis gas-fired power plants in Europe are
the massive shift to shale gas in the US and the switch from nuclear to gas in Japan,.
All these factors have contributed to make coal-based generation less costly on
average than gas-based generation. Gas-based generation of electricity increased
steadily until 2010, but has significantly decreased since 2011. Conversely, coal-based
generation has increased since 2010, reflecting the change in the relative positions of
gas and coal in the merit order curve.
(47)
Figure 17: Evolution of gross generation of coal and gas in the EU28
Source: European Commission based on Eurostat data
22
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(48)
Coal- and gas-based generation are the main source of flexible generation. In case
renewable sources are not available, gas generation is considered, among fossil fuels,
to be a particularly suitable back-up for RES, due to its ability to ramp up and down
relatively quickly, its relative advantage in terms of emissions as compared to coal and
the relatively abundant supply of gas worldwide. The erosion of both the utilisation
rates and profitability levels of gas-fired power plants impacts the business case of
existing units. Although investment decisions are not just based on current prices but
also on long term expectations, this erosion of profitability also dis-incentivises
investments in new plants, which in turn increases long term generation adequacy
concerns.
2.1.3.4 Ageing of coal and nuclear plants
(49)
A significant proportion of current installed generation capacity is approaching the
limit of its operational life. Most nuclear plants have been in operation already for 20
to 30 years, and will be older than 30 years by 2020. In Europe, little investment in
new nuclear plants is planned and a number of countries are phasing out their nuclear
fleet. While investments are being made to extend the life of a number of nuclear
plants, notably in France, a significant share of nuclear generation capacity may close
in the coming decades.
Combustible fuel plants are more evenly distributed across age intervals, the oldest
being mainly coal plants and the younger being mainly gas plants, especially
combined cycle gas plants. Coal plants are candidates to be gradually phased out, not
only due to their age, but also as a consequence of environmental policies.
Regarding renewables, most hydro plants are older than 30 years, but their operational
life is not as limited as for nuclear and coal plants. They are expected to keep
operating for many decades, provided the necessary maintenance investments are
made. Wind and solar generation units are the youngest in the capacity generation
mix, most of them having been operational for less than 20 years.
(50)
(51)
23
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Figure 18: Distribution of age of power plants per type of generation
Note: "2020 f" refers to forecasts for 2020.
Source: Platts Power Vision
2.2
(52)
Incentives for future investment in generation
Declining demand and increasing shares of renewables resulted in decreasing
profitability of electricity generators, especially conventional flexible technologies.
The trend to more generation from intermittent technologies constitutes an economic
challenge for the business model of many established energy companies with a fossil
fuel-based generation fleet
20
. While the shift towards more renewable energy
production is, on the one hand, a welcome development resulting from the
decarbonisation of the generation fleet, its impact on security of supply must be taken
into consideration and managed. In this context, combined with the general ageing of
existing power plants, the question of whether investments in generation capacity will
be sufficient to guarantee an adequate generation fleet to meet future demand has
gained prominence.
20
Though some stakeholders have noted that the expansion of renewables could have been planned in a way that allowed
investors to better anticipate the eventual outcome on the running hours and profitability of conventional power plants.
24
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(53)
To the extent that low profitability reflects an excess of installed generation capacity,
the resulting lower incentives to invest may be a sound economic signal to correct for
overcapacity. However, if low profitability is the consequence of market and
regulatory failures, then incentives to invest may prove insufficient to maintain
adequate generation capacity in the medium and long term. It is therefore important to
assess what drives investments in the European electricity markets of today and how
that will influence the generation mix of the future.
This section presents the evidence obtained from the sector inquiry on the
expectations of public bodies and market participants about future installed generation
capacity and capacity margins, and discusses, on the basis of empirical evidence as
well as economic literature on the subject, the market and regulatory failures that
impact the incentives to invest in generation capacity.
Expectations about future development of generation and demand
The sector inquiry responses show that total projected installed capacity will increase
at a slower pace than demand in six out of the nine Member States where data was
available.
(54)
2.2.1
(55)
Figure 19: Evolution of projected installed capacity and demand by Member State
Source: European Commission based on replies to sector inquiry
(56)
In the Member States where this trend is reversed (Belgium, Ireland and Poland) the
main contributor to the increase in projected installed capacity is the investment in
renewable generation capacity.
25
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Figure 20: Current and projected installed wind and solar generation capacity in GW
Source: European Commission based on replies to sector inquiry
(57)
The responses also show that, despite significant investment in gas generation in
recent years, expectations of future investments in gas generation are rather low; no
Member State except Poland expects material increases in gas-fired generation
capacity.
21
Figure 21: Current and projected installed gas-fired generation capacity in GW
Source: European Commission based on replies to sector inquiry
(58)
Several signals may have contributed to this moderation in planned investments in
gas-fired generation capacity. First, the growth in demand is expected to be modest, at
least below pre-crisis levels. Second, lower coal prices and the fall in the ETS prices
have had a positive impact on the profitability of coal-fired power plants at the
expense of gas-fired competitors.
21
The Polish Electricity Association explained that this concerned only CHP plants mainly due to a CHP support scheme
and a business case based on industrial heat sales.
26
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(59)
Lower profitability for flexible conventional technologies resulting from these
developments has a negative impact on incentives to continue investing in these types
of technologies. The increasing risk perceived by investors as a consequence of the
reduction of operating hours during which these technologies expect to have to recoup
costs and get appropriate remuneration further contributes to erode incentives to
invest.
Incentives to invest shape the energy mix of the future and therefore determine the
level of reliability that mix will provide. The relation between incentives to invest in
generation capacity and the desired level of reliability is therefore the core challenge
from a regulatory perspective
.22
In the context of the sector inquiry, 88% of public
bodies that responded to the questionnaire expressed that no reliability problems had
been observed in their Member States over the last 5 years, but 69% of them expected
reliability problems to arise in their Member States in the future. This indicates that
there are concerns among public bodies regarding future reliability.
It is therefore important to understand whether electricity markets provide sufficient
incentives to invest whenever new investments into generation become necessary. The
time dimension is a relevant factor, given the lead times between investment decisions
and operability of the new generation capacity. Expectations about future market
prices are therefore typically more determinative than current market prices and, in
terms of ensuring generation adequacy at all times, an important question is whether
investments are done timely. The remainder of this chapter explains what incentives
electricity markets can be expected to provide and why they may be insufficient to
guarantee adequate generation capacity and reliability in the future, in particular if
certain market and regulatory failures are not addressed through further market
reform.
Market and regulatory failures undermining incentives to invest
As in any other sector, investment decisions crucially depend on the returns that
private investors expect to obtain. In the case of electricity generation, either through
revenues from electricity trading/sales or other channels (e.g. selling ancillary
services
23
, or participating in capacity mechanisms or renewables support schemes).
(60)
(61)
2.2.2
(62)
22
23
As Cramton P., Ockenfels A. and Stoft S. (2013) explain it: "the heart of the adequacy problem is resolving the trade-
off between more capacity and more blackouts."
Directive 2009/72/EC defines ancillary service as: ‘a service necessary for the operation of a transmission or
distribution system.' Examples of such services that TSOs can acquire from generators are electricity for the
compensation of grid losses, regulating power and emergency power.
27
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(63)
Electricity markets where generators obtain revenues only from selling electricity,
balancing power
24
and providing ancillary services have been termed 'energy-only
markets' in the economic literature. In such markets, generators take their decisions to
invest in maintaining current capacity and installing new capacity on the basis of their
expectations of future earnings obtained exclusively from these revenue streams.
Hence, in an energy-only market, supply and demand for electricity determine the
profitability of generation activities and the incentives to invest in future generation
capacity.
Current liberalised electricity markets in the EU are imperfect examples of energy-
only markets, given that in most Member States some or all generators obtain
revenues through channels other than market prices, for instance in the form of
subsidies and payments that affect their incentives to invest in generation capacity.
The economic literature has extensively discussed whether different models of
electricity wholesale markets can be expected to generate sufficient incentives to
invest to guarantee adequate generation capacity. When this is not the case, a so-called
'missing-money' problem arises: the market proves unable to incentivise investment in
adequate generation capacity because investors fear future revenues will not cover
their fixed costs and will not appropriately remunerate their investment.
25
The missing-money problem is mainly related to the potential inability of electricity
markets to deliver sufficiently high prices during periods of scarcity – as explained in
the next Section – although other factors have been discussed in the economic
literature that can also contribute to the lack of incentives to invest, such as the public
good features of system reliability and the uncertainty about expected returns on
investments in generation capacity.
2.2.2.1 Factors undermining price signals in electricity markets
(64)
(65)
(66)
(67)
Prices in competitive electricity markets reflect to a large extent the operating costs of
the generation plants that are activated to serve the demand for electricity. However,
this is not always the case even in very competitive markets. In principle, wholesale
prices in perfectly competitive electricity markets equal the marginal cost of the most
24
25
To the extent that balancing power markets foresee remuneration based on availability in addition to delivery, they
already embed some payment for capacity and thus cannot be considered purely energy-only markets in strict sense.
However, such payments for availability are designed mainly to provide short-term balancing possibilities, rather than
long-term generation adequacy. Moreover, these markets represent relatively low traded volumes relative to the overall
level of capacity.
As Joskow P. L. (2013) puts it, "the revenue adequacy or missing money problem arises when the expected net
revenues from sales of energy and ancillary services at market prices provide inadequate incentives for merchant
investors in new generating capacity or equivalent demand-side resources to invest in sufficient new capacity to match
administrative reliability criteria at the system and individual load serving entity levels."
28
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expensive generation unit being utilised at every moment in time, provided that there
is sufficient available supply to meet demand at such price. But this is not always the
case because sometimes demand for electricity comes close to or may even exceed the
total available generation capacity, leading to a situation of scarcity. In such
circumstances, market prices typically rise above marginal cost to contract demand
and allow the market to clear. These transitory prices above operating costs produce
margins that remunerate the fixed costs of marginal generating units. An energy-only
market relies to a large extent on the rents generated during periods of scarcity to
provide sufficient incentives for generators to invest in capacity.
26
(68)
The theoretical efficient functioning of this market design depends on a number of
assumptions that are rarely satisfied in existing wholesale electricity markets, in
particular that the demand can respond to variations of wholesale prices in real time
and that generators do not enjoy a significant degree of market power.
The demand for electricity is typically insufficiently responsive to prices because
currently prevailing technical features of electricity delivery do not allow most
customers to respond to price variations in real time. As a consequence, there may be
situations when the wholesale energy market cannot clear, because demand remains
above available generation capacity independently of the price level. In such
circumstances, some kind of regulatory intervention is needed to bring supply and
demand in balance, e.g. by rationing demand and administratively setting a price.
Economic theory indicates, under certain assumptions, that during periods of rationing
it is optimal to set a price at the level of the value of lost load (hereafter, 'VOLL').
VOLL is equal to the marginal consumer surplus associated with a unit increase in
electricity supplied to rationed consumers. In other words, it expresses the value
attached by consumers to uninterrupted electricity supply. A regulated price at the
level of VOLL when the market does not spontaneously clear would in theory provide
incentives to invest in generation capacity that reflect consumers' average willingness
to pay for security of supply.
27
(69)
(70)
26
27
As Cervigni G. and Perekhodtsev D. (2013) explain, "pricing in conditions of scarcity is a crucial element of the
wholesale electricity market's design. Since the available generation capacity is far greater than demand in most hours,
the competitive market-clearing price very rarely departs from the system marginal cost. Therefore the generating units
with the highest variable costs rely on the extremely high prices prevailing during very few hours of scarcity to cover
their fixed costs."
As Cramton P., Ockenfels A. and Stoft S. (2013) explain: "The market responds to VOLL by building additional
capacity up to the point where a MW of capacity costs just as much as it earns from being paid VOLL during blackouts.
(…) So at this point the cost of capacity equals the value of capacity to consumers, and beyond this point, consumer
value per MW can only decline as the system becomes more reliable. Hence, the VOLL pricing rule causes the market
to build the second-best, 'optimal' amount of capacity. This solves the adequacy problem – with help from a regulator."
A first-best solution can only be obtained by enabling a fully responsive demand-side allowing the market to clear at all
times on the basis of individual consumers' preferences however, and a capacity mechanism in which the amount of
29
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(71)
In most Member States price caps currently exist which are not based on estimates of
average VOLL, but often on the technical bidding limits used by power exchanges.
Although the national authorities in Denmark, France, Ireland, Italy, Poland, Portugal
and Sweden have all made estimates of VOLL in their markets, only Croatia and
Denmark indicated that price caps in their markets were influenced by the estimated
VOLL.
Although VOLL has not been calculated in some Member States, many Member
States that have calculated it report values that are well above day-ahead market price
caps. Table 1 reports the price caps and estimates of VOLL in each of the 11 Member
States, as obtained from responses to the sector inquiry.
(72)
Table 1: Maximum price caps in the 11 Member States
28
Wholesale Price Caps and estimates of VOLL (EUR/MWh)
Country
Belgium
Denmark
Croatia
France
Germany
Ireland
Italy
Poland
Portugal
Spain
Sweden
Day-ahead
3,000
3,000
3,000
3,000
3,000
1,000 (moving to
3,000 in future)
3,000
~350
180
180
3,000
Intraday
9,999
No cap
No exchange
trading. No OTC
cap.
9,999
9,999
1,000 (moving to
3,000 in future)
3,000
No cap
180
180
No cap
Balancing
4,500
5,000
Estimate of
VOLL
29
n.a.
Between 2,933
and 36,800
n.a.
26,000
n.a.
No cap
9,999
No cap
No balancing
market. Price cap
TBC for future
market design
3,000
~350
No cap
No cap
5,000
11,017.98
3,000
Between ~1,250
and ~2,100
3,000
n.a.
Between ~2,800
and ~7,600
Source: European Commission based on replies to sector inquiry
(73)
The cross-country variation observed in the VOLL estimates reported show the
heterogeneity of electricity demand across countries, but may also reflect differences
in methodology. In practice it can be a challenge to estimate the VOLL accurately, so
capacity to subsidise is set based on estimates of average consumer willingness to pay will also deliver a 'second-best'
outcome.
Note that in some countries these are technical price caps that may constrain bidding on exchanges but are not an
absolute regulatory cap on prices and would not prevent OTC exchanges at higher prices.
Note where there are wide bands, this may be because studies identified different VOLLs for different consumer
classes, and/or because studies identified different VOLLs depending on the duration and frequency of lost load.
28
29
30
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that it can be confidently expected that VOLL-based administrative prices incentivise
the optimal level of investments in generation capacity, reflecting the real consumer
willingness to pay for additional security of supply.
30
Notwithstanding, rigorous
VOLL estimates remain the best approximation to what the optimal administrative
price cap would be.
(74)
However, the potential exercise of market power or the risk of market manipulation
might also have influenced the relatively low price caps seen in many markets. When
generators enjoy some degree of market power, they may abuse it by engaging in
withholding capacity or strategic bidding to increase wholesale electricity prices to
their benefit. The risk that generators implement such strategies is particularly high
when the system approaches situations of scarcity, because in these circumstances
virtually every generating unit becomes pivotal and enjoys some degree of market
power.
31
The current lack of demand response to wholesale price variation further
contributes to making the exercise of market power more likely and profitable,
because increases in prices do not trigger any significant reductions in the final
demand for electricity
.32
Regulators and competition authorities may find it difficult to distinguish instances of
exercise of market power abuse and market manipulation from genuine scarcity
conditions. In both cases the main observable market outcome is higher wholesale
prices. Generators can for instance disguise withholding of capacity as technical
maintenance or failure. It is not easy either to assess whether generators bidding above
their running costs are legitimately seeking to cover their fixed costs, or are seeking to
make windfall profits thanks to the lack of sufficient competition or demand response.
However, when asked whether concerns about market power had influenced decisions
on price caps in their markets, only the Polish national authorities and the Spanish
Regulator confirmed. Belgium, Denmark, France, Ireland, Italy, Portugal, the Spanish
Government and Sweden denied.
A number of market-power mitigation measures have been applied in wholesale
electricity markets – apart from permanent scrutiny by competition authorities and the
See Cramton P., Ockenfels A. and Stoft S. (2013).
As Joskow P. L. (2008) explains: "Unfortunately, the supply and demand conditions which should lead to high spot
market prices in a well-functioning competitive wholesale market (i.e. when there is true competitive 'scarcity') are also
the conditions when market power problems are likely to be most severe (as capacity constraints are approached in the
presence of inelastic demand, suppliers' unilateral incentives and ability to increase prices above competitive levels,
perhaps by creating contrived scarcity, increase)."
As Spees K. and Lave L. B. (2007) explain referring to some past experiences in US markets: "A serious problem with
the deregulated market structure is that the system operator creates an auction market where demand is completely
unresponsive to price and all successful generators are paid the market price; this market design offers an all but
irresistible temptation for generators to manipulate the market, sending prices soaring, as happened in California in
2000."
(75)
(76)
(77)
30
31
32
31
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increased monitoring of electricity trading under the REMIT Regulation
33
– including
forced capacity divestitures, long-term contracts, virtual power plants
34
and price caps.
The latter two are more likely to create or contribute to a missing money problem
because they are based on constraining the ability of prices to increase in periods of
scarcity.
35
Especially price caps close to the marginal operating cost of the last
generation unit in the merit order curve might help mitigate concerns about
anticompetitive behaviour, but they are also likely to create or exacerbate the 'missing
money' problem by curbing scarcity rents earned by generators.
(78)
Allowing prices to rise to VOLL in periods of scarcity is likely to entail very high
wholesale prices, albeit during short periods of time. Concerns have been raised that
such high prices may be politically or socially difficult to accept where there is a
perception that relying exclusively on scarcity pricing entails higher risks (for
instance, spilling over to retail markets) than alternative measures based on
remunerating capacity through out-of-the market channels.
36
However, experience in
several countries shows that wholesale market participants may be able to hedge
against short-term price peaks, with limited additional costs for end consumers.
In response to the public consultation and inquiry questionnaires, stakeholders have
identified other factors that may lead to price caps being set below VOLL. The system
operator in Belgium and the national authorities in Denmark and Italy identified the
Commission Guideline on Capacity Allocation and Congestion Management, which
requires the establishment of 'a proposal on harmonised maximum and minimum
clearing prices to be applied in all bidding zones which participate in single day-ahead
coupling…[taking]… into account an estimation of the value of lost load'
37
, as a
potential constraint on national authorities' discretion regarding national price caps.
France and Germany also explained that in their markets no regulatory price caps have
been set and the only caps are set by the exchanges. Some respondents to the sector
inquiry noted that the higher the potential market prices and therefore risk market
participants are exposed to, the greater the requirements for collateral and the more
expensive it will become to operate on the market.
Regulation (EU) No 1227/2011 of the European Parliament and of the Council of 25 October 2011 on wholesale
energy market integrity and transparency.
Under a virtual power plant or VPP scheme the incumbent party is obliged to sell some of his generation capacity to
third party market participants (e.g. new entrants). The buyer of the VPP contract has the option to consume power of
his VPP against the agreed virtual production cost, but not the obligation and hence the contract can be seen as a call
option. VPPs have been imposed by competition authorities in Europe both as a remedy in merger cases and to address
dominance.
For a more in-depth discussion of the various market-power mitigation measures see Cervigni G. and Perekhodtsev D.
(2013).
As Besser J. G., Farr J. G. and Tierney S. F. (2002) claim: "In theory, energy and ancillary service markets alone can
provide incentives for investment in electricity supplies. However, they can only do this by subjecting consumers to
price volatility, price levels, supply shortages, and a level of risk to reliability that costumers and policymakers would
find unacceptable."
http://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1445614788889&uri=CELEX:32015R1222.
(79)
33
34
35
36
37
32
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(80)
While the discussion on the need for price caps and their optimal level is important in
terms of market design, price caps may not be the only factor effectively limiting
market prices. Despite the existence of price caps lower than VOLL in many markets,
price caps have rarely been reached in recent years in the Member States covered by
the sector inquiry. Table 2 shows the maximum prices experienced in each of the last
five years. Over the last five years, price caps were reached only in Denmark, Ireland,
Italy, and Portugal. In each of Denmark and Ireland caps were only reached on a
single occasion.
38
Regarding the reasons why price caps have only rarely been reached, most Member
States' national authorities that chose to comment suggested that this reflects that
markets are currently well supplied and there have not been many occasions where
electricity was scarce.
(81)
38
In Denmark, prices reached the then cap of EUR 2000 / MWh once, on hour 11 of 7 June 2013. In Ireland, prices
reached the EUR 1000 / MWh cap once in the 0530 balancing period on 26 February 2013. In Italy, the EUR 3000 /
MWh price cap has been reached more frequently – for 31 intraday trading hours in 2011, once in the day ahead market
and for four intraday trading hours in 2012, for two intraday trading hours in 2013, for 16 intraday trading hours in
2014 and for eight intraday trading hours in 2015. In Portugal intraday price caps have also been reached relatively
often – for four hours in 2012, nine hours in 2013 and six hours in 2015.
33
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Table 2: Highest prices experienced in the 11 Member States (EUR/MWh)
Source: European Commission based on replies to sector inquiry
(82)
Moreover, prices in every market timeframe (i.e. intra-day, day-ahead, etc.) are
interdependent and the incentives of market participants are influenced by their
34
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expectations about prices in markets closer to delivery. The rules by which imbalance
settlements are calculated can for instance affect bids in the day-ahead market: even if
there is no price cap in the day-ahead market, electricity suppliers will never choose to
pay more for electricity in the day-ahead market than what they would be charged for
being out of balance through imbalance settlement. Also, even if the balancing market
price is in principle uncapped, the activation of operating reserves, dispatching
emergency demand response or implementing voltage reductions are sometimes used
to balance supply and demand that supress price signals, instead of implementing
involuntary curtailments of demand and let the balancing price rise up to VOLL.
39
If
these balancing services are not charged to reflect their full costs (including the cost of
the unmet demand at VOLL), price signals in all market timeframes will be distorted,
and market participants will adapt their behaviour accordingly. In all these cases,
balancing rules and interventions may impose an implicit cap on electricity prices.
(83)
Another important way in which market prices may be artificially capped is through
an inefficient delineation of bidding zones, as set out in more detail in Section 2.3.1.3.
Where supply and demand is matched in a large bidding zone in which there is
frequent internal congestion, the price formed by the market does not reflect the
critical location of supply relative to demand. TSOs will make costs to manage the
congestion, mostly by applying redispatch measures, which are generally smeared out
over all consumers in the zone. The price formed in the part of the bidding zone with
excess generation will tend to be higher than it would be if low local demand rather
than bidding zone-wide demand was used to set the price. And the price formed in the
part of the bidding zone with excess demand will be too low to reflect the local reality.
This is another way in which regulatory failures can cause missing money and prevent
the appropriate investment signals. The market distortions created can also have a
significant distorting effect on competition and trade – for example because prices in
areas of high demand are too low (effectively subsiding consumers in those locations)
and because unscheduled flows
40
constrain the commercial use of interconnection,
preventing trade to and from the zone and undermining incentives for further
investment in interconnection.
Finally, electricity prices may not properly reflect scarcity if generators self-constrain
their offers to avoid a perceived risk of competition law enforcement. Although there
(84)
39
40
See Pfeifenberger J., Spees K. and DeLucia M. (2013).
Deviations between scheduled flows and physical flows are defined as unscheduled flows. Loop flows are generally
defined as those unscheduled flows that are caused by scheduled flows within a neighbouring bidding zone. ACER has
undertaken extensive research into the occurrence of loop flows and the negative impacts they have on cross border
flows, trade and social welfare in its Market Monitoring Report 2015:
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_
2015.pdf.
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are exceptions
41,
in principle generators are free to offer electricity at prices above
their short run marginal costs. Some respondents to the sector inquiry questionnaires
and consultation noted that overarching antitrust and sector competition rules
(REMIT) place limitations on acceptable market behaviour. While this is true, and it is
important to ensure that market power abuse can be detected and penalised and that
consumers are protected when competition cannot ensure markets deliver fair
outcomes, these rules should not be seen to prohibit the formation of high electricity
prices when electricity is scarce.
(85)
The European Court of Justice defined an excessive/unfair pricing abuse as charging a
price which “has no reasonable relation to the economic value of the product”.
42
The
Court proposed a two-limb test to determine whether or not this is the case: (1) assess
“whether the difference between the costs actually incurred and the price actually
charged is excessive” and, if so, (2) assess “whether a price has been imposed which
is either unfair in itself or when compared to competing products”.
43
Regarding the
first limb of the test, it is settled case law that the “costs actually incurred” do not only
include variable costs but all the production costs, including fixed costs.
44
The
comparison between prices and costs actually incurred should therefore not be limited
to short run marginal cost, but should also include fixed production costs.
45
Furthermore, the presence of a second limb in the United Brands test signals that it is
not sufficient for the antitrust authorities to show that the price charged is high
compared to the costs actually incurred to conclude that such price constitutes an
infringement to antitrust rules. Instead, the authorities also have to demonstrate that
this price is unfair in itself or when compared to competitive benchmarks. The
underlying idea is that even dominant undertakings may have legitimate reasons to
charge high prices compared to their cost of production, not having to do with their
dominant position. In the words of the United Brands judgment, the authorities
therefore have to show that “the dominant undertaking has made use of the
opportunities arising out of its dominant position in such a way as to reap trading
benefits which it would not have reaped if there had been normal and sufficiently
In Ireland a 'Bidding Code of Practice' states that generators must sell electricity to the pool at the marginal cost of
producing each unit of electricity, as well as a licence condition in all generation licences requiring short run marginal
cost bidding. In Italy generators deemed to have a pivotal locational position can be termed 'must-run' units and face
specific bidding restrictions, and in 2010 ENEL made commitments in the context of an antitrust case (case A4233,
ENEL – Dinamiche formazioni prezzi mercato Energia elettrica in Sicilia) to limit offers from its plants in Sicily until
new interconnection was constructed. The Croatian regulator and the Portuguese national authorities indicated that in
principle generators were not free in their markets to bid above their short run marginal costs but did not refer to any
specific rules stating this. Ireland is abandoning the current blanket restrictions as part of its move to the new I-SEM
market design.
Case 27/76,
United Brands v Commission,
ECLI:EU:C:1978:22, para 250.
Case 27/76,
United Brands v Commission,
ECLI:EU:C:1978:22, para 252.
Case 27/76,
United Brands v Commission,
ECLI:EU:C:1978:22, para 251 and 254.
This is also evidenced by the price-cost comparison made by the European Commission in its Port of Hesingborg
decision (see Case COMP/A.36.568/D3 – Scandlines Sverige AB v Port of Helsingborg).
(86)
41
42
43
44
45
36
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effective competition.”
46
This might be done either by looking at competitive
benchmarks or directly by estimating the economic value of the product.
47
(87)
Finally, it is also settled case law of the European Court of Justice that "a dominant
undertaking [should] set its prices at a level covering the great bulk of the costs
attributable to the supply of the goods or services in question"
48
. It can therefore also
be derived from case-law of the European courts on predatory pricing abuses that
dominant electricity generators can legitimately seek to recover not only their variable
costs but also their fixed investment costs. These fixed costs would in principle
49
not
be recouped by a peaking plant at the end of the merit order curve bidding its short run
marginal cost.
2.2.2.2 Uncertainty on returns increases risk premiums required by investors
(88)
Generators' expectations about future returns on their investments in generation
capacity are affected not only by the expected level of electricity prices, but also by
several other sources of uncertainty, such as increasing price volatility, recurrent
regulatory reforms and the uncoordinated decisions of competitors.
The increasing weight of intermittent renewable technologies makes prices more
volatile and shortens the periods of operation during which conventional technologies
are able to recoup their fixed costs.
50
In such circumstances, even slight variations in
the level, frequency and duration of scarcity prices have a significant impact on the
expected returns on investments, increasing the risk associated to investing in flexible
conventional generation technologies.
Since the onset of the liberalisation of electricity markets, regulatory frameworks have
gradually evolved over time, and are expected to continue to change to respond to the
political objectives of decarbonisation, affordability and security of supply. Given the
relatively long time periods over which investments in generation capacity are
typically expected to be recouped, the lack of a stable regulatory framework adds
uncertainty regarding the expected returns on investments in capacity.
(89)
(90)
46
47
48
49
50
Case 27/76,
United Brands v Commission,
ECLI:EU:C:1978:22, para 249.
See Case COMP/A.36.568/D3 – Scandlines Sverige AB v Port of Helsingborg for examples of relevant elements to
consider when determining the economic value of a service/product.
Case C-209/10, Post Danmark AS v Konkurrencerådet, ECLI:EU:C:2012:172, para 38.
Unless demand response is setting higher prices in the market that this plant can capture, or market rules enable prices
at times of scarcity to be set based on the value to consumers of secure supplies rather than the direct costs of
generation.
Cramton P. and Ockenfels A. (2012) note that "all these effects imply that the 'missing money' problem is becoming
more severe as the renewables' share grows." In the same vein, Joskow P. L. (2013) considers that "the expansion of
subsidized intermittent generation and other subsidized generating investments have exacerbated and complicated the
problem."
37
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(91)
Investment decisions in the electricity sector are typically taken long before returns on
investment are effectively earned, due to the time needed to construct new power
plants. At the same time, the decentralised nature of investment decision-making
means that each generator has limited information about the generation capacity that
competitors will made available in the coming years. This constitutes an incentive to
delay investments until there is sufficient reassurance that additional generation
capacity is actually demanded in the market.
51
This may be less problematic where
generation with shorter planning and construction times is sufficient to ensure
adequacy (for instance, small and highly flexible gas plants in certain areas), but may
be more problematic where larger power plants with longer lead times of 10-15 years
are required. The result is what has been referred to as boom-bust cycles: alternate
periods of shortages and overcapacity resulting from lack of coordination in the
investment decisions of competing generators.
52
Investors factor in all these sources of uncertainty when making their investment
decisions. Different authors give different weight to each of these factors,
53
but they
all contribute to increase risk for investors.
54
If investors demand larger risk
premiums, energy-only markets may not be able to generate sufficient incentives to
invest even with high scarcity prices.
2.2.2.3 Public good features of reliability lead to insufficient investment signals
(92)
(93)
The reliability of electricity systems has certain features of a public good. On the one
hand, investments in capacity to increase the system's overall reliability to meet the
preferences of the most demanding consumers also reduce everyone else's risk of
supply interruption at no extra cost (in economic terms, this is the feature of 'no
rivalry'). On the other hand, it is currently not possible for most individual final
consumers to be selectively disconnected by the system operator on the basis of their
51
52
53
54
According to De Vries L. J. (2007), there "are reasons for generating companies to delay investments until the need for
generation capacity becomes reasonably certain. (…) Depending on the growth rate of demand, investment in reaction
to price rises may not arrive soon enough to prevent a significant period of shortages."
Cramton P. and Ockenfels A. (2012) formulate this in the following terms: "In a pure-market design, the decisions to
build new capacity are made independently. This induces strategic uncertainty: because one's investment in new
capacity tends to be more profitable if others invest less, there are incentives to not or to misinform about one's own
intentions. This seems partly reflected by the observation that there is typically a significant gap between the
announced plans to build new plants and actually executed plans. (…) The optimal strategy implies a random element
and so the outcome is likely to be inefficient."
Joskow P. L. (2008) for instance, notes that "large investments in production facilities whose output exhibits significant
price volatility occur all the time (e.g. oil and natural gas)", but acknowledges the relevance of regulatory uncertainty
"as policymakers have not been shy about ex-post adjustments in electricity market designs and residual regulatory
mechanisms, sometimes by a desire to hold up existing generators opportunistically."
As De Vries L. J. (2007) explains, "for generating companies, investing in excess of the socially optimal volume of
generating capacity means that competitive prices will be too low to recover their investment, while a volume of
generating capacity that is below the social optimum leads to significantly higher average prices, which offset the lost
turnover at least partly."
38
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individual VOLL (this is the feature of 'non excludability'). These two features are the
ones that characterise a public good from an economic perspective.
(94)
This means that in events of scarcity each consumer's likelihood of being disconnected
is independent of his VOLL, making him unwilling to pay for reliability as much as he
would otherwise be willing to. Economic theory thus suggests that in such
circumstances a decentralised competitive market is likely to provide suboptimal
incentives for generators to invest in generation capacity, which would therefore
ultimately deliver suboptimal levels of system reliability compared to what consumers
would have been willing to pay for if they were able to be individually disconnected
on the basis of their individual VOLL.
55
Conclusions on the lack of optimal incentives to invest
European electricity markets suffer from a number of market and regulatory failures
undermining investment incentives. Demand for electricity is largely inelastic due to
technical factors and regulatory barriers, which implies lack of responsiveness of
demand to price variation and leads to inefficient price signals. System operators use a
variety of tools to force the market to clear in ways that supress market price signals.
Price caps are often set below VOLL. Uncertainty about expected future returns on
investment in generation capacity contributes to undermine incentives to invest.
Electricity markets in the eleven Member States share most of these characteristics. It
is therefore understandable that authorities and stakeholders pose the question whether
the current design, rules and structure of electricity markets may lead to problems of
generation adequacy in the future, even though there may not exist such a problem
today. Answering this question requires an in-depth assessment of the current situation
of electricity markets, as well as of the expected evolution of both the demand and the
supply sides in the coming years.
2.3
(97)
What is being done to alleviate imperfections of EU electricity markets?
2.2.3
(95)
(96)
Against the backdrop of reduced investment incentives and increased concerns about
reliability levels in the future, Member States can on the one hand attempt to alleviate
imperfections of the current markets and on the other consider intervening in the
market by providing additional incentives to invest via separate payments that directly
remunerate capacity. This section assesses the improvements that have been proposed
and are being carried out on a national and European level to address the market and
regulatory failures in today's electricity markets and assesses to which extent residual
generation adequacy problems may exist that can be addressed by capacity
mechanisms.
55
See Abbot M. (2001).
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2.3.1
(98)
Improving the functioning of the electricity market
Both at national and European levels, efforts are underway to implement better market
designs and regulation aimed at improving market functioning. There is general
consensus that there exists room for improvement of the efficiency of electricity
markets, most notably by enabling demand response, broadening supply-side
participation and improving the efficiency of market outcomes, especially during
scarcity events.
2.3.1.1 Setting appropriate price caps and enabling the formation of scarcity prices
(99)
In a well-functioning market, prices that reflect VOLL when there is a risk of unmet
demand can potentially provide reliable signals for investment in the overall mix of
capacity with the right flexibility and reliability characteristics needed to meet
demand. Even if a capacity mechanism is introduced, appropriate electricity scarcity
price signals will continue to be important
56
. As discussed in the previous section,
allowing extremely high price peaks may present policy makers with other regulatory
challenges, for instance because of the potential for abuse of market power. But most
Member States did not agree that concerns about market power had influenced the
choice of price caps in their markets, and the only reason given for not increasing
price caps was the potential for increased exchange collateral requirements increasing
overall system costs. Further work to quantify these costs and compare them against
the expected efficiency benefits that sharper prices should bring would be useful to
inform the future decisions on price caps required in the context of CACM.
Balancing markets
(100) As already explained in the previous sections, the maximum price in any forward
market is constrained by the maximum prices charged in the balancing market, which
functions as an implicit price cap for electricity prices in forward markets. Some
Member States already have no price caps in the balancing market, yet have not
experienced prices reflecting VOLL even when there has been scarcity. This can be
the case when the balancing price, while not being subject to a cap, does not reflect
the full cost of the services used to balance the market or the full cost of the unmet
consumer demand (represented by VOLL). Member States should therefore ensure
that balancing market rules, even in the absence of an explicit price cap, do reflect the
full costs of balancing and do not implicitly constrain electricity prices in forward
markets.
56
In all European markets it is electricity prices that determine how interconnection between bidding zones is used and
help ensure that imports are available to bidding zones experiencing scarcity, and in many capacity mechanisms
designs – particularly those with a reliability option capacity product (see section 5.4) – the electricity price provides
the signal for short term delivery of electricity and for investments in flexibility.
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Administrative scarcity pricing
(101) Administrative scarcity pricing consists in the introduction of rules to ensure that
electricity prices are automatically augmented as the probability of unmet demand
increases, increasingly reflecting the VOLL. This means that prices are not solely
determined by the bids of generators when scarcity is anticipated
57
, but include an
administrative component. As the loss of load probability increases, for example as
the system operator deploys available reserve capacity to meet demand, a price adder
is applied automatically to the market price.
(102) The best known example of this approach is probably ERCOT in Texas, but the
approach is also used or envisaged in some European markets. In May 2014 the
British regulator concluded its review of imbalance settlement arrangements in the GB
market and alongside other reforms designed to make imbalance prices more
reflective of supply and demand introduced a 'reserve scarcity pricing function' that
functions in a similar way to the Texan arrangements but in the balancing timeframe
58
.
Ireland is planning a similar change to its market design, where the balancing market
will include an 'administrative scarcity price'
59
, the Belgian regulator has been
exploring the possibility of taking a similar approach in Belgium
60
, and the approach
was recommended by the International Energy Agency in its 2016 'Repowering
Markets' report
61
.
(103) Administrative scarcity pricing moves away from a pure market approach to
electricity price formation. Like in a capacity mechanism, it is a regulatory
intervention designed to increase security of supply and reward the reliability of
capacity and may involve State aid. The regulatory task of establishing an appropriate
demand curve for identifying scarcity prices according to different loss of load
probabilities is very similar to the process of setting the demand for capacity in a
volume-based capacity mechanism. However, administrative scarcity pricing does not
create a separate revenue stream and price for capacity separate to the electricity price,
and avoids the complications this causes for cross border electricity trading.
Hedging price risks
(104) Measures designed to allow price spikes to occur, while managing any perceived risk
associated with potentially very high prices, have been proposed and may be brought
57
58
59
60
61
This may reduce risks of market power abuse, but under administrative scarcity pricing the possibility of strategic
capacity withholding remains for portfolio generators.
Ofgem, 2014:
https://www.ofgem.gov.uk/publications-and-updates/electricity-balancing-significant-code-review-final-
policy-decision.
I-SEM Committee, 2015:
https://www.semcommittee.com/sites/semcommittee.com/files/media-files/SEM-15-
103%20CRM%20Decision%201_0.pdf.
CREG, 2016:
http://www.creg.info/pdf/Divers/Z1532FR.pdf.
IEA, 2016:
http://www.iea.org/publications/freepublications/publication/REPOWERINGMARKETS.pdf.
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forward by market participants without the need for additional intervention by
national authorities. For instance, the introduction of hedging products which
suppliers can buy to protect themselves against peaks. Options are widely traded in
Australia – where price spikes are allowed – and are being introduced in Germany by
EEX.
62
Increasing confidence in market outcomes
(105) Competition rules to prevent the abuse of market power are not intended to prohibit
high electricity prices resulting from the competitive interaction of supply and demand
when electricity is scarce. Effective data availability and market monitoring will
increasingly be required to ensure confidence in market outcomes and the reliability of
high prices as a signal of market fundamentals. This will increase the confidence of
market participants, regulators and governments and help ensure markets are left to
function without unnecessary intervention, The continued development of demand
response and the opening up of markets across borders are also essential contributors,
since they make the abuse of market power less likely and help ensure market prices
genuinely reflect the competitive equilibrium of supply and demand, and eventually
scarcity.
2.3.1.2 More efficient, market-based balancing and ancillary services
(106) The increase of intermittent renewables has created more uncertainty in forward and
day-ahead trading and more volume volatility during the day, with system frequency
risking falling and rising more quickly and drastically following a system disturbance.
It has therefore become more important to improve short-term markets to enable
balance-responsible parties to balance their portfolios on the shorter term intraday and
balancing markets, but also foster the development of ancillary services that can
respond in ever shorter timeframes to system disturbances.
(107) To support Member States in their effort to improve their balancing and ancillary
services, the Commission is preparing legislation to this end, in particular with a view
to fostering effective competition, non-discrimination, transparency and efficiency in
balancing markets. The proposal will include no-regret measures such as moving gate
closure time
63
closer to real time (the closer to real time, the more accurate the
forecasts of potential generators are on what they will be able to generate and the
forecasts of demand response operators on when they will be able to switch-off),
62
63
'An electricity market for Germany’s energy transition', White Paper by the Federal Ministry for Economic Affairs and
Energy, July 2015. Available at:
http://www.bmwi.de/English/Redaktion/Pdf/weissbuch-
englisch,property=pdf,bereich=bmwi2012,sprache=en,rwb=true.pdf
See also:
https://www.eex.com/en/about/newsroom/news-detail/eex--successful-start-of-trading-in-cap-futures/21902
The Gate Closure Time is the time at which a market closes and trading is no longer allowed.
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standardising and limiting the products to be traded (e.g. in terms of preparation
period, ramp-up time, full activation time, minimum quantities, deactivation time
etc.), reviewing the products to ensure they are suitable both for generators and
demand response operators, and opening up national balancing markets to cross-
border capacities.
(108) The Commission moreover emphasises the importance of the correct remuneration of
ancillary services, as already explained in section 2.3.1.1 concerning balancing
markets. The Commission’s legislative proposal will therefore also define minimum
rules for the procurement of balancing services. As a first step towards more
generalised market-based procurement of all ancillary services, the proposal will
prescribe such competitive procurement of certain frequency ancillary services.
2.3.1.3 More efficient bidding zones reflecting transmission constraints
(109) Another element of market design that is crucial for ensuring efficient locational
signals for investment in generation and transmission, and the location of demand, is a
more efficient definition of bidding zones. The European market is divided into
bidding zones within which market participants can trade electricity without having to
acquire the rights to use transmission capacity. As such, the price formed in each zone
reflects the overall demand/supply balance in the zone.
(110) Ideally, for electricity prices to appropriately signal local scarcity the market area or
bidding zone needs to reflect the technical limits of the transmission system. The price
in a very large zone may not indicate with sufficient precision where additional
generation capacity is most needed and transmission constraints may cause inefficient
plants to run instead of more efficient ones. As described in Section 2.2.2.1, this can
cause significant distortions to competition and trade. In such situations, TSOs are
forced to revert to congestion management, often in the form of re-dispatching
measures
64
, in order to ensure system balance and minimize loop flows, leading to
significant costs for consumers and further market distortions.
(111) Zones defined based on transmission constraints can allow zonal electricity prices to
provide more accurate signals for the efficient location of generation capacity and
electricity demand, and the market-based scheduling of generation (i.e. avoiding the
need for re-dispatching). Of the Member States assessed in the context of the sector
inquiry, Denmark, Italy and Sweden have divided their electricity market in two or
more bidding zones.
64
A TSO that applies re-dispatching requests or instructs a power plant to adjust their power generation in order to
address congestions and maintain system balance.
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(112) A document published by ACER in 2014
65
as a result of a joint initiative between
ACER and ENTSO-E provides a comprehensive and balanced view of the impact of
the current bidding zone configuration on the electricity markets. In particular, it looks
at the following factors: the efficient use of infrastructure, liquidity, hedging, market
power and investment incentives.
(113) The ACER report identifies clear positive effects on effective competition and
efficient price formation of a bidding zone delineation that reflects transmission
constraints, but also points that these benefits are currently not reaped due to the
challenges of identifying clearly constrained lines to define bidding zone borders and
also to the potential costs of network development. This difficulty is reflected by the
limited progress that is being made in the ongoing process for the review of the
current bidding zone configuration in Europe, as prescribed in the CACM Network
Code. The Market Design Initiative includes measures to improve the delineation of
bidding zones.
(114) Replies to the sector inquiry provided mixed views on the current ability of the
electricity markets to generate the right locational signals for investment in generation
capacity in the national territories covered by the present sector inquiry. Member
States that are already split in different bidding zones are generally more positive
about the benefits of smaller bidding zones, though some of the respondents from
these countries still felt there was room for improvement as even where there are
multiple bidding zones, these too often reflect national borders rather than
transmission limits.
2.3.1.4 Further integration of demand response in the electricity market
(115) On the demand side, increased demand responsiveness can have important impacts for
generation adequacy because it has the potential to flatten demand peaks and thus
reduce the need for additional generation capacity to ensure adequacy. Its role will
further increase with the shift towards generation from variable renewables, as coping
with shorter time generation peaks and gaps will be more in the focus of the balancing
concerns in many Member States. Demand response can be realised both for
household and small industrial/commercial consumers – where smart meters are
progressively being deployed
66
and aggregators
67
are facilitating participation in
electricity markets – and for larger industrial consumers.
65
66
Report on the influence of existing bidding zones on electricity markets (2014).
For instance, in 17 Member States the wide-scale deployment of smart metering devices is underway or planned and
data from Member States show that 72% of European consumers are expected to have a smart electricity meter by
2020. Moreover, retail consumers can increasingly choose more flexible tariffs based on real-time prices. For instance,
in Finland and Sweden retail consumers increasingly opt for dynamically priced electricity contracts saving 15% to
44
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(116) Experience has shown that the potential to integrate significant volumes of demand
response on short notice is highest for industrial customers. Industrial consumers are
being increasingly incentivized to reduce load in times of scarcity by making them
sensitive to wholesale prices, either directly responding to the real-time market signals
or through commercial offerings from their suppliers. Smart grids and meters help
mitigating the problems related to the public good character of reliability as they allow
individual consumers to manage their consumption on the basis of price signals.
Moreover, a manageable demand side provides an additional tool to TSOs in
balancing the system, by providing balancing or ancillary services to the TSO or by
participating in a targeted scheme for interruptible loads.
(117) However, at present serious regulatory obstacles persist in a great majority of Member
States, ranging from explicit prohibitions on becoming active on the wholesale market
to the continuation of disincentivising grid tariff structures.
68
Moreover, national legal
frameworks differ considerably across the EU, for instance on aggregation or the
determination of baseline capacities. For these reasons, the Commission is proposing
to harmonise some basic elements related to the treatment of the participation of
demand response in the various time frames.
2.3.1.5 Further integration of renewable generation in the electricity market
(118) On the supply side, participation can be broadened to ensure that all potential
contributors are able to deliver what they physically can to meet peak demand.
Renewables for example have historically been shielded from price fluctuations in the
market to help support the development of nascent technologies. However, now that
RES generation is maturing and comprises a significant proportion of overall installed
capacity, there is an increasing opportunity for a more active participation in the
market. There is still a substantial number of Member States in which RES producers
are either not able or have no incentive to participate in the wholesale market and
react to price signals, for instance because they bear no responsibility to ensure that
their actual generation output meets projections.
(119) The contribution of wind and solar will increase as necessary grid reinforcements are
implemented and the right incentives are put on renewables operators through their
67
68
30% on their electricity bills. Source: Communication from the Commission, 'Delivering a New Deal for Energy
Consumers' of 15 July 2015, COM(2015)339 final, page 3 – 5.
Demand response aggregators typically enter into contracts with small consumers and sell the combined load reduction
that these consumers can achieve together to the system operators, sharing the revenues with the participants.
European Commission, JRC 'Demand Response status in EU Member States 2016',
http://publications.jrc.ec.europa.eu/repository/bitstream/JRC101191/ldna27998enn.pdf.
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inclusion in balancing markets. Wind capacity is increasingly able to offer ancillary
services and to adjust its output in the balancing timeframe
69.
Table 2: Balancing Responsibility for RES in the eleven Member States
Balancing Responsibility for RES
Country
Balancing responsibility
Yes
Belgium
Yes
Denmark
No
Croatia
No
France
FIP Only
70
Germany
Partly
Ireland
Partly
Italy
Yes
Poland
Yes
Portugal
Yes
Spain
Yes
Sweden
Source: European Commission, adapted from Commission Communication 'Delivering the internal
electricity market and making the most of public intervention', 5 November 2013, C(2013)7243
2.3.1.6 Further cross-border integration of the electricity market
(120) Another example is foreign capacity. The participation of foreign capacity is
optimized in the day-ahead market where market coupling has been implemented, but
regulatory arrangements typically do not allow the use of interconnection closer to
real time when scarcity would be expected to emerge.
71
The use of cross border
resources in the intraday and balancing will help to ensure competition in all market
timeframes, and Member States and TSOs should ensure that investments are made to
relieve transmission constraints between bidding zones and enable the full benefits of
the Single Market to be realised.
(121) Under market coupling rules, the only signal that is taken into account for determining
cross border electricity flows is the electricity price, so it is important to ensure that
electricity prices can rise to reflect consumers' willingness to pay. It is also critical that
market coupling systems ensure that different price caps can be set in different
69
70
71
See for example Fraunhofer IWES, DTU Wind Energy, EWEA, April 2013,
Capabilities and costs for ancillary
services provision by wind power plants.
Available at:
http://www.reservices-project.eu/wp-content/uploads/D3-
RESERVICESAncillaryServicesfromWind_v1.3_final.pdf
Balancing responsibility is only applied to those renewable generators that receive a feed-in premium and thus
participate in the market (currently some 80% of RES).
However, power exchanges have initiated pilot projects aimed at the development of cross-border intraday trading
based on implicit continuous trading, in accordance with the Commission's Target Model for Intraday and Commission
Regulation (EU) 2015/1222 of 24 July 2015 establishing a Guideline on Capacity Allocation and Congestion
Management.
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bidding zones if appropriate to reflect the different willingness to pay of consumers in
different zones.
2.3.1.7 More stable, harmonised regulatory environment
(122) Finally, though reforms are necessary to improve market functioning, the extent to
which an electricity market delivers signals for sufficient investment depends on
investors' view of long term regulatory stability. Regulatory stability helps create an
environment in which longer term and forward trading can happen within the market,
which can provide an important basis for supporting new projects. Alongside a stable
regulatory framework for electricity prices, the longer term impact of carbon prices is
an important consideration for investors, and a reformed European carbon market with
a functioning Market Stability Reserve that addresses the surplus of emission
allowances on the market will help to deliver this.
2.3.2
Addressing residual market failures with a capacity mechanism
(123) The reforms mentioned in the previous section could significantly improve the
efficiency of electricity markets. Some analysts indicate that there is practical
evidence that an energy only market design can realise sufficient investment without
the need for mechanisms that make separate capacity revenues available to generators
and/or demand response.
72
However, other authors stress that such reforms alone may
not completely solve the missing-money problem.
73
Either because market reforms
may take time to be fully implemented or because they may be insufficient to fully
address the generation adequacy problem generated by the lack of optimal incentives
to invest in generation capacity, Member States may want to establish additional
72
73
The electricity markets of Australia and Texas are often referred to as examples of functioning energy-only markets. In
Australia, the price cap is set at VOLL, but market participants have ensured themselves against peaks by developing
hedging products which in turn allow operators of peak generation units to earn a stable income in the energy-only
market. In Texas, the electricity price is amplified by adding a pre-defined amount of money per MWh to the electricity
price depending on the stress of the system. The lower the remaining reserves, the higher the sum that is disbursed to
the contributing generators. According to the respective regulatory authorities, both of these markets appear to have
delivered sufficient investment to meet centrally determined reliability standards over many years. See for Australia:
https://www.aer.gov.au/system/files/State%20of%20the%20energy%20market%202014%20-%20Chapter%201%20-
%20National%20electricity%20market%20A4_0.pdf
and for Texas: Brattle Group’s 1 June 2012 report to the Public
Utility Commission of Texas, “ERCOT Investment Incentives and Resource Adequacy”
http://www.ercot.com/content/news/presentations/2013/Brattle%20ERCOT%20Resource%20Adequacy%20Review%2
0-%202012-06-01.pdf.
See Joskow P. L. (2008): "The reforms to wholesale energy markets discussed above should help to reduce the missing
money problem associated with the operation of many 'energy only' wholesale markets today. However it is not at all
obvious that the missing money problem will be completely solved with these reforms or that they can be implemented
overnight. These reforms may also increase market power problems and further increase price volatility."
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measures to address a residual missing money problem and ensure generation
adequacy.
74
(124) While it is possible that such a residual missing money problem subsists even after
market reforms, the Commission does not conclude here that there is a need for
further intervention through capacity mechanisms in every Member State. The need
for a capacity mechanism depends on the objective circumstances in each market,
which will need to be thoroughly assessed by the competent authorities in each
Member State, taking into account the participation in an increasingly integrated
electricity system at European level.
(125) While capacity mechanisms can be justified when a residual missing money problem
is identified, capacity mechanisms cannot replace the reforms pending to make
electricity markets more efficient. Each of the opportunities for reform identified in
the previous section are at the very heart of the effort, both at national and European
levels, to bring about more efficient markets that provide reliable electricity to
consumers at the least possible cost. These reforms will allow exploiting as much as
possible the potential of competitive markets to efficiently deliver reliable electricity
to the benefit of final consumers. These reforms can therefore be neither neglected nor
delayed.
(126) Correcting the market and regulatory failures that, to a large extent, contribute to
erode incentives to invest in generation capacity will reduce the concerns about the
reliability of European electricity systems. It will also reduce the need for additional
interventions like capacity mechanisms, minimising potential market distortions and
saving public resources. Therefore, advancing in the market reforms discussed above
is warranted irrespective of whether the implementation of any capacity mechanism is
planned, and irrespective of the type of capacity mechanism envisaged.
(127) The eleven Member States under assessment in this inquiry have opted for the
introduction of one or more capacity mechanisms to address perceived residual market
failures. The designs of the mechanisms vary widely, but all have in common the
underlying principle of enabling revenues for capacity providers and thus they may
fall within the category of state aid measures. They can therefore be subject to the
Union's rules on state aid and their compatibility with these rules may have to be
assessed by the Commission.
74
See Joskow P. L. (2008): 'Lessons learned from Electricity Market Liberalization': "A number of countries are
considering imposing resource adequacy, forward contracting obligations, or providing capacity payments to generators
to overcome imperfections in wholesale and retail markets in order to restore incentives for investments in generating
capacity and demand response capabilities consistent with traditional reliability levels."
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(128) The following chapters describe and assess the capacity mechanisms applied or
planned in the eleven Member States.
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3.
M
EMBER
S
TATE INTERVENTIONS
:
OVERVIEW AND CLASSIFICATION
(129) There are various types of capacity mechanisms. They can be categorised to some
extent based on their basic characteristics, and within each category further parameters
can be set that determine the precise design.
75
This chapter describes the six basic
types of capacity mechanism previously identified by the Commission, and identifies
where the capacity mechanisms identified in the sector inquiry fit into this framework.
(130) The chapter briefly describes the main features of the different types of capacity
mechanisms identified in the sector inquiry. More detail on specific design elements is
provided in Chapter 5.
3.1
Types of capacity mechanisms
(131) The various types of capacity mechanisms can be grouped into two broad categories:
targeted mechanisms and market-wide mechanisms. Within these two categories, it is
also possible to distinguish volume-based mechanisms and price-based mechanisms.
Figure 22: Taxonomy of capacity mechanism models
Source: European Commission
3.1.1
Targeted mechanisms
(132) Targeted mechanisms are those where the amount of capacity required and the amount
expected to be brought forward by the market are identified centrally. The capacity
mechanism then provides support only to the additional capacity (or 'top up') expected
to be needed beyond what would anyway be brought forward by the market.
75
The Commission developed this categorisation in a Non Paper, which was discussed with Member States in a working
group that took place on 30 June 2105. It is available here:
http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_working_group_10_en.pdf.
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(133) For the purposes of the sector inquiry, we have identified three basic types of targeted
mechanism.
76
Tender for new capacity – typically, the beneficiary of such a tender receives
financing for the construction of a power plant that would bring forward the identified
top up capacity. Once the plant is operational, in some models the top up capacity runs
in the market as normal (without a guarantee that the electricity will be sold). It would
also be possible for the plant to be supported through a power purchase agreement.
Strategic reserve – in a strategic reserve mechanism, the top up capacity is contracted
and then held in reserve outside the market. It is only run when specific conditions are
met (for instance, when there is no more capacity available or electricity prices reach a
certain level). Typically strategic reserves aim to keep existing capacity available to
the system.
Targeted capacity payment – in this model, a central body sets the price of capacity.
This price is then paid to a subset of capacity operating in the market, for example
only to a particular technology, or only to capacity providers that meet specific
criteria.
(134) Both the strategic reserve and the tender models are 'volume-based' mechanisms
because the volume of capacity that receives support is determined at the outset. They
differ from the 'price based' targeted payment model where there is no restriction on
the amount of capacity that receives the payment, but rather a restriction on the type/s
of capacity eligible.
3.1.2
Market-wide mechanisms
(135) In a market-wide mechanism, all capacity required to ensure security of supply
receives payment, including both existing and new providers of capacity. This
essentially establishes 'capacity' as a product separate from 'electricity'.
(136) There are three basic types:
Central buyer – where the total amount of required capacity is set centrally, and
then procured through a central bidding process in which potential capacity
providers compete so that the market determines the price.
De-central obligation – where an obligation is placed on electricity suppliers /
retailers to contract with capacity providers to secure the total capacity they need
to meet their consumers' demand. The difference compared to the central buyer
model is that there is no central bidding process, but market forces should still
establish the price for the required capacity volume.
76
http://europa.eu/rapid/press-release_MEMO-15-4892_en.htm.
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Market-wide capacity payment – where the price of capacity is set centrally, based
on central estimates of the level of capacity payment needed to bring forward
sufficient total capacity and then paid to all capacity providers in the market.
(137) These mechanisms provide support to all (or at least the majority of capacity providers
in the market – there may still be some restrictions on eligibility).
(138) The central buyer and de-central obligation models are volume-based: in these models
the volume of capacity required is set at the outset, while the price is determined by
the market. The market-wide capacity payment is price-based since the price for
capacity expected to achieve sufficient investment is fixed at the outset, while the
volume may vary depending on how the market reacts to that price.
77
(139) Further variations are possible within the different models depending on the detailed
design.
3.2
Capacity mechanisms in place in the 11 Member States
(140) The Member States assessed in the sector inquiry have been selected because they
have either introduced or are considering introducing one or more capacity
mechanisms. The combination of Member States was also chosen to constitute a
representative sample of the different capacity mechanism types being developed in
Europe.
(141) The mechanisms brought to the attention of the Commission by respondents to the
sector inquiry vary widely and categorising them according to the taxonomy provided
in Figure 22 is not always straightforward.
(142) To help determine whether a measure or practice in a Member State qualifies as a
capacity mechanism within the scope of this inquiry, the Commission has identified
the following indicators. Capacity mechanisms:
are generally initiated by or with the involvement of governments;
have the primary objective of contributing to security of supply; and
provide remuneration to capacity providers in addition to revenues they receive in the
electricity market, or instead of revenues they could otherwise have received in the
electricity market.
(143) A particular area in which there may be debate about what constitutes a capacity
mechanism and what requires State aid approval is in the specification and
77
Note even volume based mechanisms may be designed to enable some flexibility on the volume procured in reaction to
prices of capacity (sloping demand curve), which is not known definitively until the allocation process takes place. This
is for example the case in the planned Italian central buyer mechanism and in the GB capacity auction.
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procurement of ancillary services. TSOs typically procure frequency (balancing of the
system) and non-frequency (voltage control and black-start) ancillary services to
ensure the management of the system. In most cases, they are mandated to do so by a
general public service obligation to maintain system stability and security. Where such
ancillary services are procured independently by TSOs, and where in particular the
determination of the precise volumes and types of services to be procured is left to the
TSOs without Government involvement, there will be a strong indication that the
purchase of such services does not involve State aid and that those services are
therefore not covered by this inquiry. Such indication will be strengthened when
procurement of such services is performed in a transparent, competitive and non-
discriminatory way, thereby excluding undue advantages. Another element to
distinguish ancillary services from capacity mechanisms is the use and purpose of the
services: when they are used in small volumes relative to the overall level of capacity
in the market and only to provide short term corrections to enable system security,
they will more likely be considered ancillary services.
(144) However, where ancillary services appear to be contracted at the request of
governments and/or are used to ensure capacity is available to balance the system over
longer periods, they can have the same effect as capacity mechanisms. Such measures
may merit attention from the Commission and require State aid approval.
(145) In some cases capacity mechanisms do not cover the whole territory of a Member
State. In particular islands may be excluded from a capacity mechanism (as is the case
in one Portuguese scheme) or may benefit from specific support measures (for
example, Italy has implemented separate interruptibility schemes, one for the
mainland and one for Sardinia and Sicily).
(146) Some mechanisms are hybrid forms of two types identified in the taxonomy: for
example a Portuguese scheme which makes administratively determined payments to
demand response beneficiaries, in return for their being available – effectively in
reserve – until the TSO asks them to reduce demand. This has elements of the targeted
capacity payment model (administratively determined payments to a subset of
capacity providers) and of the strategic reserve model (beneficiaries are held in
reserve and instructed to run by the TSO).
(147) The sector inquiry identified seven countries that operate specific schemes for demand
response (usually large industrial users) that at first sight match the indicators for
identifying a capacity mechanism: France, Germany, Ireland, Italy Poland, Portugal
and Spain. Beneficiaries of such 'interruptibility schemes' are then held in reserve until
required by the TSO. For this reason, these schemes can be regarded as a form of
strategic reserve.
(148) Other measures identified by respondents have some features of a capacity
mechanism, but are not designed primarily to ensure security of supply and instead
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address other objectives, for example the existing Danish schemes for combined heat-
power (CHP) generation which make payments for availability but were designed
primarily to bring forward investment in CHP capacity and reduce emissions.
78
(149) Although not a definitive view of the number of capacity mechanisms in the countries
covered by the sector inquiry, Table 3 below was compiled on the basis of responses
to the sector inquiry and the above indicators and considerations, and gives an
impression of the number and type of the capacity mechanisms in place or considered
in the countries.
Table 3: Capacity mechanisms in the sector inquiry
Source: European Commission based on replies to sector inquiry
78
Denmark's support to CHP capacity has been the subject of previous State aid decisions – see SA.30382, SA.35486,
and SA.42519.
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Figure 23: Capacity mechanisms (existing, planned and on hold) in the 11 Member
States – excluding interruptibility schemes
Source: European Commission based on replies to sector inquiry
(150) The following sections in this chapter describe the features of each type of capacity
mechanism with reference to the examples found in the inquiry. The different schemes
are described in terms of three general design elements:
the eligibility rules, which determine any restrictions or requirements relating to the
type, size and location of potential beneficiaries;
the allocation process, which determines the way in which eligible beneficiaries are
selected, and the way in which the capacity remuneration they will receive is
determined; and
the capacity product, which determines what the beneficiaries must do in return for
their capacity remuneration, and what the sanctions are if they do not do this.
(151) A more detailed analysis of these design elements is given in Chapter 5.
3.2.1
Tender for new capacity
(152) Examples of tenders for new capacity were found in four of the Member States
included in the sector inquiry: Belgium, France, and Ireland.
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Belgium in 2014 launched a tender to attract investment in 700-900 MW of OCGT
(open-cycle gas turbine) or CCGT (combined-cycle gas turbine) capacity. The tender
was however abandoned in early 2015.
In Croatia, the State owned energy company Hrvatska elektroprivreda (HEP) launched
a tender in 2012 for investment in a new 515 MW coal-fired power station at Plomin
on the Adriatic coast.
France launched a tender for the construction of a 450 MW combined cycle gas-fired
power station in 2011 to deal with regional security of supply concerns in Brittany.
79
In 2003, Ireland developed a tender mechanism in view of an expected shortfall in
capacity from 2005 onwards. The process resulted in the construction, in 2005 and
2006 respectively, of a new CHP facility and a new CCGT with a combined installed
capacity of over 500 MW.
80
3.2.1.1 Eligibility
(153) All four tenders for new capacity specified many characteristics of the chosen capacity
product in advance, including for example the size, technology type and location. The
tenders in France and Belgium were limited to gas-fired plants only (with the tender in
France limited only to CCGT capacity). The tender in Ireland was open to bids from
any new centrally dispatchable thermal plants
81
. The tender in Croatia was limited to
coal capacity at a specific coastal site with existing coal infrastructure and where coal
can be imported. None of the four tenders were open to demand response.
(154) All tenders were limited to new projects, although the Belgian tender was eventually
opened to existing foreign capacity with the potential to be incorporated into the
Belgian bidding zone. In all examples long contracts were available (ten years in
Ireland, twenty years in Croatia and France and up to seven years in Belgium).
(155) In Croatia and France, the proposed tender required a single bidder to fulfil the
identified capacity requirement. In Ireland, the 2003 tender was open to multiple
projects (of minimum 50 MW each) and in fact there were 2 successful beneficiaries
that, taken together, were able to fulfil the identified requirement.
(156) The French tender for new capacity was limited to capacity physically located in a
specific area within Brittany. This locational requirement was justified by the need to
ensure voltage control. The Belgian and Irish tenders were open to projects located
79
80
81
The Commission opened a formal investigation into the measure on 13 November 2015. See:
http://europa.eu/rapid/press-release_IP-15-6077_en.htm
The mechanism received state aid clearance from the Commission in 2003.
http://ec.europa.eu/competition/state_aid/cases/137628/137628_485545_28_2.pdf
Centrally dispatchable plants are those that can be dispatched at the request of power grid operators (ie. they can
reliably begin generating on request).
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outside of the Member States' national territory, but only on the condition that they
had dedicated transmission connections to the Belgian or Irish grid.
3.2.1.2 Allocation process
(157) In all of the tenders the price, but also the speed of development of potential projects
were considered. In Ireland, bid prices were adjusted to account for the projects'
locations and development dates; eventually the cheapest bundle of bids that met the
requirement was selected. In the French and Belgian tender price was not the only
award criterion; for instance, in both procedures the construction time was also taken
into account. The French authorities also considered the proposed site of the
installation and its impact on the environment, while in the Belgian tender procedure
the "contribution to market functioning" (i.e. the contribution to a competition in the
market, with a bias in favour of new entry) were also considered.
3.2.1.3 Capacity product
(158) In Belgium and France, the successful beneficiary would receive capacity payments in
return for making capacity available, and could participate in the electricity market
and earn separate revenue from the sale of electricity. In France, these payments can
be reduced both in case of non-availability and in case of a delay in the construction of
the installation. In Belgium the selected power plant(s) would have needed to be
available during winter for a predetermined amount of time, while in Brittany the
availability obligations apply throughout the year.
(159) In Croatia, the successful beneficiary would receive availability payments per MW of
capacity made available to HEP, and energy payments for the costs of each MWh of
energy generated by the plant.
(160) In Ireland, the successful generators received 'capacity and differences agreements'.
They received capacity payments for their availability, and were free to run in the
market and earn separate electricity revenues. However, the agreements included a
claw-back mechanism since the generators had to repay the difference if market prices
went above a pre-defined strike price.
3.2.2
Strategic reserve
(161) Examples of strategic reserves (excluding interruptibility schemes) were found in five
of the Member States included in the sector inquiry: Belgium, Denmark, Germany,
Poland, and Sweden. Germany plans to operate more than one strategic reserve.
In Belgium a strategic reserve was introduced in 2014 as a back-up for peaks in
demand during the winter period. 800 MW capacity was sought in the first year,
3,500 MW in the second year, and 750 MW for the winter 2016-2017.
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Denmark proposed to create a new 200 MW strategic reserve in its Eastern DK2
bidding zone in 2016. The reserve was intended to be transitional until interconnection
capacity is increased. However, the measure has not been implemented.
Germany has a 'network reserve' in place to address grid bottlenecks between
generation in the north of the country and demand in the south. The reserve consists
primarily of power plants that have signalled their intention to close down but have
been prohibited from doing so because they are deemed of importance for maintaining
system stability ('system relevance'). These plants are moved into the network reserve,
activated when there is insufficient network capacity to send power from north to
south ('mandatory part') and reimbursed for the costs that result from the statutory
interference with the rights of the plant operator. In case the combined capacity of the
power plants that have been prohibited from closing is insufficient to satisfy the
identified need for the network reserve, then a tender is organised to attract additional
reserve capacity (the 'voluntary part'). In practice, this additional need is satisfied by
power plants located in Austria and Italy. The network reserve differs from other
strategic reserves not only because of its regional nature, but also because its
activation is not triggered by a non-clearing market, but rather as an instrument for the
TSOs in Southern Germany that allows them to maintain grid stability when there is
insufficient transmission capacity to flow power to the south of the country ('re-
dispatch'). A review of the network reserve is currently ongoing.
Germany is also considering introducing a country-wide strategic reserve of 2 GW
('capacity reserve') as of 2018, to be held outside the market. The deployment of the
capacity reserve is triggered when the day-ahead or intraday market does not clear and
if no other measures are available to the TSO, so as to minimise market distortions.
Poland has created a strategic reserve comprising 830 MW of generation capacity
('cold contingency reserve'). The cold contingency reserve is intended to be
transitional for two years starting in 2016, with the possibility to extend for a further
two years beyond this.
Sweden has operated a strategic reserve of up to 2 GW since 2003, designed to ensure
sufficient capacity is available in the winter to cover peak load. The reserve currently
comprises 1 GW capacity. The reserve was due to be removed after winter 2019/20
but it will be extended for a further five years until 2025. 750 MW will be contracted
for the period 2017-2025.
3.2.2.1 Eligibility
(162) The technological eligibility rules for strategic reserves are varied, with the reserves in
Belgium, Denmark and Sweden open to demand response as well as generation, while
the German network reserve and the Polish reserve are only open to generation
capacity. Reserves are typically not designed to attract new generation capacity.
(163) Some reserves are location-specific, meaning they aim to address grid congestion or
capacity shortage only in certain parts of a Member State. None of the strategic
reserves are open to generators located outside of the Member State operating the
reserve, except for the German network reserve.
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3.2.2.2 Allocation process
(164) In general, the strategic reserves include a competitive process for identifying the
capacity providers that will provide reserve services and in all examples with
competitive processes beneficiaries are paid the price they bid for the services they
provide (which usually includes a payment for being available and a separate
activation payment). In practice, however, there is not always enough existing
capacity on offer to allow for a competitive tender.
3.2.2.3 Capacity product
(165) In all examples of strategic reserves except for foreign plants participating in the
German network reserve, selected capacity providers are held in reserve outside of the
market. They can no longer earn revenues from the sale of electricity, and can only
run when instructed to do so by the TSO. In practice most reserves are used
infrequently
82,
but the existing reserves are usually dispatched when the day-ahead
electricity market does not clear.
(166) If the capacity providers are not able to make themselves available or fail to deliver
when tested or called by the TSO, then they generally face a risk of missing out on
future availability payments, or having to return already received availability
payments.
3.2.2.4 Dispatch rules and link with market pricing
(167) In Belgium and Sweden reserve capacity is dispatched if the day-ahead market fails to
clear and there would be involuntary unmet demand without the reserve capacity.
Reserve capacity can also be triggered intraday in Belgium if the TSO anticipates
scarcity that was not apparent at the day-ahead stage. And in Sweden, reserve
participants can also be dispatched by the TSO after gate closure in the regulating
power market if there are insufficient commercial bids to meet demand.
(168) Once reserve capacity is dispatched it can have a significant impact on electricity
market prices. In Sweden, in periods when the reserve is activated electricity prices
are set by the highest commercial bid in the electricity market. In the Belgian reserve
and the on hold Danish reserve, however, for periods when the reserve is dispatched
and its capacity is required to meet demand, electricity prices are set to a pre-
determined high level (4,500 EUR/MWh in Belgium, and 3,000 EUR/MWh in
Denmark).
82
For example, the Swedish strategic reserve has been activated eleven times between 2003 and 2015. In seven of the
twelve years of operation it was not activated at all. The Belgian reserve has not yet been activated.
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3.2.3
Interruptibility schemes
(169) A subcategory of strategic reserves, interruptibility schemes were found in seven of
the Member States included in the sector inquiry: France, Germany, Italy, Ireland,
Poland, Portugal, and Spain.
Since 2010, Italy also has operated two interruptibility schemes: one for the two main
islands (aiming to contract 500 MW in each of Sardinia and Sicily) and another for the
mainland contracting 3,300 MW. The scheme for the two islands was reformed in
2016, with the target volume being reduced to 400 MW in Sardinia and 200 MW in
Sicily.
Between 2013 and 2016 German TSOs have organised monthly tenders for 3,000 MW
of sheddable load provided by consumers larger than 50 MW. The scheme is presently
being revised, whereby it is the intention of the German legislator to widen eligibility
requirements by means of a lowering of the participation threshold (to 10 or 5 MW),
by shortening contract durations (from one month to one week) and by allowing for
the possibility of pooling or aggregation of loads. Also the total amount to be procured
would be reduced to 1,500 MW.
In September 2012, the Polish TSO launched a tender to attract demand response
services. The first tender failed to attract any bids but four subsequent tenders between
2013 and 2015 resulted in 200 MW demand response capacity being contracted.
Since 2011, Portugal has operated an interruptibility scheme. 1,410 MW of capacity
was contracted under the scheme in 2015.
Since 2007 Spain has operated an interruptibility scheme. 3 GW of capacity was
contracted in 2015.
In Ireland the Powersave scheme, operated by Eirgrid, is a voluntary scheme
encouraging large and medium sized customers to reduce their demand when total
system demand is close to available supply. With up to 50 MW of total demand
reduction potential it is considerably smaller than the other schemes.
In France, an interruptibility scheme is in place since 2014, to be used during
emergency situations only. Since late 2015, the law prescribes the exact amount to be
procured by the TSO: 1,600 MW divided between two product categories.
(170) In most schemes, beneficiaries are paid a fixed price for each MW of demand
response made available as well as a price for demand reductions actually made
(energy delivered). In Poland and Ireland beneficiaries are only paid for energy
delivered and receive no availability payment.
(171) There is a difference between schemes that have been established by the TSO to
provide it with a valuable tool for ensuring system stability and schemes that have
been introduced by the government to request a fixed amount of demand response to
be contracted. Also where the capacity is requested by the government it may have a
useful function, but the distinction is relevant from a state aid perspective. For
instance, the interruptible load scheme established by the German government may be
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used by the TSOs for re-dispatch purposes. By temporarily switching off loads in the
South, the need for north-south flows is alleviated.
3.2.3.1 Eligibility
(172) By definition the interruptibility schemes are limited to demand response capacity.
Some schemes have further restrictions on eligibility, such as minimum size
requirements.
(173) None of the interruptibility schemes are open to beneficiaries located in other Member
States.
3.2.3.2 Allocation
(174) Most schemes allocate contracts through a competitive process, Prices are
administratively set in Ireland, Italy (only islands scheme as of 2016), and Portugal. In
Germany, currently demand for the service generally outweighs supply so prices are
set administratively. Amendments to the scheme may address this issue by reducing
the total demand.
3.2.3.3 Capacity product
(175) In all schemes, large energy users must agree to be automatically disconnected when
needed by the TSO. There is generally no prior notice and disconnection is often
instant. Interruptions can last for up to several hours.
(176) There are schemes where the product specification allows the TSO to respond to
immediate balancing issues, such as frequency restoration, whereby it immediately
remotely disconnects contracted loads, such as the German and Italian schemes. There
are also schemes aimed at alleviating adequacy concerns of a longer term, such as the
Irish scheme in which consumers are obliged to reduce their loads themselves upon
notification by the TSO at least 30 minutes before the 'Powersave' event starts.
Beneficiaries in the Irish scheme do not have to reduce their consumption, but are
only rewarded if they do reduce their demand.
3.2.4
Targeted capacity payments
(177) Examples of targeted capacity payments were found in four of the Member States
included in the sector inquiry: Italy, Poland, Portugal, and Spain. Portugal operates
two of these mechanisms, and Spain has operated four of these mechanisms.
In 2003, Italy introduced targeted capacity payments for dispatchable generators. The
mechanism was conceived as a transitional measure and Italy is planning to replace it
with a central buyer mechanism.
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Poland has operated an operational capacity reserve since 1 January 2014. During
working days' peak hours (8-22h), all available centrally dispatchable capacity (so
excluding wind, CHP etc.) that has not secured power sales contracts or is not subject
to a forced dispatch by the TSO (Poland has a central dispatch model) automatically
constitutes the operational reserve. The operational reserve plants receive a level of
remuneration per MW that varies depending on the amount of capacity constituting
the operational reserve in a given hour but is in any case capped (in 2016, the hourly
cap equalled 41.2 PLN/MW ~ 9.5 EUR/MW).
Portugal operates four targeted capacity payments schemes:
o
an 'availability incentive' scheme that remunerates thermal plants for their
availability; and
o
an 'investment incentive' scheme which aims to incentivise investments in new
hydro generation and in the repowering of existing pump storage units through
a capacity payment
83
.
o
a power purchase agreement with a regulated company covering one coal and
one gas-fired power plant (1.8 GW in total). The contracts run until 2024;
o
the Contractual Equilibrium Insurance ('CMEC') whereby after 2004, power
stations bound by PPAs were allowed to replace them by a legal mechanism
that grants them difference between market prices and what they would have
received under the PPA; it covers 3.8 GW of capacity and is valid until 2027.
Spain operates three targeted capacity payments schemes:
o
an 'investment incentive' scheme since 2007 for new nuclear, gas, coal, hydro,
and oil plants;
o
an 'availability incentive' scheme since 2007 for new and existing gas, coal, oil
and hydro with storage; and
o
an 'environmental incentive' scheme since 2007 for coal plants that fitted
sulphur dioxide filters.
Between 1997 and 2007 Spain operated another capacity payment mechanism called
the 'power guarantee'. The mechanism was replaced by the currently operational
capacity payments schemes.
Between 2010 and 2014, Spain also operated a 'supply guarantee constraints
resolution' mechanism which supported domestic coal production by providing plants
burning domestic coal with priority dispatch
84
and regulated prices. Some market
participant respondents noted that Spain may develop a new support scheme for plants
burning domestic coal. However, Spain has explained that it has no plans to develop
any new capacity mechanism.
83
84
Pump storage units are hydropower facilities in which water can be raised by means of pumps and stored to be used for
the later generation of electricity.
Plants subject to priority dispatch will be selected to generate electricity ahead of plants with lower running costs that
would otherwise have been chosen to meet demand.
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3.2.4.1 Eligibility
(178) Most of the targeted capacity payments schemes are open to dispatchable generation
(coal, gas, hydro with storage, and sometimes oil). But there are many variations, for
example the hydro-specific investment incentive scheme in Portugal, the investment
incentive in Spain which is also open to nuclear, and the environmental incentive in
Spain which is only open to coal plants.
(179) Although they are all national schemes and therefore geographically restricted to the
territory of the Member State implementing them, most of the targeted capacity
payments are otherwise non location-specific.
(180) None of the targeted capacity payments schemes are open to demand response, nor are
they open to beneficiaries located outside of the Member States operating the
schemes.
(181) Most targeted capacity payments schemes are open to existing and new generators and
provide annual capacity payments with no longer term contracts.
3.2.4.2 Allocation process
(182) By definition, capacity payments mechanisms involve an administrative price-setting
and allocation process rather than a competitive price-setting process. The level of
remuneration is set centrally – e.g. in Italy by the regulator – and then paid to all
eligible capacity providers.
3.2.4.3 Capacity product
(183) In general, the beneficiaries of targeted capacity payments must make their capacity
available during peak demand periods, or face penalties requiring them to repay or
forego capacity remuneration. However, beneficiaries of the Spanish investment
incentive are simply obliged to build and operate an eligible power plant with no
additional performance requirements.
3.2.5
Central buyer
(184) Examples of central buyer schemes were found in three of the Member States
included in the sector inquiry: Ireland, Italy, and Poland. All three mechanisms are
still in development and are not yet operational. Examples of central buyer schemes
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are also found in the UK (British mechanism)
85
, and in the United States including in
the ISO New England and PJM systems on the East Coast.
86
Ireland intends to replace the existing market wide capacity payment mechanism in
2017 with a market-wide central buyer capacity mechanism based on reliability
options. Reliability options are a type of capacity product and are described in more
detail in Section 5.4.2.1.
Italy is planning to replace its existing targeted capacity mechanism with a central
buyer mechanism, where reliability options would be traded in auctions organised by
the TSO.
Poland is planning to make various reforms to its electricity market and also to
implement a central buyer mechanism, and aims to hold the first auction as early as
2017. The proposed design appears to be similar to the British mechanism.
3.2.5.1 Eligibility
(185) Although still in development, the Irish, Italian and Polish central buyer schemes are
both intended to be open to all potential capacity providers including both new and
existing resources, and demand response. Central buyer models allow different
contract durations, ranging from one to fifteen year contracts in the EU mechanisms
(incl. GB).
(186) In terms of geographic scope, the Irish mechanism is expected to operate across the
whole island of Ireland. The Italian mechanism, by contrast, is being designed as a
zonal system to match Italy's underlying electricity market which is divided into six
bidding zones. This means demand for capacity will be established for each of the six
zones, and a separate capacity price established in auctions for each zone depending
on the local balance of supply and demand. The British mechanism is open to the
participation of interconnectors, but not to foreign capacity. The Irish and Italian
schemes have not yet developed rules for foreign capacity participation but intend to
enable foreign participation. Poland's intentions for cross border participation are not
yet clear.
85
86
See Commission decision C (2014) 5083 final of 23.7.2014 in Case SA.35980 (2014/N-2) – United Kingdom -
Electricity market reform – Capacity market. The public version of the decision is available at:
http://ec.europa.eu/competition/state_aid/cases/253240/253240_1579271_165_2.pdf.
Although the sector inquiry has not gathered additional information on mechanisms in countries outside the 11 included
Member States, key points from the design and operation of these mechanisms still offer valuable insights for the
inquiry and are therefore occasionally mentioned in this report.
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3.2.5.2 Allocation process
(187) The central buyer mechanisms, by definition, involve a central process in which all
capacity providers offer their capacity and it is 'bought' by a single buyer on behalf of
electricity suppliers/consumers.
3.2.5.3 Capacity product
(188) In the Irish and Italian schemes, the capacity product is a 'reliability option' which will
oblige the capacity providers to pay the difference between a reference electricity
price and a strike price specified in the reliability option contract whenever the
reference price exceeds the strike price. In the British mechanism, providers must
have delivered their contracted capacity in any periods in which it was required, and if
they failed to deliver (or only partially delivered) after a four hour warning was given,
penalties will apply.
3.2.6
De-central obligation
(189) The only de-central obligation scheme subject to the inquiry is the one being
implemented in France. Due to the amendments that have been proposed to make it
comply with the State aid rules
87
, the mechanism has become more hybrid, since it
now also includes aspects typical of a central buyer mechanism.
3.2.6.1 Eligibility
(190) All potential capacity providers including demand response and both new and existing
projects can be granted capacity certificates in the French scheme.
(191) Foreign generation and demand response capacity can participate directly to the
French capacity mechanism, though to the extent that the neighbouring TSO enters
into a cooperation agreement with the French TSO relating for instance to the
certification and testing of foreign capacities. Absent such cooperation agreement, the
interconnectors with the respective neighbouring Member State can get certified and
sell their certificates in the French capacity market.
87
The Commission opened a formal investigation into the measure on 13 November 2015. See:
http://europa.eu/rapid/press-release_IP-15-6077_en.htm.
The Commission's decision is publicly available (in French)
at:
http://ec.europa.eu/competition/state_aid/cases/261326/261326_1711140_20_2.pdf. The French authorities have
subsequently amended the mechanism to comply with the requirements of the Energy and Environmental Aid
Guidelines. Even though some amendments still need to be implemented in law, the remainder of this Staff Working
Document will refer to the amended French capacity mechanism.
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3.2.6.2 Allocation Process
(192) The de-central obligation model is essentially based on a market for tradable capacity
certificates. Capacity operators, on the one hand, obtain guarantees/certificates to
attest of their capacities, while suppliers, on the other hand, have an obligation to
obtain capacity certificates in proportion to their customer portfolios' peak demand
(adjusted to take account of thermosensitivity). There is an obligation for the largest
capacity operators (> 3 GW) to offer specified volumes of certificates in different
public auctions preceding the delivery year, while other capacity providers are free
either to participate to those auctions or to trade their capacity certificates bilaterally
OTC.
88
3.2.6.3 Capacity product
(193) In the French scheme, capacity providers must make the capacity they have sold as
certificates available in peak demand hours identified in advance by the TSO. In such
hours, suppliers must either reduce their customers' demand or ensure that they have
sufficient certificates to cover the peak consumption of their consumers (adapted to
represent a cold winter). If suppliers hold insufficient certificates, or capacity
providers make insufficient capacity available, capacity imbalance penalties will
apply.
3.2.7
Market wide capacity payments
(194) Ireland introduced a market wide capacity payment mechanism in 2007 to provide
additional revenue to remunerate market participants for their fixed costs.
89
3.2.7.1 Eligibility
(195) The capacity payments are paid to all generators in the market, as well as to providers
of demand-response and storage that contribute to meeting demand.
(196) The Irish scheme also makes payments to foreign capacity providers – however, it
does this by providing a capacity payment on top of the Irish electricity price for
providers of imports to Ireland (and also deducts the capacity payment for exporters of
electricity from Ireland).
88
89
Note in central buyer schemes the secondary trading of capacity obligations / contracts may also be possible after the
initial allocation through the capacity auction/s.
Ireland's electricity market operates as a single market across the Republic of Ireland and Northern Ireland. Due to the
cross-jurisdictional market arrangements in the Irish electricity system, where the Commission refers to Ireland in this
report it is usually referring to the island of Ireland which comprises territory of the Republic of Ireland and the United
Kingdom. Although the Irish electricity market is currently being reformed, in the current design generators can only
bid their short run marginal costs in the energy market which means prevents peaking generators recovering their fixed
costs without additional remuneration.
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3.2.7.2 Allocation process
(197) As with the targeted capacity payment schemes, the Irish market's wide capacity
payment involves an administrative price-setting process where the value of capacity
payments is calculated by the Irish and Northern Irish regulators. Capacity providers
receive a capacity payment for every 'trading period' in which they were available.
3.2.7.3 Capacity product
(198) Capacity payments in the Irish market are highest at times of tighter capacity margins,
which incentivises generators to be available at these times. Moreover, the generators
have to declare themselves available to be called-upon by the TSO in real-time and
performance penalties apply if they do not comply with instructions from the TSO.
3.3
Conclusions
(199) 35 mechanisms have been identified in the eleven Member States under assessment –
including past, existing, abandoned and planned mechanisms. Three Member States
have used tenders for new capacity, and six examples of strategic reserves were found.
Four countries have used targeted capacity payment schemes, but the inquiry found
nine examples of this model because Spain and Portugal operate more than one
different scheme of the same type. Two Member States are developing central buyer
mechanisms similar to those already operating in the United States and UK. Only one
Member State is developing a de-central obligation mechanism, and there is only one
example of a market wide capacity payment mechanism.
(200) There seems to be a trend away from price-based towards volume-based schemes.
There is only one proposed capacity payment scheme; all schemes currently proposed
or in development are volume-based.
(201) The following Chapters will describe and assess specific features of the identified
schemes in more detail in order to learn lessons from the design and operation of the
various capacity mechanisms identified.
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4.
4.1
A
DEQUACY
A
SSESSMENTS AND
R
ELIABILITY
S
TANDARDS
Introduction
(203) A necessary starting point in the process of determining whether or not to implement a
capacity mechanism is to make an assessment of the generation adequacy
90
situation
and how it is expected to develop in the future. Based on the outcomes of such
adequacy assessment Member States can establish whether and how much
intervention is necessary, for instance by comparing the outcome of the adequacy
assessment to a pre-determined ‘reliability standard’ that sets a level of security of
supply that is deemed appropriate.
(204) In the context of the sector inquiry the Commission has asked public bodies and
market participants whether and how they have carried out adequacy assessments and
how the assessments relate to reliability standards – where these are in place – and
how they have influenced the choice and the design of the existing or future capacity
mechanisms. Respondents were also asked for information on past reliability
problems and their expectations for the future.
(205) As adequacy assessments and reliability standards are used to define the potential
generation adequacy problem, they are also a necessary basis for the analysis in the
subsequent chapters, namely, whether market or regulatory failures have been
correctly identified, whether alternative and/or complementary measures have been
considered and put in place, and whether the remedies that have been introduced have
been appropriate to address the identified problem.
4.2
4.2.1
Findings of the sector inquiry
Reliability incidents are rare
(206) The sector inquiry asked public bodies whether reliability issues had occurred in the
past in their Member State or are expected to occur in the future. The respondents
indicate that unmet demand due to generation inadequacy has been extremely rare in
the past five years.
(207) In nine out of ten Member States, no such problems have occurred at all. The only
exception was Poland, where a large amount of forced plant outages coincided with a
heat wave in August 2015.
91
These findings were confirmed by Member State
90
91
Throughout the Report the term ‘generation adequacy’ refers to the ability of the totality of generating units to meet the
demand at all times. It is distinct from the wider ‘system adequacy’ which relates to the ability of the entire system, i.e.
including notably the transmission and the distribution grid, to meet demand at all times.
In the interim report, the Commission had found that in Italy generation adequacy issues had arisen on the islands of
Sardinia and Sicily which are not well connected to the grid on the mainland. However, the Italian authorities have
made it clear that these issues are to be regarded as network related, rather than generation adequacy related.
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responses to targeted questions from the Commission. Of the Member States that
calculate a loss of load expectation – a group to which Poland and Italy do not belong
– none had experienced an actual generation induced loss of load event in the past five
years.
(208) This in turn confirms observations made in the Commission's 2014 Energy Prices and
Costs report which concluded that Europe outperforms all other regions in the world
when it comes to reliability of supplies.
92
It also confirms one of the conclusions in
Chapter 2 that the general increase in capacity and in particular in RES, has resulted in
a situation in which the difference between peak demand and supply has widened and
capacity margins – that is, the simple difference between installed capacity and peak
demand – have increased.
Table 4: The necessity of capacity mechanisms and actual reliability problems
Source: European Commission based on replies to sector inquiry
93 94
4.2.2
More adequacy problems are expected in the future
(209) Although most Member States do not experience reliability issues at present, Table 4
also demonstrates that a clear majority of public bodies indicate that they are of the
opinion that reliability problems are expected to arise in the coming five years. Only
in two out of ten Member States the expectation is that no reliability problems will
occur in the medium term, but these Member States expect their overcapacity to
reduce in the longer term even though they currently display a comfortable capacity
margin.
92
93
94
Commission Staff Working Document, SWD(2014)20 of 22 January 2014:
http://eur-lex.europa.eu/resource.html?uri=cellar:ba385885-8433-11e3-9b7d-
01aa75ed71a1.0001.01/DOC_3&format=PDF.
Croatia did not provide information on these questions.
Please note that compared to the Interim Report, two changes were made to this graph. i) the second column on Italy
has been updated to reflect the fact that the reliability problems on the islands Sardinia and Sicily were grid related
rather than generation adequacy related. ii) the second and third column on Poland: the second to 'Yes' because of the
reliability issues that occurred in summer 2015, and the third to 'Yes' in view of recent information provided by the
Polish Electricity Association. The Polish Electricity Association points out that both ENTSO-E and the Polish TSO do
expect Adequacy problems in Poland. The fact that Poland now envisages the introduction of a central buyer capacity
mechanism indeed suggests that adequacy concerns exist.
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(210) As discussed in Chapter 2, a number of market developments and failures have
contributed to the increased uncertainty about future generation adequacy. Public
bodies have expressed two key concerns. Firstly, the expected closure of existing
plants – mentioned by public bodies from Belgium, France, Poland and Spain – and,
secondly, the inability of the future generation mix to cover peak demand, as
underlined by public bodies from Belgium, France, Ireland, Italy, Poland, Portugal,
Spain and Sweden.
(211) In a majority of cases, these concerns originate from the 'missing money' problem
referred to in Chapter 2: particularly as the shares of intermittent renewables increase
and the profitability of conventional power plants declines the underlying question
arises whether sufficient flexible back-up capacity will be available when demand
peaks but renewables cannot produce.
(212) The underlying reasons stated by Member States for the occurrence of missing money
in their local markets appear to be different. In Germany for instance, the rapid
increase of renewables combined with the phasing out of nuclear power plants and
difficulties in expanding the grid have led to local adequacy issues, which may be
alleviated in the long run when additional transmission lines are built. As a result,
Germany has introduced a measure that prevents power plants in the South from
closing, the network reserve.
(213) In Poland, the concerns addressed by the Polish cold contingency reserve are not of a
locational, but rather of a temporal nature: increased emission standards will force a
number of old and polluting coal power plants out of the market, but already
committed, new generation units may not be operational before the old ones will have
closed. Poland therefore anticipates its contingency reserve to be transitory. However,
the fact that Poland now envisages the introduction of a central buyer capacity
mechanism, may suggest that it now has longer term adequacy concerns.
(214) Ireland and Italy set-up their tender and capacity payment mechanisms respectively in
direct response to acute adequacy concerns that occurred in 2003. Similarly, in
Belgium the lower profitability of (ageing) thermal plants was expected to lead to the
closure of power plants and caused the Member State to implement its strategic
reserve in 2014.
(215) Identifying the underlying causes properly can help targeting the need, type and size
of a capacity mechanism, but even where a solution responds to the identified
problem, it is important that it is proportionate, that alternative solutions have been
assessed properly and that it is not distortive for instance by harming market
functioning or increasing market power.
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4.2.3
Member States carry out increasingly advanced adequacy assessments
(216) To substantiate their concerns about the future generation adequacy, respondents to
the sector inquiry often refer to the assessments carried out for their Member State,
usually by their TSO.
(217) The generation adequacy assessment needs to take into account that both demand and
supply vary considerably during the day, during the year and over the years. They are
dependent on a wide array of variables. Moreover, in liberalised markets without
central planning, the decision on whether to invest in or divest generation units and
whether to produce or not is in the hands of market participants and – for reasons of
business confidentiality – there is often very limited information available about the
commercial plans of individual operators. Various respondents to the interim report of
the present inquiry suggested that one approach to this challenge could be to include
an economic assessment of the expected profitability of the generators in the market.
Even if the decision to remain active, mothball or close down remains in the hands of
the operator, such economic assessment, which could look at elements such as plant
efficiency, generation technology and the projected development of fuel prices, would
provide an indication of the continued profitability of each plant that could be taken
into account in assessing the overall generation fleet expected to be available in future.
It appears from these responses that this element is thus far not taken into account
anywhere in Europe, but its introduction foreseen in any of the ongoing modernisation
and harmonisation efforts as described in the conclusion of this Chapter.
(218) An additional challenge is that adequacy assessments, in order to provide useful
information in time to devise and implement appropriate remedies, need to be able to
look far ahead, e.g. five to ten years, which significantly increases uncertainty.
(219) All Member States that are part of the sector inquiry measure the security of supply
situation in their country by carrying out an adequacy assessment in which one or
more methodologies are applied that give an indication of the potential of the
generation fleet to meet demand in the system at all times and under varying
scenarios. Moreover, in all Member States the TSO is the main responsible body for
carrying out the calculations. In a minority of countries this is followed by either the
government or the national regulatory authority ('NRA') scrutinising the TSO's data
and publishing a monitoring report.
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Table 5: Member State practice in carrying out adequacy assessments
Source: European Commission based on replies to sector inquiry
95
, see Box 1 for a description of
capacity margins, LOLP, LOLE, and EENS
(220) With an increasing proportion of variable renewable resources, electricity systems
have become more complex. To address this increased complexity, a majority of
Member States have replaced relatively simple, ‘deterministic’ assessment metrics –
which simply compare the sum of all nameplate generation capacities with the peak
demand in a single one-off moment – by more complex ‘probabilistic’ models, which
are able to take into account a wide range of variables and their behaviour under
multiple scenarios. This includes not only state of the art weather forecasts, but also
factors in less predictable capacity sources such as the contribution from demand
response, interconnectors or renewable energy sources.
(221) Such advanced adequacy assessments provide signals to market participants, TSOs,
regulators, consumers and policy makers on the most probable development of the
adequacy situation. On this basis, parties active in the electricity sector can choose to
invest or divest and to produce or consume more or less electricity. Box 1 briefly sets
out the various methods and their advantages and disadvantages.
Box 1 Methodologies to assess generation adequacy: from deterministic to probabilistic
models
Today, a variety of adequacy assessment methodologies are applied across Europe. One of the
simplest measures to determine the level of generation adequacy is the
capacity margin.
This
'deterministic' methodology simply expresses the relation between peak demand in the
electricity system and the reliably available supply, usually as a percentage. For instance, a
system with 11 GW of installed capacity and 10 GW of peak demand has a 10% capacity
margin. In two of the eleven Member States only this relatively simple capacity margin is
calculated.
95
Croatia did not provide information on these questions.
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However, deducing the likelihood of generation related adequacy problems from these simple
metrics is not possible with a high level of accuracy/confidence for the following reasons. A
simple capacity margin calculation does not give a reliable impression of the adequacy
situation due to the increase in variable renewables, as shown in Chapter 2. No form of
generation can always output its full nameplate capacity with 100% reliability. The intermittent
nature of solar and wind generation means that these sources in particular cannot always be
assumed to be available and contribute at nameplate capacity during periods of high demand.
The practice of assigning an expected average contribution to various sources of input is
referred to with the term
de-rating.
Measuring capacity margins by comparing peak demand and de-rated total supply can
therefore improve the accuracy of the capacity margin a measure of generation adequacy.
However, although a deterministic model can determine an average contribution that can be
safely expected to be received from the various sources, it cannot do this as accurately as a
probabilistic model. Furthermore, a simple deterministic method can conceal internal grid
bottlenecks. For instance, in Germany the overall amount of generation is expected to remain
positive compared to its overall demand for at least the coming five years, but nevertheless a
network reserve has been in place and regularly used in the South of Germany since 2012 to
cope with network constraints within Germany by enabling re-dispatch capabilities for the
TSOs in the southern regions.
A more sophisticated method to measure generation adequacy is the calculation of a loss of
load probability (LOLP), which quantifies the probability of a given level of unmet demand
over a certain period of time.
Figure 23
above shows that around half of the Member States
carry out a LOLP calculation. Often, LOLP is expressed as a loss of load expectation (LOLE)
which sets out the expected number of hours or days in a year during which some customer
disconnection is expected. (for example, if 1 day in 10 years some customers would need to be
disconnected, LOLE would be 0.1 days or 2.4 hours). This probabilistic approach can take into
account variations in demand over the years as a result of climate fluctuations.
LOLP/LOLE do not measure the total shortfall in capacity that occurs at the time when there
are disconnections, and neither LOLP/LOLE nor capacity margins measure the amount of
unmet demand. This would require a measurement of expected energy not served (EENS)
which would be expressed in MWh over a specific time period (e.g. a year). EENS thus also
makes it possible to monetize the shortfall in a system where VOLL
96
has also been calculated
(see below) since the amount of EENS can then be multiplied by VOLL.
4.2.4
Member State practice in setting reliability standards
(222) Adequacy assessments contribute to an informed decision about the necessity of
capacity mechanisms in the market. If a capacity mechanism is introduced, a
transparent reliability standard is needed to determine the appropriate size of the
96
For a more detailed explanation of VOLL, see paragraph 2.2.2.1
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mechanism. A reliability standard expresses a trade-off between cost and reliability
and determines which long-term level of security of supply is deemed appropriate.
Although it is easy to argue that a system must be 100% reliable, achieving 100%
reliability would entail extremely high costs and in fact would be technically
impossible.
(223) As Table 6 demonstrates, a majority of the Member States included in the sector
inquiry make use of a reliability standard to identify the appropriate level of security
of electricity supply in their territory.
(224) In Member States that calculate a LOLE in the context of their adequacy assessment,
the standard is sometimes expressed as a tolerated number of hours in which there is
some (unquantified amount of) loss of load. Targets generally range from 3 to 8 hours.
In Member States that only calculate a capacity margin, the reliability standard or
target is expressed in terms of a capacity margin percentage. Comparing the outcome
of the adequacy assessment with the standard provides an indication as to potentially
missing capacity and hence the need for and size of a capacity mechanism. Once a
capacity mechanism is introduced, the reliability standard is also required as a
reference point for identifying the amount of capacity to procure through the capacity
mechanism (or, in a price-based mechanism, the price to set).
Table 6: Member State practice in setting a reliability standard
Source: European Commission based on replies to sector inquiry
979899
97
The Belgian LOLE (P95) refers to a 95
th
percentile standard according to which during severe conditions of which the
chance is 5% (i.e. a very cold winter that occurs once in 20 years) the LOLE must be inferior to 20 hours.
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(225) Responses to the Commission's second questionnaire provide further insight into the
relation between LOLE calculations and reliability standards.
(226) None of the six Member States that established a LOLE reliability standard have
experienced any LOLE events in the past five years. However, only Ireland and
Portugal responded affirmatively to the question whether the absence of any lost load
in practice suggested that their standards were routinely exceeded. France and
Belgium said that five years' absence of loss of load does not mean that the standard is
routinely exceeded, given that the standard is based on probabilistic methods taking
into account a large amount of possible situations.
(227) In Ireland, a revision procedure was carried out, but it was decided that the current
level should be maintained. In Portugal, the public bodies indicated that although an
evaluation takes place, but a revision of the standard is not foreseen. The Danish
public bodies instead indicated that the methodology of determining their standard
will change from being based on historic data to a 'politically determined' standard.
(228) To determine their reliability standard, a number of Member States make use of a
calculation of VOLL. Where a Member State calculates VOLL, it estimates the value
an average consumer places on secure electricity supplies at any point in time. In other
words, it is the price point at which the consumer is indifferent between paying for
electricity and being cut off. By using it to determine a reliability standard, it goes one
step further and de facto determines that protection by way of a capacity mechanism
should not go beyond the level of protection that would be achieved through a
perfectly functioning free market for electricity. The higher the degree of protection
desired, the more (back-up) capacity is needed and therefore the higher the price tag
attached to it. In order to determine the cost of additional protection against
disconnections through additional capacity investment, some countries calculate the
cost of new investment by estimating the cost of a 'Best New Entrant (BNE)' or 'Cost
of New Entry (CONE)'. The estimate is usually based on the costs of a new peaking
plant (since this represents a cheaper way of providing marginal capacity than a
baseload plant). A comparison of VOLL and BNE/CONE can identify the point at
which the value for consumers of investment in additional capacity is maximised – at
98
99
Croatia did not provide information on these questions.
The German capacity reserve is triggered when the day-ahead or intraday market do not clear and all other instruments
have been exhausted. The market not clearing means in practice that offers at the maximum bid price (3,000 and
10,000) remain unmatched in the day-ahead and intraday market respectively. Balancing responsible parties pay 20,000
Euro/MWh after deployment of the reserve, if they contributed to the shortage in the system and therefore the need to
deploy the capacity reserve.
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the point at which the incremental cost of insuring customers against power cuts is
equal to the incremental cost to customers of power cuts.
100
(229) Linking the reliability standard to the level of capacity that reflects the maximum
value consumers place on being supplied with electricity, means that an economic
efficient level of protection is set and that expensive overprotection is avoided.
Therefore, a reliability standard based on VOLL and BNE/CONE constitutes in
principle the efficient target guiding any intervention in the market with the aim of
ensuring optimal security of supply.
(230) Less than half of the countries calculate VOLL and use it as their basis for
determining their reliability standard.
101
A possible reason that not all Member States
make use of a VOLL to ensure an economically sensible level of protection may be
that it is difficult to calculate an appropriate average VOLL. Electricity has a different
value for different users and differs over time. An additional complexity, as
underlined in Chapter 2, is that most electricity consumers are currently not able to
individually express their valuation of electricity for every time slot. VOLL
calculations therefore attempt to replace the true (but unknown) value of
disconnection with an administrative average value. The average VOLL in each
Member State or bidding zone is also likely to be different, reflecting the different
cost of a MWh of unserved energy to different types of consumers and/or consumers
in different parts of Europe. However, although calculating VOLL is challenging,
seven countries in the inquiry have made an estimate of VOLL (see Section 2.2.2.1),
and no consultation or questionnaire respondents have justified an alternative way to
calculate an appropriate reliability standard.
(231) Moreover, a majority of the countries that have established a reliability standard do
not link the capacity demanded through their capacity mechanism to the achievement
of this standard. This means that the reliability standard does not fulfil its main
function, namely to ensure an appropriate level of capacity. For instance, respondents
100
101
One of the countries in the sector inquiry considering such approach is Ireland. It has provided a more thorough
discussion on this topic in its consultation paper on the detailed design of its envisaged capacity mechanism:
https://www.semcommittee.com/publications/topics/19
In Italy a different approach to VOLL, reliability standards and the determination of the amount of capacity to be
remunerated in its planned capacity mechanisms is applied. The Italian planned capacity mechanism makes the targeted
reliability standard dependent on the demand and supply in the capacity market. The demand curve is estimated
through a probabilistic approach which embeds the probabilistic generation adequacy assessment, but does not make
explicit a targeted reliability standard. In the Italian proposal, the reliability standard depends on how much will it cost
to achieve a certain level of reliability and on how much consumers are willing to pay for it. Hence, the lower the bids
in the auction, the more capacity will be contracted; and the higher the VOLL of consumers, the more capacity will be
contracted. This approach reflects the idea that the cheaper additional security of supply, the more consumers will be
ready to pay for it. The capacity mechanism in Great Britain and the planned mechanism in Ireland incorporate this idea
by way of a sloping demand curve (though in GB and Ireland a long term reliability standard is also set based on the
expected cost of capacity).
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to the sector inquiry argued that the amount of capacity to be procured in the Belgian
strategic reserve and in the interruptibility scheme in Spain was overestimated.
(232) The sector inquiry also provides evidence that some Member States fail to scale down
their capacity requirements on the basis of a comparison between the standard and the
outcome of the adequacy assessment. For instance, Spain applies a 10% capacity
margin as its reliability standard. The current situation demonstrates there is 43%
capacity margin. Instead of limiting the capacity measure to the achievement of the
applicable standard, Spain has continued to pay capacity payments.
4.3
4.3.1
Assessment
The absence of a common approach in assessing adequacy
(233) The increased concerns of Member States about future generation adequacy have led
to the development and application of more sophisticated and more reliable adequacy
assessments. However, the fact that an increasing number of countries apply a similar
methodology, based on an hourly LOLE, does not mean the outcomes can now be
compared easily with one another. In fact, the assumptions used by Member States to
calculate their LOLE vary widely and are not clearly communicated. This has a
number of potential negative effects: it decreases transparency on the actual level of
protection sought, it reduces the potential for using cross-border data to inform local
assessments and it may lead to inappropriately sized capacity mechanisms. Since
assumptions and scenarios chosen in the individual assessment (e.g. “one in 20 year”
vs “one in 50 year” winter peak, or how imports are taken into account in a national
adequacy assessment) can have an important impact on the outcome of the
assessment, it is important to make the assessment as transparent and comparable as
possible.
(234) The absence of a common approach means that no comparison between the Member
States can be made as to their relative generation adequacy without fully exploring the
individual methodologies used. As a result, Member States cannot simply rely on the
assessment of a neighbouring country and use that as input to their own assessment.
As such, the potentially important contribution of interconnectors may not be fully
taken into account. The diverging approaches of Member States become apparent in
defining what constitutes a LOLE-event and in the approach to de-rating the various
elements in the generation mix.
(235) In the interim report, the Commission concluded that there is no common definition of
what qualifies as a 'reliability event' and thus contributes to LOLE-hours. As a result,
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it is not clear to what extent interventions by the TSO to prevent brownouts
102
or
blackouts – such as issuing generation maximisation instructions, using ancillary
services to fill a supply gap, or implementing voltage reductions – qualify as LOLE-
events. A 2012 report on the Texan electricity market provides an interesting example
of how the application of a LOLE standard can cause confusion.
103
The market
operator ERCOT explains that its legal '1-day-in-10-years' LOLE standard has in
Texas traditionally been interpreted as '1-outage-event-in-10-years' and not as a total
of 24 hours during which there is lost load every ten years. It is however aware that
other market areas of the US, such as in its northern neighbouring market SPP, use the
latter interpretation, and that again other market operators do not use the 1-in-10
standard at all in determining their target reserve margins. It furthermore notes that
although there is consensus in Texas about the interpretation of allowing not more
than one LOLE-event in ten years, there is no definition as to what constitutes an
'event', which means that all events carry the same weight, irrespective of their
seriousness, for the purpose of calculating the standard. Obviously, the size and
duration of an event clearly influence how much consumers are affected by it. The
report remarks that the EENS standard does not have this weakness as it expresses the
standard in the amount (in MWh) of the non-served energy.
(236) Where the question of definition and determination of LOLE has not been answered
with sufficient clarity, the ensuing uncertainty not only makes comparability of the
level of generation adequacy across borders problematic, it also creates a large
discretion for TSOs to determine the volume of the additional safety margins they
believe are needed in a way that may initially appear to be based on VOLL and
therefore consumers' willingness to pay but which in practice targets a far higher level
of reliability.
(237) There is a risk related to leaving large margins of discretion to the TSO, because
depending on its responsibilities and regulation, it may have an incentive to
overprotect. A transparent approach is therefore important to objectivise risk
perception. There is great consensus among both public bodies and market
participants responding to the sector inquiry questionnaires that a more harmonised
approach to determining generation adequacy is necessary.
102
103
A brownout is less serious than a blackout in the sense that it is merely a short voltage reduction and not a complete
loss of power. Brownouts can be intentionally used by network operators to temporarily accommodate increased
demand. Brownouts can however damage special equipment used in industrial processes that require stable power
flows.
The Brattle Group, “ERCOT Investment Incentives and Resource Adequacy, Report to the Public Utility Commission
of Texas, of 1 June 2012, page 101. Available at:
http://www.ercot.com/content/gridinfo/resource/2015/mktanalysis/Brattle_ERCOT_Resource_Adequacy_Review_201
2-06-01.pdf.
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(238) Following the publication of the interim report of this sector inquiry, the Commission
has asked additional information as to how Member States that calculate LOLE
determine which events contribute to LOLE hours and the response has been
consistent: events count as LOLE events only when there is lost load that is caused by
the inadequacy of generation units in the market, i.e. the insufficient availability of
supply to meet demand. TSO interventions to stabilise the grid and ensure security of
supply, such as by using ancillary services or balancing reserves do not generally
count as LOLE events.
Box 2: Putting LOLE in perspective
Reliability standards are generally established to represent a long term average target. In
practice however there may be no unmet demand in some years and a much higher level that
the reliability standard in others. The 3 hours on average per year LOLE standard in France
for instance is derived from a calculation that predicts a 30 hour disruption every ten years
when there is for example a particularly severe winter and high demand for electric heating.
The standards can also appear alarming. The standard of an average of 8 hours in which there
is some loss of load each year in Ireland for example sounds alarming if 'black outs' are
expected for 8 hours each year. It is important to realise that LOLE hours should not be viewed
as hours in which a major blackout takes place leaving entire market areas without power, but
may be solved by TSOs without major impacts, i.e. by using instruments such as temporary
voltage reductions or the selective disconnection of large industrial users. When not seen in
perspective, a Loss of Load Expectation may give the wrong impression that blackouts are
expected. And even the 8-hour per year standard in Ireland – which on the face of it is the most
relaxed standard employed in Europe – translates into a system security level of 99.9% - i.e.
99.9% of the time no one will be involuntarily disconnected.
Indeed, for most Member States network failures, for example after weather events that damage
network infrastructure, have historically led to far more involuntary unmet demand than
generation inadequacy
104
.
(239) The absence of a common approach also becomes apparent with regard to the de-
rating
105
of capacity (most importantly for renewables and imports), which further
complicates cross-border comparison and objective insight into the actual adequacy
situation in a country or bidding zone. There may be good reasons that contributions
of such sources differ per country, but a common approach on the underlying
principles would create an objective basis for cross-border comparison. A large
number of market participants that have responded to the public consultation
104
105
In 2014 ENTSO-E identified over 1000 security of supply incidents. Most of these were minor but there were some
more serious disturbances, for example storms on 12 February 2014 leaving 250,000 homes in Ireland without power.
See
https://www.entsoe.eu/Documents/SOC%20documents/Incident_Classification_Scale/151221_ENTSO-
E_ICS_Annual_Report_2014.pdf.
See Box 1 for a description of de-rating.
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following the publication of the interim report subscribe to this conclusion and express
their wish for more clarity in the calculation of LOLE hours and their translation into
reliability standards, in order to objectivise their authorities' interventions in the form
of capacity mechanisms.
4.3.2
Reliability standards are not used to ensure appropriate intervention
(240) Ideally, comparing the outcomes of an adequacy assessment with the desired level of
protection laid down in a reliability standard that takes into account the average
consumer's willingness to pay for security of supply provides an objective indication
as to whether or not intervention in the market to foster generation adequacy is
necessary and to what extent. At present, this is however not common practice.
(241) Some Member States do not have reliability standards and Member States that do
apply them often do not explicitly link them to the type and extent of their capacity
mechanism. Moreover, a majority of countries does not calculate a VOLL for their
market, nor use it in setting a market price cap or a reliability standard.
(242) This results in a situation in which the necessity and the size of a capacity mechanism
are not always based on a proper economic assessment. As a consequence, there is a
risk that interventions in the market become subjective and hence sub-optimal.
Objectivising the need for and degree of interventions can be done by adopting a well-
defined VOLL as a key indicator in determining an appropriately maximum level of
protection.
4.4
Conclusions
(243) Despite the absence of reliability issues, Member States are concerned about future
generation adequacy for a variety of reasons, mostly linked in some way to the
missing money problem. A thorough problem identification can help tailoring an
intervention in the electricity market to solve the precise problem and adequacy
assessments can help quantifying the extent of the adequacy problems. By using
different scenarios in a transparent and comparable manner, adequacy assessments can
help demonstrate whether an identified problem is of a transitional nature. A
reliability standard can ensure that intervention takes place up to a level consumers
would wish to pay for.
(244) However, practice demonstrates that whilst increased concerns about generation
adequacy have been accompanied by the development of better adequacy assessments,
the proper follow-up to those assessments does not take place, mostly because
reliability standards are not always based on sound economic assessment. As a result,
regulatory decisions on capacity markets are not sufficiently evidence-based and most
capacity mechanisms are not tailor-made to secure the capacity shortfall identified by
an adequacy assessment compared against a reliability standard based on VOLL.
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(245) Demonstrating necessity of intervention is a prerequisite for any capacity mechanism
to be accepted under State aid rules. A more harmonised and transparent approach to
adequacy assessments and VOLL can contribute to objectivising the need for and size
of interventions.
(246) Several harmonisation efforts are already ongoing at European level. The TSOs of the
Pentalateral Energy Forum
106
have carried out a common adequacy assessment at
regional level using a probabilistic approach with an hourly resolution. It includes a
common approach to de-rating RES based on historic climate data, and to the de-
rating of interconnection capacity.
(247) Also ENTSO-E publishes a Europe-wide yearly system outlook and long term
adequacy forecast (SO&AF) on the basis of Article 8 of the Electricity Regulation
(EC) No 714/2009. ENTSO-E develops and improves its methodology regularly and
has established a Target Methodology that will include the use of a probabilistic
method, an extensive range of indicators and state of the art RES and climate
simulations. The first SO&AF under the updated methodology will be published in
2016.
(248) As regional and European-wide methodologies mature and become more reliable, they
should increasingly be used as a basis for assessing the necessity of introducing
capacity mechanisms. Respondents to the public consultation support this conclusion
strongly, pointing out that whilst Member States should be able to apply a national
standard that differs from their neighbours, the standards should be comparable and
have a common methodology as their basis.
(249) With its energy market design initiative, the Commission intends to strengthen the
requirements related to the European and national adequacy assessments. It proposes
an obligation on Member States to adopt a reliability standard that is based on the
value of lost load and expressed as a function of LOLE or EENS. The calculation of
these metrics should be based on a to-be developed common European methodology.
Moreover, the Commission intends to prescribe in more detail what the Europe-wide
framework for generation adequacy assessments and standards should contain. For
instance, it should take into account the economic outlook of the plants in the market,
the regulatory barriers that persist in the market and the potential for market reforms
to help improve the situation in the future. All these proposals should contribute to a
more objective approach to calculating generation adequacy and therefore reduce the
risk of non-economic over- or underprotection.
106
Austria, Belgium, France, Germany, Luxembourg, the Netherlands, Switzerland. The full report is available here:
www.benelux.int/download_file/view/4201/3852/
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5.
5.1
D
ESIGN FEATURES OF CAPACITY MECHANISMS
Introduction
(250) This chapter presents the findings on the design features of the capacity mechanisms
in the 11 Member States covered by the sector inquiry.
(251) Once Member States have assessed their generation adequacy situation and concluded
that there is a need for the introduction of a form of support for generation capacity,
they face a range of choices to design a suitable capacity mechanism to address the
identified adequacy problem. There are a number of considerations to be made
irrespective of the type of capacity mechanism. Chapter 5 aims to present the most
important of those design choices, which are considered in three categories:
Eligibility:
who gets to participate in the capacity mechanism?
Allocation:
how does the selection process among the eligible parties work and how is
the level of capacity remuneration determined?
Product design:
what do participants in the scheme have to do, and what happens if
they don't do it?
(252) For each of those categories, examples from the capacity mechanisms found in the
inquiry will be presented to illustrate the impact of those choices on the effectiveness
of the mechanism.
(253) This final report also includes a new section on the ways in which the design choices
in a capacity mechanism can alter the potential for the abuse of market power both in
the capacity mechanism itself, and in the electricity market.
5.2
5.2.1
Eligibility
Eligibility criteria in capacity mechanisms
(254) Once Member States have identified the residual market failures that they want to
address with a capacity mechanism, they need to decide which capacity providers can
contribute to procuring the identified capacity need and should be made eligible to
participate in the mechanism. Well-designed eligibility criteria enable an optimal
selection of capacity providers to address the identified security of supply problem.
Open criteria encourage participation of all potential sources, whereas more narrowly
defined criteria limit the pool of potential contributors.
(255) This section analyses the eligibility options available to policy makers, and assesses
whether there may be valid reasons for limiting a capacity mechanism to a single or
very few capacity sources. The eligibility rules can explicitly or
de iure
limit
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participation to certain pre-determined capacity types, or set performance related
criteria that have the equivalent effect by
de-facto
excluding of one or more types.
5.2.2
Findings of the sector inquiry on eligibility
(256) The sector inquiry demonstrates that Member States design and target the eligibility
criteria in their capacity mechanism mainly on the basis of:
(1)
Generation technologies:
Member States may for different reasons selectively exclude
specific generation technologies from a capacity mechanism or favour others within
the mechanism. Indeed, the majority of capacity mechanisms covered by the present
inquiry is
de facto
targeted at one or more technologies and excludes others;
(2)
Demand response:
there are several reasons Member States may want to foster the
participation of demand response. As underlined in Chapter 2, an active demand side
could deliver significant benefits to market functioning. And because some forms of
demand response can deliver capacity at short notice it is increasingly a useful
competitor in capacity mechanisms.
(3)
Storage providers:
Member States furthermore need to determine whether storage can
usefully contribute to address the generation adequacy they have identified. Storage
can significantly contribute to security of supply by storing electricity when it is cheap
and abundant, and again releasing it, usually on short notice, when it is scarce and
expensive. Storage can however only provide that capacity (or in other words be
available) for short periods of time.
(4)
New vs. existing capacity:
another eligibility choice that Member States need to make
is whether they want to include new or existing capacity in their mechanism, or a
combination of both. Where Member States were concerned that no investments in
new capacity took place, they have often tended to focus on attracting new capacity,
while when they were concerned that a considerable amount of existing capacity
would go offline in the near future, they have often tended to focus on keeping
existing plants on stand-by outside of the market (i.e. they have introduced strategic
reserves).
(5)
Location:
in case of a geographically delimited capacity problem, Member States have
sometimes chosen to limit participation to the capacity mechanism to the capacity
providers in the zone that experiences the capacity problem. Additionally, many
Member States only consider capacities on their own territory and do not take into
consideration foreign capacities.
(257) This section is divided into sub-sections that address each of these design
considerations.
(258) Table 7 below provides a general overview of the types of capacity providers that are
sought by each of the capacity mechanisms covered by the sector inquiry:
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Table 7: Overview of eligible capacities
(table includes existing, planned and past schemes)
Member State
Belgium
France
Ireland
Italy
Poland
Portugal
Capacity mechanism
Tender for new capacity
Tender for new capacity in Brittany
Tender for new capacity
Eligibility
Tender for new capacity
CCGT and OCGT
CCGT
Thermal generation capacity
Targeted capacity payment
Targeted capacity payments
Generation capacity that can participate in the ancillary services market
Operational reserve
Centrally dispatched generation capacity
Availability incentive
Thermal generation capacity
Investment incentive
Hydro
Availability service
Thermal generation (except nuclear) and hydro (with storage)
Investment incentive
Nuclear, gas, coal, hydro and oil entering into service before 1 January 2016
Environmental incentive
Coal plants
Support to power plants using indigeneous coal Coal plants
Reserve
Generation capacity announced for closure or mothballed and non-generation DSR
Strategic reserve
Minimum demand response purchase obligation of 50MW
Strategic reserve
All types of generation capacity (existing and new), DSR and storage
All types of generation capacity (incl. storage) announced for closure or mothballing
Network reserve
but considered "system relevant". If insufficient, tender for additional capacity
consisting
de facto
of foreign plants (incl. storage)
Capacity reserve
All types of generation capacity (existing and -in future- new)
Centrally dispatched generation capacity entitled to a temporary derogation from
Cold contingency reserve
IED emission standards as of 1 January 2016
Generation capacity and demand response. Minimum demand response purchase
Strategic reserve
obligation of 25%
Central buyer
All generation capacity (existing and new). Italy exploring to include DSR and foreign
Central buyer reliability obligation scheme
capacity as of 2017 auction
All types of generation capacity (existing and new), DSR and storage.
Central buyer reliability obligation scheme
In principle also open to cross border generation capacity.
De-central obligation
All types of generation capacity (existing and new), DSR and storage.
Supplier obligation
France is publicly consulting on possibility of direct cross border participation.
Market-wide capacity payment
All types of generation capacity (existing and new), DSR and storage, foreign
Market-wide capacity payments
capacity and interconnectors
Interruptibility scheme*
Interruptibility scheme
Demand response >50MW
Interruptibility scheme for Sardinia and Sicily Demand response >1MW
Interruptibility scheme for the mainland
Demand response >1MW
Interruptibility scheme
Demand response >0.1MW and not active as demand response in the market
Interruptibility scheme
Demand response >10MW
Interruptibility scheme
Demand response >4MW
Interruptibility scheme
Demand response >5MW or >90MW (two auctions)
Spain
Belgium
Denmark
Germany
Poland
Sweden
Italy
Ireland
France
Ireland
Germany
Italy
Ireland
Poland
Portugal
Spain
*size requirements only given for interruptibility schemes - size requirements also apply in other schemes
Source: European Commission based on replies to sector inquiry
5.2.2.1 Generation technology neutrality
Rationale for selectivity
(259) A clear majority of the existing and planned capacity mechanisms covered by this
inquiry exclude one or more generation technologies. There appear to be various
reasons why governments wish to encourage or discourage the participation of certain
technologies. Environmental considerations for instance may inspire the exclusion of
lignite, coal or nuclear power plants. Member States have also used capacity
mechanisms to promote indigenous energy sources as a secondary objective. This is
for instance the case of the investment incentive mechanism in Portugal, in which only
hydro power plants can participate. It was also the case in the 2010-2014 Spanish
scheme in support of power plants using indigenous coal.
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(260) Member States may also wish to narrow participation in their capacity mechanism to
target the type of capacity that they consider most suitable to alleviate a shortage of
certain types of capacities or capacities with specific abilities. Where existing capacity
for example cannot ramp up and down quickly enough to react to sudden changes in
demand, a Member State may wish to target a mechanism only to flexible capacity
such as demand-response, storage or gas-fired generation. The question is then
whether such objectives cannot be better attained through better remuneration of
ancillary services rather than through a capacity mechanism.
(261) Some capacity mechanisms explicitly exclude capacities which already receive
subsidies via other, separate support schemes. This may on the one hand be mandated
by rules prohibiting the cumulation of aid. On the other hand, full participation and
fair competition can only work if a level playing field exists between potential
capacity providers more generally, through the elimination of subsidies other than
capacity payments to specific capacities.
(262) The sector inquiry found that most Member States support renewable energy and
combined heat-power generation in principle through separate support schemes. While
there are in principle different objectives behind RES support schemes (which aim to
reduce greenhouse gas emissions) and capacity mechanisms (which aim to ensure
security of supply), there is some recognition of the value of RES for security of
supply. Accordingly, more recent capacity mechanisms tend to allow RES to
participate (while at the same time including safeguards to avoid cumulation of aid
from different mechanisms). This is for instance the case of the French de-central
obligation scheme where RES producers are awarded certificates (and receive the
higher of the income from the certificates or the "normal" RES subsidies), and the
British capacity market (where RES can participate provided they opt out of
alternative support schemes). It appears that RES will also be able to participate in the
planned Italian and Irish reliability option mechanisms.
Openness of capacity mechanisms to different generation technologies
(263) To assess how the different types of capacity providers participate in capacity
mechanisms the following sections distinguish between the explicit and implicit
exclusion of generation technologies.
Explicit exclusion
(264) Some capacity mechanisms are explicitly technology specific, determining a single
type of generation technology to fulfil the identified capacity need. This applies to all
tenders for new capacity: the tenders in Brittany (CCGT) and Belgium (CCGT and
OCGT) targeted only gas-fired power plants; in Ireland it was limited to thermal
generation capacity.
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(265) The only capacity payment schemes explicitly open to all generation technologies are
the Irish and Italian one.
107
All the other capacity payment mechanisms covered by the
inquiry are open to specific generation technologies. Typically, participation is limited
to thermal generation, with the exception of the Portuguese investment incentive
mechanism which is open only to hydroelectric plants. In some cases, only a subset of
thermal plants is eligible, such as for instance in the Spanish environmental incentive
scheme and the Spanish scheme for power plants using indigenous sources which are
only open to coal-fired power plants.
(266) In contrast, none of the strategic reserves explicitly excluded certain technology types.
As discussed in the next section, there were however implicit criteria that de facto
limited participation.
(267) The market-wide capacity mechanisms in the inquiry were usually open to all
generation technologies. As already explained above, they however differ in their
treatment of RES.
Implicit exclusion
(268) Eligibility criteria are in some instances defined in such a way that in practice only
certain capacity providers can participate.
(269) A first category of requirements that may lead to the exclusion of certain types of
generation are size requirements. In the mechanisms covered by the inquiry, they
range from a 0.1 MW threshold –for certification in the French de-central obligation
scheme
108
– to a 450 MW threshold for participation in the tender for new capacity in
Brittany.
109
The higher the threshold, the more likely it de facto excludes smaller
generators (especially RES) and also demand response providers.
(270) A second category relates to environmental standards. The sector inquiry found the
example of the Spanish environmental incentive mechanism that required coal plants
to install a sulphur dioxide filter to participate. In contrast, participation in the Polish
cold contingency reserve is reserved for plants that enjoy a temporary derogation from
emission standards under the industrial emissions Directive
110
and are therefore too
107
108
109
110
Participation in the Italian scheme is, in principle, open to all plants admitted to participate in the ancillary services
market. However, size and performance requirements for the ancillary services market lead to the implicit exclusion of
certain generation technologies, such as renewables.
Although smaller capacities can aggregate to surpass the threshold.
Size requirements are for example to be found also in the Belgian tender for new capacity (400 MW for CCGTs and 40
MW for OCGTs), the tender for new capacity in Ireland (50 MW), the Italian targeted capacity payments (10 MW), the
Portuguese targeted capacity payment mechanisms (30 MW), the Spanish investment incentive capacity payment
mechanism (50MW) and all interruptibility schemes.
Directive 2010/75/EU of the European Parliament and of the Council of 24 November 2010 on industrial emissions.
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polluting to operate in the market. The mechanism therefore in practice addresses old
coal and lignite plants only. In the French capacity mechanism, stricter environmental
criteria are applied but only to new projects (see sub-section 5.2.2.4 below).
(271) A third category includes criteria that are based on the technical performance of the
capacity provider, such as power plant efficiency, ramp-up time or the ability to
provide certain ancillary services. Power plant efficiency requirements were for
instance set in the Belgian and French (Brittany) tenders for new capacity.
111
In both
cases, the Member State also required that the power plants were able to provide
certain ancillary services. As these tenders were explicitly addressed at specific types
of newly built power plants, the efficiency and ancillary services requirements did in
practice not exclude certain technologies but rather act as minimum standards for the
offers.
112
Participation in the Italian targeted capacity payment mechanism is only
open to plants that are admitted to participate in the ancillary services market. This has
led to the de facto exclusion of generation capacity that cannot be programmed to
increase or reduce load as required for the performance of ancillary services
(essentially certain RES, such as wind or solar).
(272) Another technical performance criterion relates to ramp up times. The Belgian
strategic reserve for instance requires a 6.5 hour ramp-up time for participating power
plants whilst keeping the door open for even longer ramp-up times if these can be
justified by the bidders. The planned Greek flexibility remuneration mechanism (not
included in the sector inquiry) grants capacity payments to individual plant capable of
increasing electricity generation at a rate greater than 8 MW/min with three hours'
notice (starting from hot conditions).
(273)
Finally, Member States often de-rate capacities to reflect their actual value to supply
electricity during scarcity periods, for example taking into account average
maintenance needs or average load factor. De-rating is common in market-wide
mechanisms including a large variety of capacity providers. De-rating is either
determined centrally (as in the Italian and British central buyer mechanisms and the
Spanish availability incentive mechanism) or de-centrally by the individual capacity
providers subject to ex-post control (as in the French de-central obligation scheme). In
either case, the capacities will only participate in the mechanism to the de-rated
extent. If for example a 400 MW power plant is only expected to make 60% of its full
111
112
In the Belgian example the efficiency requirements were different for OCGTs and CCGTs.
However, in practice the Belgian tender attracted bids from existing foreign plants which proposed to disconnect from
their Member State's grid in order to connect to the Belgian grid and become part of the Belgian TSO's balancing zone
(thereby increasing the amount of capacity available to Belgium). To the extent the minimum power plant efficiency
requirement or requirement to be able to perform ancillary services had the effect of limiting such foreign offers, they
in fact acted as implicit eligibility factors.
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installed capacity available on average, it will be able to participate in the capacity
mechanism only with up to 240 MW
).113
(274) De-rating is particularly relevant for renewables because of their intermittence. In the
French mechanism, renewables producers may opt out of the self-de-rating regime and
apply a pre-determined de-rating factor instead. In that case, their risk for being in
negative imbalance for being unavailability is reduced because they are only
considered unavailable if their unavailability is caused by technical reasons (not
meteorological reasons).
5.2.2.2 Demand response
Rationale for selectivity
(275) Demand response can reduce peak demand and therefore reduce the overall need for
generation and transmission capacity. Moreover, by putting a price on their
willingness to reduce demand, demand response providers and aggregators reveal
their individual Value of Lost Load, as explained in Chapter 2. The participation of
demand response in capacity mechanisms is also of particular importance from a
competition perspective since it may foster new entry and help ensure existing
capacity providers face competition.
(276) Some Member States target demand response specifically by means of interruptibility
mechanisms. Such schemes may be intended to kick-start demand response and
unlock its potential, in particular from energy intensive industries.
Openness of capacity mechanisms to demand response
(277) While almost all Member State support demand response by means of some form of
capacity remuneration, it does not always compete on equal footing in capacity
mechanisms or is even implicitly or explicitly excluded. Even separate interruptibility
schemes are not always open to all types of demand response.
Explicit exclusion
(278) Demand response is explicitly excluded from all tenders for new capacity covered by
the sector inquiry since these target specifically certain generation technologies. It is
equally excluded from all targeted capacity payment schemes subject to the sector
inquiry, but is included in the market-wide Irish capacity payment scheme.
113
Note: in the case of self-de-rating, in theory the respective power plant could participate to the capacity mechanism
with its full 400MW of installed capacity, but it will then be subject to unavailability penalties in order to discourage
overestimating of capacities. The strength of non-performance penalties is therefore particularly important in
mechanisms that allow self de-rating.
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(279) Demand response is furthermore excluded from some strategic reserves (Polish cold
contingency reserve and German network reserve) but included in others (Belgium,
Denmark and Sweden). In the Belgian and Swedish reserve, demand response is only
subject to limited competition from generation since they define a minimum share of
demand response. The requirement to contract a minimum amount of demand
response results in practice in a separate category of strategic reserve that does not
directly compete with generation and therefore does not increase competition in the
capacity mechanism. In Belgium the special treatment of demand response was
welcomed by demand response aggregators as an efficient way to kick-start their
development, and it appears to have such effect as the participation of DSR increased
from 100 MW to 300 MW. Kick-starting the development of new DSR can be further
stimulated by allowing only new DSR to participate to the capacity mechanism for
instance by limiting the participation to one year. In the on hold Danish strategic
reserve, 10% of the total volume required would have been available with a special
capacity product to enable competition between demand response and generators.
(280) Market-wide capacity mechanisms almost always encompass demand response. This
is true for the current Irish capacity payment scheme and the planned Irish central
buyer scheme, but also for the French de-central obligation scheme. The planned
Italian central buyer mechanism does currently not allow for the participation of
demand response, but Italy plans to include demand response at a later stage.
(281) Conversely, in many Member States, demand response is still targeted specifically
through separate mechanisms. This is the case in Germany, France, Ireland, Italy,
Poland, Portugal and Spain, where support is granted through a separate strategic
reserve type of mechanism only aimed at demand response, commonly referred to as
an interruptibility mechanism.
Implicit exclusion
(282) The eligibility of demand response to a capacity mechanism may
de facto
be
influenced by the Member State's design choices on the following points:
size requirements;
the lead time between capacity contracting and capacity delivery; and
the product design (and in particular the availability duration, testing and requirement
to provide collateral), explained in more detail in sub-section 5.4.2.1.
(283) As mentioned above in sub-section 5.2.2.1, some schemes may limit participation to
capacity exceeding a certain size. Although a minimum threshold may be appropriate
to keep the scheme manageable, if that threshold is set too high, this may present a
barrier to entry to smaller demand response providers, particularly if aggregation is
not allowed. A number of interruptibility schemes targeting demand response services
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set such thresholds. For example, in the existing German interruptibility scheme a 50
MW threshold applies (although in the future this is likely to be lowered to 10 MW
and aggregation will become possible), while in Spain separate auctions are held for 5
MW and 90 MW loads with no possibility for aggregation.
(284) The lead time is the time between the conclusion of the allocation process and the start
of the delivery obligation for the successful bidders.
(285) In the originally planned strategic reserve for Denmark, the lead time was only about
one month, while in Sweden it appears to have been around 11 months for generation
and 2.5 months for demand response in the most recent tenders for delivery in winter
2015/16. 40% of market participants in Belgium considered that the two-month lead
time was insufficient for the sourcing of demand response. This concern was voiced
also by respondents in Denmark. However, in all strategic reserves in which demand
response can participate, the lead time is the same for demand response and
generation. These reserves have also in practice succeeded in attracting some demand
response capacity which proved reliable when activated. In interruptibility schemes,
the lead time varies from one month to 3 years. Irrespective of the lead time, the
duration of the scheme as such is considered important for the participation of demand
response operators.
(286) Under the French de-central obligation scheme, demand response providers will be
able to carry out the certification process from four years up to two months prior to the
start of the delivery year, while a minimum three-year lead time is provided for
existing generation. Furthermore, participants in the mechanism will be able to adjust
their position at any time before the delivery period and even after the delivery period
(though –in certain cases- at cost). Market participants welcomed the flexible lead
time envisaged for demand response and the possibility of continuously trading
capacity certificates as it would facilitate their participation.
(287) Market participants in Italy expressed the view that the four-year lead time proposed
for the planned central buyer mechanism would be too long for demand response
providers, who would not be able to commit too long in advance of the delivery
period. The British capacity mechanism includes a one year ahead auction in addition
to the main four year ahead auction, which enables the fine-tuning of the amount of
capacity to be procured for each delivery year to reflect the latest available demand
projections, but was also intended to help enable demand response participation.
(288) As regards product requirements, their impact is illustrated for example by the
experience with the Polish interruptibility scheme. The first auction organised by the
Polish TSO for the procurement of interruptible load was postponed as no offers were
received. Subsequent auction rounds with less strict participation conditions were able
to attract only limited amounts of interruptible capacity (up to around 200 MW of
capacity after a total of five auction rounds spread over four years). According to
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market participants, the potential for interruptible load services in Poland is much
bigger and one of the reasons why the auction did not manage to unlock the full
potential of demand response has to do with the products requirement (demand
response providers find it difficult to understand the the baselining methodology and
identify the actual demand reduction obligation) and the level of remuneration offered
(payment for actual interruptions without availability payments).
5.2.2.3 Storage
(289) The sector inquiry found no capacity payments dedicated solely to storage capacities.
The four market-wide capacity mechanisms covered by the sector inquiry, the existing
Irish capacity payment scheme, the planned Irish and Italian central buyer schemes
and the French de-central obligation scheme, all appear to be open to storage. In the
case of the German network reserve and the on hold Danish strategic reserve storage
would be eligible to participate.
5.2.2.4 New vs. existing capacities
Rationale for selectivity
(290) With respect to the inclusion of new and existing capacities, the sector inquiry has
shown that the focus of Member States is often either entirely on attracting new
capacity or on avoiding the closure of existing capacity, rather than both. The capacity
mechanisms are therefore often tailored entirely to address either of those problems.
At one end there is the tender for new capacity, aiming to attract new capacity only,
while at the other end there is the strategic reserve aimed at keeping plants that were
announced for closure or mothballing available to the system.
Openness of capacity mechanisms to new and existing capacities
Explicit exclusion
(291) In four Member States (Belgium, France, Portugal and Spain), separate capacity
schemes for new and existing capacity providers co-exist or are planned.
114
(292) In the three tenders for new capacity identified as part of the sector inquiry (the
abandoned tender in Belgium and the ones in Ireland and Brittany), contracts were
offered to new generation capacity only. Existing capacity would receive no
remuneration.
114
In the case of Belgium, a tender for new capacity was envisaged alongside the strategic reserve but was later
abandoned.
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(293) None of the strategic reserves covered by the sector inquiry explicitly excluded new
capacity. Equally in the central buyer models in Britain and being developed in
Ireland and Italy both existing and new capacity can participate. The same is true for
the French de-central obligation scheme, where both new-build generation capacity
and existing capacity can be certified and consequently receive tradable certificates.
(294) Capacity payment mechanisms are almost always open to both new and existing
capacities. In certain cases, however, capacity payment mechanisms may be
specifically targeted at new-build capacity. This is for instance true for the Spanish
and Portuguese investment incentive mechanisms.
Implicit exclusion
(295) Even in cases where both new and generation capacity can theoretically compete,
either of them can
de facto
be excluded by:
lead time;
contract duration; or
specific prequalification requirements.
(296) The concept of
lead time
is not applicable to the capacity payment mechanisms
covered by the sector inquiry because there is no time gap between the allocation and
the delivery obligation. This is because in this kind of mechanism, capacity providers
are either automatically selected or are selected upon the submission of a simple
application form, as long as they fulfil the eligibility criteria. Table 8 below provides
an overview of the lead time in the remaining capacity mechanisms.
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Table 8: Lead time in the capacity mechanisms covered by the sector inquiry
Member State
Belgium
France
Ireland
Belgium
Denmark
Germany
Poland
Sweden
Germany
Italy
Poland
Portugal
Spain
Ireland
Italy
Lead time *
Tender for new capacity
Tender for new capacity
Proposed by tenderers
Tender for new capacity in Brittany
Proposed by tenderers
Tender for new capacity
3 years
Strategic reserve
Strategic reserve
~ 2 months
Strategic reserve
1 month
Network reserve- mandatory
1 year**
Network reserve - voluntary
4.5 months
Capacity reserve
Not yet known
Cold contingency reserve
~ 2 years
Strategic reserve - generation
8-11 months
Strategic reserve -demand response
2.5 months
Interruptibility services scheme
Interruptibility scheme
2 weeks
Interruptibility scheme for Sardinia and Sicily
3 years
Interruptibility scheme for the mainland
3 years to 1 month
Interruptibility scheme
Not available
Interruptibility scheme
Not applicable*
Interruptibility scheme
~ 4 months
Central buyer mechanism
Planned central buyer mechanism
Not yet known
Planned central buyer mechanism
4 years
Decentralised mechanism
Supplier obligation- existing generation
4 to 3 years
Supplier obligation - new generation
4 years to 2 months
Supplier obligation -demand response
4 years to 2 months
Capacity mechanism
France
* The concept of lead time is not applicable to capacity payments
**Planned closure must be announced 12 months ahead
Source: European Commission based on replies to sector inquiry
(297) It appears from Table 8 that strategic reserves tend to have shorter lead times than the
other volume-based mechanisms. Despite in theory being open to new and existing
generation capacity, they managed to attract only existing generation.
(298) 40% of market participants in Belgium believe that the two-month lead time is
insufficient to carry out the technical investments needed to bring the selected
installations in line with the requirements of the strategic reserve.
(299) In Ireland, the tender for new capacity was launched in 2003 and became operational
by the planned deadline in 2006. The lead time for the tenders for new capacity in
Belgium and France was not set in advance but had to be proposed by tenderers and
was evaluated as part of the award criteria. In the French tender, the regulatory
authority (CRE) expressed reservations about the proposed timeframe for completion
of the project by the successful bidder.
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(300) A lead time of four years for both new and existing capacity applies in the British
central buyer mechanism and is envisaged in the Italian one. The British 2014 and
2015 four year ahead auctions managed to attract about 2,621 MW and 1,936 MW of
new generation capacity, respectively.
115
Under the British central buyer mechanism
an additional auction is held one year ahead of delivery and capacity providers can re-
trade their capacity in a secondary market, and the Italian mechanism provides for
adjustment auctions and secondary trading of reliability obligations.
116
(301) Conversely, under the French de-central obligation scheme, different lead times are
envisaged for new and existing capacity. The latter must be certified between three
and four years ahead of the delivery year while new generation capacity (like demand
response) can be certified up to two months prior to delivery. It is noteworthy that
capacity certificates can be traded for the whole duration of the lead period.
(302) The vast majority of market participants in France and Italy consider the lead time
appropriate to allow the participation of new generation capacity provided that the
necessary authorisations and permits have already been obtained at the time of the
capacity allocation. However, market participants in France pointed out that the
mechanism, which is in principle based on bilateral trading, will be successful in
triggering new investments only if clear price signals are provided at the beginning of
the lead period. For that purpose the French authorities revised the mechanism to
include a central buyer element, whereby the TSO contracts competitive new
capacities longer term (7 years). The contract is in the form of a contract for
difference, comparable to a feed-in premium. The price of the individual offers will
serve as a 'strike price': if the capacity market price is above the strike price, the
capacity provider will pay back the difference; if the market price is below the strike
price the capacity provider will receive a subsidy covering this difference.
(303) This moreover illustrates that the length of the contracts concluded under the capacity
mechanisms is equally essential to determine the competition between new and
existing capacity. In principle, a longer contract duration provides additional coverage
against uncertainty on future revenues. Long contracts can therefore reduce the rate of
115
116
The total capacity purchased amounts approximatively to 49,259 MW in 2014 and 46,354 MW in 2015. See National
Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at:
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;
and National Grid, Provisional Auction Results, T-4
Capacity Market Auction 2015, available at
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/2015%20T-
4%20Capacity%20Market%20Provisional%20Results.pdf
In the Italian central buyer mechanism the main auction (T-4) will be followed by yearly adjustment auctions with the
aim of enabling capacity providers to re-negotiate the contracted obligations and the TSO to adjust the amount of
capacity to be procured in concomitance with the approaching of the delivery period. Hence, for these auctions the lead
time varies from three to one year. Furthermore, participants will be able to further adjust their position through
continuous trading in the secondary market during the period from the adjustment auction and the delivery period.
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return required by the promoters of new investment projects and facilitate external
project financing. These considerations must however be balanced against the benefits
of shorter contracts, which allow for the reflection of rapidly evolving market
conditions and avoid locking-in certain technologies.
(304) Table 9 below provides an overview of the duration of contracts or certificates in the
capacity mechanisms covered by the inquiry.
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Table 9: Contract length in the capacity mechanisms covered by the sector inquiry
Source: European Commission based on replies to sector inquiry
117
(305) In strategic reserves open to both new and existing generation capacity, the contract
length is the same for both and ranges from 1 to 3 years. An exception is the German
network reserve that allows for contracts of up to 5 years. In any event, these strategic
reserves have managed to attract only existing generation capacity (and in some cases
demand response). Market participants consistently expressed the opinion that
strategic reserves are not fit to promote investments in new capacity. Moreover,
several market participants have argued that one and two-year contracts may not be
sufficient to refurbish existing generation units.
117
Plants in the German network reserve can be forced to remain in the network reserve beyond the indicated contract
lengths of 2 and 5 years so long as the relevant TSO continues to consider them 'system relevant'.
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(306) In the case of the inquired capacity payment mechanisms open to both new and
existing capacity, the duration of contracts is one year. An exception is the Portuguese
availability incentive payment scheme which grants the payments for the entire
operational lifetime of new plants and for the remaining lifetime of existing plants.
With respect to the duration of the payment schemes as such, it is indefinite in Italy
and Portugal, while it is limited to 10 years in Ireland and one year in Spain.
According to the Irish authorities, the mechanism has managed to attract investments
in generation, demand response and storage since its introduction in 2007. On the
other hand, market participants from those countries where the duration of the
mechanisms is short (Spain) or the level of remuneration has varied significantly over
time (Spain and Portugal) are of the view that the mechanism mainly aims at
preventing existing generation from exiting the market. They have also noted that the
changes in the level of remuneration create uncertainty and undermine signals for
investments.
(307) In the planned Italian central buyer mechanism, the contract length is the same for
new and existing generators. Market participants in Italy are generally of the view that
contracts of three-year duration may be sufficient to attract investments in new
generation capacity. Others however pointed out that this duration is only sufficient to
avoid mothballing which would be the objective of the mechanism given that most
CCGT units in Italy are new and efficient.
(308) Initially, in the French mechanism one-year contracts were considered sufficient to
address the missing money problem for existing generators and other capacity
providers, but market participant respondents stated that the mechanism would not
attract investments in new capacity. For that purpose, as explained above, the French
authorities revised the mechanism to include a central buyer element, where the TSO
contracts competitive new capacities longer term (7 years) on contracts for difference.
(309) The British capacity mechanism was the first among those open to new and existing
capacity to differentiate in the contract lengths for new and existing capacities. The
2014 and 2015 auctions attracted approximatively 2,621 MW and 1,936 MW of new
generation capacity respectively. In view of different obligations pertaining to such
new capacities, in 2014 92% of the new generation capacity was awarded long term
(14 and 15 year) contracts (2,423 MW), while in 2015 only 50% (982.50 MW) of
new-build generation chose those types of contracts.
118
118
See National Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at:
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;
and National Grid, Final Auction Results, T-4 Capacity
Market Auction for 2019/2020, available at:
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(310) Likewise, all three tenders for new capacity (Belgium, France and Ireland) offer
longer contract durations ranging from 6 to 20 years. In Spain, 20 year contracts are
available under the investment incentive capacity payment scheme. In Portugal, where
10-year contracts are allocated for the construction of new hydroelectric
installations
119
, installed hydro capacity is expected to increase from 5.6 GW in 2014
to 7.9 GW in 2020.
(311) Additionally, new generation capacity is often implicitly excluded through
preselection criteria, such as the 15 months prior announcement for closure in the
Belgian strategic reserve, the requirement for plants to derogate from emission
standards under the IED in the Polish cold contingency reserve or the prohibition for
plants to return to the market once they have entered the German strategic reserve. In
all these cases, new generation capacities are effectively excluded or strongly
discouraged from participating.
(312) But there are also cases where additional requirements apply to new capacities,
without necessarily excluding new projects. For example, in the French capacity
mechanism stricter environmental criteria apply for new projects willing to benefit
from long-term contracts. Such "positive discrimination" was considered justified by
France since the state had a direct role in contracting such capacity (thereby
guaranteeing their remuneration for a longer period), whereas this could not be said of
capacity contracted directly by other market players (suppliers).
5.2.2.5 Locational requirements within the Member State
Rationale for location requirements within the Member State
(313) One main reason to include locational capacity requirements in a capacity mechanism
is to take account of network constraints and ensure capacity is built or maintained in
particular places.
Locational requirements in capacity mechanisms
(314) The capacity mechanisms covered by the inquiry are in general open to capacity
irrespective of its location within the Member State although separate rules often
apply to islands.
120
119
120
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf
Note: in this Portuguese investment incentive scheme for hydro power plants, 10 year contracts are equally granted for
the repowering of existing plants, in order to extend their lifetime.
Participation in capacity mechanisms in Portugal and France is limited to capacity providers located on the mainland,
while the British capacity mechanism excludes capacity providers located in Northern Ireland. Moreover, Italy has
separate interruptibility auctions for Sardinia and Sicily.
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(315) Exceptions are the tender for new capacity in Brittany and the Italian central buyer
mechanism where participation is linked to the location of the capacity provider in a
certain region within the Member State. The on hold Danish strategic reserve, the
German network reserve and the Swedish reserve also have locational requirements.
Explicit exclusion
(316) Explicit locational eligibility requirements can be found in the tender for new capacity
in Brittany, given that the new power plant must be built in a certain area of Brittany.
In the Swedish reserve, only capacity located in South-Sweden can be contracted
while the on hold Danish reserve was intended to contract only capacity located in
East-Denmark. Furthermore, the central buyer mechanism in Italy envisages zonal
capacity auctions, which means demand for capacity will be established for each of
six zones in Italy, and a separate capacity price established in auctions for each zone
depending on the local balance of supply and demand.
Implicit exclusion
(317) Implicit locational requirements are to be found in the 'mandatory part' of Germany's
network reserve, which is
de facto
restricted to generators located in South-Germany.
5.2.2.6 Cross-border locational requirements
Rationale for excluding cross-border participation
(318) Member States mostly limit participation in the mechanism to capacity located in their
territory, citing various reasons mostly based around the relative lack of control their
TSOs have over foreign capacity and the inability to ensure imports when they might
need them without reserving interconnector capacity for this purpose – which would
undermine the efficiency of the Single Market by reducing the interconnection
available to traders.
Openness of capacity mechanisms to foreign capacities
(319) Table 10 shows the current approaches taken with regard to foreign capacity in the
Member States included in the sector inquiry, based on information provided by
public body respondents. Since all of the existing mechanisms covered by the inquiry
either explicitly include or exclude foreign capacity, this subsection does not make a
distinction between explicit and implicit exclusion.
(320) Portugal, Spain and Sweden appear to take no account of imports when setting the
amount of capacity to support domestically through their capacity mechanisms. In
Belgium, Denmark and Italy, expected imports are reflected in reduced domestic
demand in the capacity mechanisms. The only examples of capacity mechanisms
which allowed, allow or plan to allow the direct participation of cross-border capacity
are found in Belgium, France, Germany and Ireland.
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(321) Foreign plants were allowed to participate in the Belgian tender for new capacity,
provided that they would subsequently become part of the Belgian bidding zone even
if geographically located in another Member State.
(322) In France, a hybrid model of explicit cross-border participation is proposed. Foreign
generation and demand response capacity will be able to participate directly to the
French capacity mechanism through a market based process that enables the foreign
capacity or the interconnector to each receive a share of capacity remuneration
depending on the relative scarcity of each
121
. France intends to enable the delivery of
foreign capacity under this system from 2019.
(323) None of the strategic reserves are open to generators located outside of the Member
State operating the reserve, except for the German network reserve which contracts
capacity outside of Germany provided that it can contribute to alleviating security of
supply problems in Southern Germany through re-dispatch abroad. As explained in
more detail in sub section 7.1 of Annex II to this report, it appears that the situations
in which cross-border reserve capacity could actually be useful to the zone with the
strategic reserve, are limited unless interconnector capacity was reserved specifically
to allow the reserve to be dispatched across border. This however would be inefficient
because it would permanently reduce the amount of interconnection capacity available
commercially for market coupling.
(324) In the Irish tender, foreign capacity could participate if it could demonstrate its
contribution to Irish security of supply – no foreign capacity was selected in the
tender. In the existing Irish capacity payments model, foreign capacity can benefit
from capacity payments. However, the method for enabling this participation involves
levies and premiums on electricity prices and is not therefore compatible with market
coupling rules which require electricity prices, not capacity premiums/taxes, to
provide the signal for imports and exports.
122
(325) A condition of the State aid approval for the British capacity mechanism was that the
participation of interconnected capacity would be enabled. Since December 2015 the
British capacity mechanism has included interconnectors with Britain, which are de-
rated by the TSO and can then participate as price takers (i.e. they cannot bid above a
predetermined threshold without having to justify the need for that higher support) in
capacity auctions. Interconnectors receive one year capacity agreements at the auction
121
122
Interconnection tickets will be allocated per interconnector on the basis of that interconnectors’ contribution to security
of supply in France. They are then auctioned border by border. Capacities that win interconnector tickets in the auctions
can get certified and receive certificates to the amount of their certified capacity. Subsequently, they will be able to
trade their capacity certificates on the French capacity market.
Note however that the Irish capacity mechanism does operate across the UK and Irish border because of joint market
arrangements and a single bidding zone covering Ireland and Northern Ireland.
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clearing price, in return for a capacity obligation requiring the delivery of capacity
towards Britain at times of scarcity.
(326) More Member States are now apparently ready to follow in the UK and France's
footsteps and aim to develop cross-border participation in their mechanisms. Ireland
published a decision paper on the design of its future capacity mechanism indicating
that an 'interconnector led model will be used at the inception of the capacity
remuneration mechanism, moving to a hybrid option later where both interconnectors
and external capacity providers are paid for their contribution to the I-SEM generation
security standard'
123
, and also Italy is apparently considering future foreign
participation in its capacity mechanism.
123
Second CRM Decision paper, SEM-16-022 of 10 May 2016,
https://www.semcommittee.com/sites/semcommittee.com/files/media-files/SEM-16-
022%20I%20SEM%20CRM%20Detailed%20Design%20Decision%20Paper%202.pdf,
p. 5
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Table 10: Approach to cross-border participation in the capacity mechanisms in sector inquiry countries
Source: European Commission based on replies to sector inquiry
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Both interconnectors and foreign capacity provide security of supply
(327) The contribution foreign capacity makes to a neighbour's security of supply is
provided partly by the foreign generators, storage or demand response providers
that deliver electricity, and partly by the transmission (interconnection) allowing
power to flow across borders. Depending on the border, there can be a relative
scarcity of either interconnection or foreign capacity.
(328) In its 24 September consultation on options for cross border participation in the
French de-central obligation scheme, RTE included analysis of the extent to
which interconnection with its neighbours is a limiting factor to receiving imports
at times of scarcity in France. In only 15% of scarcity situations in France,
interconnectors between Belgium and France are congested (i.e. there is no more
capacity available to transfer electricity from Belgium to France). But in 95% of
scarcity situations in France, interconnectors between France and Spain, France
and Switzerland, and France and Italy are congested.
Figure 24: Probability that interconnectors are congested at times of stress in
France
Source: RTE Consultation on cross-border participation
(329) RTE's analysis shows that while there may be a relatively strong security of
supply benefit to France of increased investment in generation and demand
response capacity in Belgium, there is likely to be relatively little security of
supply benefit to France of increased investment in generation or demand
response capacity in Spain, Switzerland or Italy; on those borders, France would
see increased security of supply from increased investment in interconnection.
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(330) This complicates the design of an efficient solution for enabling cross border
participation in capacity mechanisms since it requires an appropriate split of
capacity remuneration between interconnector and foreign capacity to reflect the
relative scarcity of each. It also ideally requires this split to adapt over time – for
example through a design that increases the reward for foreign capacity and
reduces the reward for interconnection if over time the proportion of
interconnection increases. The 'hybrid' approach to cross border participation
proposed in France should address this issue, and is in line with the proposal
published as part of the interim report of the sector inquiry (see Annex 2). The
Market Design Initiative will propose further rules to assist Member States with
the implementation of hybrid solutions that appropriately reward both foreign
capacity and interconnection.
5.2.3
Issues encountered in relation to eligibility
5.2.3.1 Despite trend towards opening, high selectivity of existing capacity
mechanisms
(331) The findings on the various capacity mechanisms indicate that most mechanisms
are still targeted at a limited range of capacity providers. The sector inquiry
shows that implicit participation requirements are not only as frequent as explicit
ones, they are also equally effective in reducing the range of eligible capacity
providers.
(332) There is however a growing tendency towards more encompassing mechanisms.
This trend is illustrated by the recent British central buyer mechanism, the de-
central supplier obligation scheme in France, the planned central buyer scheme in
Ireland and, so far to a lesser degree, by the mechanism being developed in Italy
which for the time being excludes demand response.
5.2.3.2 Selectivity leads to less competition
(333) Eligibility criteria are of particular importance from a competition perspective. If
allowing for a wide participation, a competitive bidding process allows the
market to bring forward the technologies that can most cost-efficiently provide
the required capacity. Competitive pressure should provide capacity providers
with incentives to bid at the level that corresponds to the funding they require to
provide the necessary capacity product.
(334) The supply curve in the most recent British capacity auction (see Figure 25) and
the mix of different capacity types selected in the auction (see Figure 26)
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suggests that extending the pool of eligible capacities should increase competitive
pressure and lead to a lowering of the price paid for capacity.
124
Figure 25: British Capacity Market 2015 auction supply curve
Source: National Grid
125
(335) In the 2015 British capacity auction 46.35 GW of capacity was contracted to the
different types of capacity included in the left hand pie chart of Figure 26
whereas 11.37 GW of different capacity types participating to the auction did not
receive contracts (see the pie chart at the right hand side of Figure 26. In this
case, the exclusion of storage capacity, for instance, would have required the
procurement of 2,617 MW of other, more expensive (since not selected) types of
capacity. In other words, less competition for the capacity contract would have
led to a higher overall capacity price and,
a contrario,
increased competition
leads to lower capacity prices. By opening up the pool of eligible resources as
much as possible without jeopardising the objective of the mechanism, Member
States can therefore attain security of supply at a lower price.
124
125
Note if demand is reduced to account for excluded capacity then the price paid for capacity may also reduce.
However, if capacity is excluded there is less certainty about whether it will actually be available in the delivery
year. Any exclusion also reduces the potential for new entry, which will help increase competition and exert
downward pressure on prices.
National Grid - Final Auction Results T-4 Capacity Market Auction for 2019/20. Full report available here:
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf
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Figure 26: Results of 2015 T-4 British capacity auction; left: capacity providers
contracted; right: non-selected capacity providers
Source: National Grid
126
5.2.3.3 Interruptibility schemes should not result in overcompensation of industry
(336) There is a risk that interruptibility schemes are not competitive (for instance
because of high participation thresholds, as described in sub-section 5.2.2.2) and
overcompensate participating industries. A reason is that it is difficult for
governments to estimate the actual costs of load reductions or load-shifting. Some
of these mechanisms were indeed criticized by respondents to the sector inquiry
as constituting indirect subsidies to energy intensive industries. This was
particularly the case for interruptibility mechanisms that were in practice hardly
ever used (for instance in Portugal and Spain) or where the remuneration level
was much higher than the one paid to generators under another capacity
mechanism (as in Italy). In Poland, in contrast, the demand response-specific
capacity mechanism remunerated demand only if actual curtailments were carried
out by the TSO (i.e. per MWh payments instead of per MW payments).
Moreover, during actual scarcity periods, the TSO curtailed demand
administratively (without remuneration) rather than through the mechanism.
(337) Separate demand response schemes may however be justified to unlock demand
response potential. This objective was most explicitly present in the UK Capacity
Market where two transitory auctions (TA) were organised to unlock “unproven”
demand response, which could subsequently, once they won a TA contract and
126
Ibid.
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therefore became “proven”, participate to the general capacity auctions in order to
increase competition in those.
5.2.3.4 Selectivity leads to a snowball effect
(338) The selective remuneration of certain types of capacity only will aggravate the
missing money problem of non-remunerated types of capacity and more often
than not eventually require the development of additional support measures
targeted at those capacity types.
(339) An example is the fragmented landscape of capacity payment mechanisms in
Spain. As early as in 1997 Spanish power plants started receiving targeted
capacity remuneration. This however did not appear sufficient to address the
generation adequacy problems, since in 2007 the scheme was complemented by
an interruptibility scheme and later still, in 2010, by a preferential dispatch
scheme for indigenous sources (coal).
127
(340) Another example is the tender for new capacity that is conceived as an
emergency response to a perceived urgent need for new generation capacity
which the market does not bring forward. If this is indeed the objective of the
tender, and it is not accompanied by energy market improvements, it ignores the
reasons why the market fails to make the investment decision on its own
initiative. If market participants are not confident that the investment will
generate a positive return on investment and therefore fail to make new
investments, this may indicate that there is a general missing money problem in
the market, such that market conditions are already negative for existing plants.
The addition of a subsidized power plant to the merit order would only aggravate
that situation. In other words, the addition of new generation capacity would only
aggravate the missing money problem of existing capacity. This was evidenced
by the information received by the Commission when Belgium intended to
develop a tender for new gas-fired production capacity, which was argued to
further deteriorate the already negative business models of existing gas-fired
power plants. It is then only a matter of time until either a solution for the missing
money problem of the existing plants imposes itself or the need for another tender
or capacity mechanism arises (as a result of existing capacity closing or
127
In order to obtain sufficient running hours to make the selected coal plants viable, under that scheme the selected
coal plants are dispatched prior to other plants, even if these other plants have placed a lower bid in the market.
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mothballing). Indeed, in all cases where a tender was launched, it was
accompanied or followed by another mechanism.128
(341) Although it can not be excluded that Member States suffer from multiple and
diverse market failures, these can usually be addressed by a single market-wide
capacity mechanism that allows for competition between a broad spectrum of
potential capacity providers. Where Member States wish to opt for a piece-meal
approach, they risk creating inefficiencies and their mechanisms will therefore
generally be found to not be appropriate or to lead to overcompensation. The
exception to this rule is the separate support to unlock demand response potential,
in view of the considerations made on interruptibility schemes in section 6.2.3.
5.2.3.5 Capacity mechanisms do not address causes of locational capacity issues
(342) Where there is a locational capacity problem (i.e. there is either not enough
generation capacity located in that particular region or that region is poorly
connected to neighbouring regions), this is a sign that the electricity market is
failing to provide the required signals for investment in the right places, or for
sufficient transmission investments to mitigate any locational problem.
(343) The sector inquiry has found two types of capacity mechanisms that have
selective locational requirements within a Member State's territory:
(i) those that correspond to bidding zones, such as the existing Swedish and on hold
Danish reserve which only procure capacity in specific parts of the country, and
the Italian central buyer mechanism which is country-wide but sets different
demand levels for different bidding zones; and
(ii) those that are intended to encourage investment in particular locations within
large bidding zones, for example the Brittany tender and German network
reserve.
129
(344) All of these mechanisms can maintain or obtain more capacity in a specific
region. However, the reserves may not be appropriate in the longer term because
their aim is generally to keep existing capacity from mothballing or closing and
not to enable new investments. Similarly, tenders can provide a quick-fix solution
for a lack of investment in a certain region, but they will have to be accompanied
128
129
For France, the tender was accompanied by the de-central obligation mechanism, for Ireland, the tender was
followed by a market-wide capacity payment mechanism and in Belgium the tender was launched while in
parallel a strategic reserve was developed.
Also Ireland is considering building locational signals into their planned capacity mechanism, but it has not been
decided in what way the new mechanism will take locational requirements into account.
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by other measures aimed at improving local investment signals to avoid the need
for another tender in the future. Only the Italian central buyer mechanism appears
to have the potential to address the underlying market failures preventing
investment in a particular region in the longer term by allowing the corresponding
regional electricity and capacity prices in Italy's bidding zones to provide suitable
investment signals.
5.2.3.6 The exclusion of foreign capacity distorts the Single Market for energy
(345) The exclusion of foreign capacity from capacity mechanisms reduces the
efficiency of the Single Market and increases costs for consumers. The most
damage is done if Member States make no assessment of the possibility of
imports when setting the amount of capacity to contract through a capacity
mechanism (in a volume-based model) or setting the price required to bring
forward the required volume (in a price-based mechanism). This approach will
lead to overcapacity in the capacity mechanism country, and if each country has a
capacity mechanism and does the same thing, overcapacity throughout Europe.
The potential unnecessary costs of this overcapacity have been estimated at up to
EUR 7.5bn per year in the period 2015-2030.
130
(346) As shown in Table 10 above, some Member States have recognised this problem
and attempted to address it by taking account of expected imports (at times of
scarcity) when setting the volume to contract in their capacity mechanism. But
although this approach recognises the value to security of supply of connections
with the Single Market for energy and reduces the risk of domestic over-
procurement it does not address two further ways in which the exclusion of
foreign capacity from capacity mechanisms can have distortive impacts across
border:
(i) If only domestic capacity receives capacity payments, there will be a greater
incentive for domestic investment than investment in foreign capacity or
interconnectors. Signals for investment will therefore be skewed in favour of the
capacity mechanism zone and there will be less than optimal investment in
foreign capacity and in interconnector capacity.
(ii) If capacity mechanisms provide incentives for short term operation on top of the
electricity price signal (through capacity obligations and penalties) they will
reduce the potential effectiveness of the electricity price as a signal for efficient
short term market operation, demand response and imports. This is because it
130
See Booz & Co, 2013, 'Study on the benefits of an integrated European energy market':
https://ec.europa.eu/energy/sites/ener/files/documents/20130902_energy_integration_benefits.pdf
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would never make sense to have a combination of electricity prices and capacity
mechanism penalties providing a stronger short term signal for operation than
electricity prices at VOLL, which represents consumers' maximum willingness to
pay. This issue is not discussed further here, but is considered in sub-section
5.4.3.2.
5.2.3.7 Split of capacity remuneration between interconnectors and foreign
capacity
(347) If a capacity mechanism only rewards interconnection or foreign capacity, it will
not fully correct the distortions the capacity mechanism causes to investment
incentives. To ensure the right investment incentives, the revenues from the
mechanism paid to the interconnector and/or the foreign capacity should reflect
the relative contribution each makes to security of supply in the zone operating
the capacity mechanism. Where interconnection is relatively scarce but there is
ample foreign capacity in a neighbouring zone, the interconnectors should thus
receive the majority of capacity remuneration.
131
This would reinforce incentives
to invest in additional interconnection, which is the limiting factor in this case.
Conversely, where there is ample interconnection but scarcity of foreign capacity,
the foreign capacity should receive most of the capacity remuneration. In this
case, foreign capacity is the limiting factor that should receive additional
incentives.
5.2.3.8 Risk of increasing fragmentation from diverse cross-border solutions
(348) As explained in sub-section 5.2.2.6, some Member States have developed or are
attempting to develop solutions to enable cross border participation in their
capacity mechanisms – France, Ireland and the UK for example. When
developing solutions for explicit participation of interconnectors or foreign
capacity to their mechanism, Member States need to address a number of policy
considerations. For example, an explicit participation model needs to identify:
whether there should be any restriction on the amount of capacity that can
participate from each connected bidding zone – including considering more
remotely connected zones;
what type of capacity product (obligations and penalties) should apply to foreign
capacity providers; and
131
For regulated interconnectors, any capacity congestion rents earned would need to be appropriately regulated (eg.
refunded to consumers in the connected markets if the interconnector's revenues – including the capacity
revenues – are above its regulated cap). See Regulation 714/2009 Articles 16 and 17.
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which foreign capacity providers are eligible to participate – for example whether
a mechanism should be open to interconnectors and/or to foreign capacity
(demand response, generation, storage).
(349) The risk with an uncoordinated approach is that the Single Market becomes
increasingly fragmented and complex, with specific different rules emerging on
each border.
(350) It is therefore not surprising that 85% of market participant respondents and 75%
of public body respondents to the sector inquiry questionnaire felt that rules
should be developed at EU level to limit as much as possible any distortive
impact of capacity mechanisms on cross national integration of energy markets.
As explained in sub-section 5.2.3.6 above, one of the main ways in which
capacity mechanisms create distortions cross border is if they are limited to
national capacity. The Commission therefore developed a potential approach
concerning aspects of cross border participation which is included in Annex 2.
France has proposed to adopt the approach outlined in Annex 2 in its mechanism
and the Market Design Initiative includes proposals to require the implementation
of such an approach in future.
5.2.4
Conclusions on eligibility
(351) To obtain as much competition as possible in the capacity mechanism, Member
States should design a mechanism that is as encompassing as possible so that
different types of capacity providers are effectively put into competition with
each other. This may require specific arrangements to accommodate certain
capacity types, the benefit of which should again be balanced against the possible
discrimination created by differentiated treatment of different capacity resources.
(352) Although certain selective capacity mechanisms may appear to be appropriate
solutions to address immediate or transitory capacity concerns, in the long run
they often do not really target the underlying adequacy problem and even risk
aggravating it. They may therefore trigger the need for additional capacity
mechanisms to address the fallout of the initial mechanism(s). However, since
parallel capacity mechanisms fail to foster competition between different types of
capacity providers, they should be avoided as much as possible.
(353) Unless interconnectors and foreign capacity providers receive remuneration from
capacity mechanisms reflecting the extent to which they deliver security of
supply for the capacity mechanism zone, signals for investment will be skewed in
favour of the capacity mechanism zone and there will be less than optimal
investment in foreign capacity and in interconnector capacity. This inefficiency
will increase costs for consumers overall.
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(354) Despite the repeated acknowledgement by the European Council of the need for a
fully-functioning and interconnected energy market, cross border participation in
capacity mechanisms remains rare in practice. There may therefore be a need for
a set of principles or rules harmonising the cross-border participation of
capacities in different capacity mechanisms, including the definition of a
common product to account for the capacity to be supplied from neighbouring
markets. Such harmonized approach appears to have the potential to avoid the
complexity that might arise if individual solutions are developed for each
mechanism or border, while still allowing Member States the flexibility to design
different capacity mechanisms to address the problems that best address their
local issues.
5.3
5.3.1
Allocation Process
The role of the allocation process in capacity mechanisms
(355) This section covers the 'allocation process', used to select the capacity providers
that will receive capacity remuneration and to determine the price paid to these
beneficiaries.
(356) The capacity mechanisms covered by the sector inquiry either use an
administrative or a competitive allocation process.
(357) When an administrative allocation process is employed all the capacity providers
that meet the eligibility requirements are selected without competition and the
remuneration of capacity is set in advance by the Member State authorities or
negotiated bilaterally between the latter and the capacity provider.
(358) In a competitive allocation process, eligible capacity providers participate in a
bidding process and the capacity remuneration is the result of this process.
(359) The following sections will examine the design of the different types of allocation
processes employed and assess to what extent they prevent excessive profits
while sending the right signals for investments.
5.3.2
Findings of the sector inquiry on administrative allocation processes
(360) As illustrated in Figure 27, an administrative allocation process is employed in
price-based mechanisms, such as (market-wide and targeted) capacity payment
schemes, the interruptibility scheme in Portugal and, since 2016, in the
interruptibility scheme in Sardinia and Sicily.
(361) Moreover, an administrative procedure is in practice employed also in the
'mandatory part' of the German network reserve. While this reserve is in principle
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volume-based and the price of capacity is intended to be competitively
determined, the requested volume has so far always exceeded the offers of
eligible capacity providers. This has resulted in all eligible providers located in
Germany receiving the capacity remuneration, which is bilaterally negotiated
between the TSO and the capacity providers on the basis of a methodology
established by the regulator.
Figure
27:
Capacity mechanisms with an administrative allocation process in the
Member States covered by the sector inquiry
Source: European Commission based on replies to sector inquiry
(362) In most of these capacity mechanisms, capacity providers submit an application
to the competent Member State authority, which limits itself to verifying whether
the eligibility criteria are met and the application form is complete. The existing
Irish market-wide capacity payment mechanism grants administrative payments
systematically to all capacity providers with no need for an application process. A
similar process is followed for the operational reserve in Poland where during
peak hours on working days the capacity payment is automatically granted to all
available centrally dispatchable plants that have not secured power sales contracts
or are not dispatched by the TSO.
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5.3.2.1 Capacity price-setting in administrative allocation processes
(363) In an administrative allocation process, the level of capacity remuneration is
established ex ante by public authorities rather than being determined by market
forces.
(364) In reply to the Commission's survey, the vast majority of market participants have
argued that administratively set prices are unlikely to reveal the real value of
capacity.
(365) There is one mechanism in which the allocation process has switched from
administrative to competitive that is the Spanish interruptibility scheme. This
scheme was based on fixed payments until 2014. For each year from 2008 to
2014, the TSO disbursed 550 million EUR to procure 2,000 MW of capacity. In
2015, the TSO decided to allocate the same amount of capacity as in the previous
six years by means of an auction rather than an administrative procedure. This
resulted in a decrease in the total annual remuneration under the scheme from 550
million EUR to 353 million EUR.
(366) In Germany, the authorities plan to also switch from an administrative to a
competitive allocation mechanism for the interruptibility scheme. In order to
ensure sufficient competitive tension in the bidding process the total capacity
volume to be tendered is planned to be reduced from 3 GW to 1.5 GW.
(367) While the level of remuneration plays an important role in providing signals for
investments and ensuring that the right capacity volume is procured to meet a
certain reliability standard, only in some price-based mechanisms the level of
remuneration (or the methodology for its calculation) is explicitly and
automatically tied to the reliability standard. This is the case in the Irish market-
wide capacity payment mechanism, the Polish operational reserve and the
investment incentive mechanism in Portugal.
(368) In Ireland, the value of the annual capacity payment is determined as the product
of the required quantity of capacity (necessary to meet an adequacy standard set
for Ireland and Northern-Ireland jointly) and its cost-based price. Furthermore,
40% of the payment is calculated year-ahead, 30% month-ahead and the
remaining 30% is determined and allocated ex-post so that it reflects the actual
value of capacity in any period.
(369) Under the Polish operational reserve the hourly cap on capacity payments is tied
to a percentage (18% in 2015) of the expected demand during peak hours on
working days. Capacity remuneration is proportionally lowered if the amount of
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available operational reserve capacity exceeds the TSO's target of 18% of
expected demand in peak hours.
(370) In Portugal, the remuneration under the investment incentive mechanism is
inversely proportional to the capacity margin. This means that the remuneration
should decrease and eventually tends to zero when the capacity margin has been
exceeded so as to avoid that the capacity mechanism sends misleading signals for
investment.
(371) In Spain, according to the law establishing the investment incentive mechanism,
the remuneration should have been calculated according to a methodology which
is almost identical to the one used in the Portuguese investment incentive
mechanism. However, that methodology was never applied. Instead, the level of
remuneration was administratively set and the payment maintained (and
increased for some periods) even in times of overcapacity.
(372) Figure 28 below shows the evolution of the capacity margin in Spain for the
period 2007-2014. During the same period, the remuneration under the
investment incentives scheme was set at 20,000 EUR/MW in 2007 and at 26,000
EUR/MW in November 2011. It remained more or less stable until July 2013
when the annual payment decreased to 10,000 EUR/MW (however, the aid
granting period was doubled at the same time).
Figure 28: Evolution of the capacity margin in Spain
Source: Report on Electric System - year 2013. REE, System Operator
(373) In Spain the capacity margin (ratio between installed firm capacity and peak
demand) is set at 1.1. The figure shows that this reliability standard was exceeded
since as early as 2007. However, the mechanism continued to provide incentives
for investments in new capacity. For instance, the sector inquiry identified an
example of a new gas-fired power plant which was authorised in 2013 and will
receive the investment incentive payments for 20 years once in operation.
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(374) The remuneration for interruptibility services in Sardinia and Sicily has been set
by law as of 2016. For the period 2010-2015 the service had been tendered.
However, the poor participation in tenders resulted in the maximum allowed price
(300,000 EUR/MW/year) always being paid to service providers. On the other
hand, in the same period, the auction for similar interruptibility services in the
mainland cleared at a substantially lower price (approximately 90,000
EUR/MW/year in 2015). Italy decided therefore to use this price as benchmark to
fix the price of the islands' scheme
132
.
5.3.3
Findings of the sector inquiry on competitive allocation processes
(375) Two different types of competitive allocation processes have been identified in
the capacity mechanisms covered by the sector inquiry: central auctions133 and
de-central capacity market systems.
(376) In central auctions, the Member State's authorities determine (or ask the TSO to
determine) at the outset the capacity needed to ensure generation adequacy. This
capacity is then auctioned. The sector inquiry has also identified a capacity
mechanism in which the volume to be procured through the auction is not defined
ex ante, namely the planned central buyer mechanism in Italy.134 Auctions have
been employed mainly in strategic reserves including interruptibility schemes and
for tenders for new capacity. They are also used in central buyer mechanisms.
(377) In the de-central obligation mechanism which France is implementing, the
amount of capacity needed to ensure security of supply is not determined ex ante
but is estimated by individual suppliers (however, based on projections by the
TSO). The suppliers are under the obligation to procure from capacity providers
enough capacity certificates to cover the capacity needs of their customers,
adjusted to simulate a cold spell occurring once every ten years.135 Moreover,
the de-central French mechanism was originally supposed to be based mainly on
bilateral trading. However, the French authorities have proposed to amend the
system obliging large capacity operators (> 3 GW) to offer predetermined
volumes of certificates in different public auctions to be held on the EPEX SPOT
132
133
134
135
The level of remuneration is adjusted to take into account the specificities of the islands' scheme. For instance,
the average number of sheds over the 2010 – 2015 period was higher than in the mainland and the average
duration of the shedding events was longer.
In this report, the term 'auction' is meant to comprise different types of competitive bidding process including
also tenders.
Rather than determining a fixed amount of capacity, the planned Italian mechanism uses a sloping demand
function so that the capacity to be procured depends also on the prices of the offers in the auction.
It is important to note, however, than under the French market-wide capacity mechanisms the estimation of the
amount of capacity to be procured is not left entirely to suppliers, since the TSO determines (ex-post) the
correction factor to be applied to the total consumer demand to simulate severe winter conditions.
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exchange. Finally, France has also proposed to organise annual tenders for new
capacity.
(378) Figure 29 below provides an overview of the capacity mechanisms covered by
the sector inquiry that employ a competitive allocation process.
Figure 29: Capacity mechanisms with a competitive allocation process in the
Member States covered by the sector inquiry
Source: European Commission based on replies to sector inquiry
5.3.3.1 Capacity price-setting in competitive allocation processes
(379) The sector inquiry has identified different pricing rules in the capacity
mechanisms that employ a competitive allocation process.
Pay-as-bid and pay-as-clear rule
(380) The tenders for strategic reserves in Belgium, Denmark, Germany ('voluntary
part' of the network reserve and the planned capacity reserve), Poland (cold
contingency reserve) and Sweden employ a pay-as-bid rule, meaning that
successful bidders receive the remuneration specified in their individual bids.
(381) A pay-as-bid rule was also applied in the tender procedures carried out for the
construction and operation of new power plants in Ireland in 2003 and in France
in 2012. However, while in the Irish tender the contract was awarded solely on
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the basis of price, in the tender for new capacity in Belgium and Brittany price
was only one of the award criteria (albeit the most important one).
(382) The French de-central obligation scheme envisages both bilateral trading of
capacity certificates and public trading via a number of auctions organised every
year by the EPEXSPOT trading platform.
(383) A pay-as-clear or uniform price rule has been used in the auction in the British
central buyer mechanism and is proposed for the planned Italian and Irish central
buyer mechanisms, and under the French market-wide mechanism (EPEX SPOT
auctions). In this type of auction, successful bidders all receive capacity
remuneration equal to the marginal price in the auction (i.e. the most expensive
unit that was successful). This means each MW of capacity will receive the same
remuneration level at the end of the bidding process.
Price caps and price floors
(384) Existing and planned capacity mechanisms covered by the sector inquiry often
include (implicit or explicit) price caps or price floors. For instance price caps are
used in the German interruptibility scheme, the German capacity reserve, the
Italian auctions for the procurement of interruptible load and in the planned
Italian and Irish central buyer mechanism. In the latter two, it is expected that a
price cap will be set at the level of the fixed costs of new entrant i.e. the
generation technology with the lowest fixed costs. In the British capacity
mechanism, the price cap was set at 75,000 GBP/MW.
(385) The French market-wide mechanism, the Belgian strategic reserve and the Polish
cold contingency reserve employ an 'implicit' price cap. In the French capacity
mechanism, an implicit price ceiling applies through the cap on capacity
imbalance settlement prices; the cap is set to increase gradually and is meant to
eventually reflect the cost of new entry. In Belgium, the national regulatory
authority has the power to review the level of the remuneration if it considers bids
manifestly unreasonable. In Poland, the 2013 tender for the cold contingency
reserve was not successful in procuring the amount of capacity requested because
some of the bids exceeded the TSO's projected budget. A second tender
procedure in 2014 managed to procure the remainder of the capacity because the
bids were substantially lower than in the 2013 procedure.
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(386) In the interruptibility scheme for Sardinia and Sicily, since the tender was
undersubscribed
136
, all participants bade at the price cap and received the
maximum remuneration. This has led Italy to switch from a competitive to an
administrative allocation process for that scheme and to reduce the amounts to be
procured. These changes will result in considerable savings for the system.
(387) In Spain, the first auction for 2,000 MW of interruptible load in 2015 was
followed by an extraordinary auction for an additional 1,020 MW of interruptible
load although the service had never been used in the previous six years. The total
budget allocated for the services was 550 million EUR. While, as mentioned
above, the first auction had succeeded in substantially reducing the cost, with the
second auction costs increased to a level close to the total budget available (508
million EUR). Conversely, competition in the two British capacity auctions held
to date pushed the clearing price (19.40 GBP/kW/year in 2014 and 18
GBP/kW/year in 2015) substantially below the price cap, set at 75
GBP/kW/year.
137
(388) A price floor is only envisaged in the Italian central buyer mechanism. According
to the Italian authorities, the price floor will enable the capacity mechanism to
support new investment without the need for long contracts. The premium would
be paid to all existing capacity that participates in the auction, even if it is in
excess of the demanded capacity.
5.3.4
Issues encountered in relation to allocation processes
(389) The choice of the allocation process and its design impact the level of capacity
prices and their transparency. These are crucial to ensure that a capacity
mechanism sends the appropriate and clear signals for investments. The
following sections examine the issues identified in this respect.
136
137
For instance, in 2015, interruptible power contracted under the mechanism amounted to 163 MW in Sardinia and
156 MW in Sicily falling significantly short of the desired target of 500 MW per island.
See National Grid, Final Auction Results, T-4 Capacity Market Auction 2014, available at:
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%202014%20Final%20Auction%20Results%20Report.pdf;
and National Grid, Final Auction Results, T-4
Capacity Market Auction for 2019/2020, available at:
https://www.emrdeliverybody.com/Capacity%20Markets%20Document%20Library/T-
4%20Final%20Results%202015.pdf
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5.3.4.1 Competitive allocation processes are better at revealing the real value of
capacity
(390) The sector inquiry revealed that the remuneration granted through a competitive
allocation process is more likely to correspond to the real value of capacity than
where an administrative allocation processes is applied.
(391) This conclusion is supported by a vast majority of market participants from
Member States with capacity payment mechanisms. For instance, none of the
market participants in Spain believe that the level of the remuneration is
appropriate in the various price-based schemes. A large majority of market
participants in Italy, Portugal and Spain are of the view that the current level of
remuneration under the respective capacity payment mechanisms is too low to
cover the costs of availability or, in the case of the Portuguese investment
incentives mechanism, to recoup the investments for the construction or
refurbishment of hydro power plants that the scheme obliges them to undertake.
(392) In capacity payment mechanisms the remuneration is spread over a large number
of – in some case all – operators, whereas in an auction the remuneration is
granted only to those that are needed to address the estimated capacity shortage.
For instance, a number of Italian respondents also noted that although the
capacity payment is paid to all eligible capacity providers, the majority of those
are never or very rarely called upon to provide their services in situation of
system tightness, either because of their location or because of the type of
capacity they could supply.
(393) In case the remuneration is lower than the real value of capacity the capacity
mechanism will not provide adequate incentives for investments and will thus be
ineffective. In that case, the capacity mechanism may not deliver value for money
as it will not meet the security of supply objective.
(394) However, an administrative allocation process can also set the price at a level that
is too high. This was the case for the Spanish interruptibility scheme, where the
price per MW of interruptible capacity decreased considerably when the
allocation process changed from a fixed remuneration determined ex-ante to a
competitive auction.
(395) The risk of administratively determining a level of remuneration that is either too
high or too low does not normally occur in competitive allocation processes
because the remuneration is based on bids received from market participants that
indicate the value they place on delivering the requested service. However, as
underlined in the next paragraph, competitive processes need to be well-designed
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in order to indeed produce a remuneration that reflects the true value of the
capacity.
5.3.4.2 The use of a competitive allocation process will not always guarantee
competition
(396) Market power can allow capacity providers to withhold capacity or inflate prices
in the allocation process. For instance, in the absence of sufficient competition or
regulatory oversight, an operator that owns a large fleet of power plants could
withdraw some plants from the process to increase competition and the chances
of setting higher prices for the plants that it does include in the process. Note
strategic withholding is also a risk in electricity markets – it is not a risk unique to
capacity mechanisms.
(397) In the auctions held under the interruptible load scheme in Sardinia and Sicily
and the second auction held under the Spanish interruptibility mechanisms only
few market participants were able to deliver the requested capacity. Those market
participants could therefore exercise market power in the auction by bidding
close to the price cap (or maximum available budget in the case of Spain).
Conversely, the two auctions held so far in the British mechanism demonstrate
that when there is strong competitive tension in the allocation process prices can
be much lower than the price cap.
(398) These examples also show the importance of the design of the competitive
allocation process in ensuring that capacity is procured at the lowest cost for the
community. This is not the case, for instance, when the amount of capacity to be
procured has been overestimated or when the price cap is set at a very high level
and there is insufficient competition to determine the right price of capacity.
However, the history of the interruptibility scheme for Sardinia and Sicily shows
that in some (exceptional) circumstances, it is not possible to design the
allocation process in a way that maximises competition. In those circumstances,
an administrative allocation process may be more effective at procuring the
service at the lowest cost for the system.
(399) The issue of market power is even more prominent in de-central allocation
systems when these are implemented in a market with a highly concentrated
generation segment. Those mechanisms strongly rely on de-central capacity
forecasting and trading. Therefore, more established players will normally have
an advantage over their competitors as a result of asymmetric market information.
(400) These effects could be partially mitigated by the introduction of mandatory
exchange trading in the de-central mechanism. However, only by opening
participation to the mechanism as much as possible to new entrants, foreign
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generation and demand response it can be ensured that competitive pressure is put
on the incumbent and that the price of capacity would be the result of competitive
market forces. These considerations are valid also for central buyer mechanisms
that operate in highly concentrated markets.
(401) When market power exists and it is not possible to extend participation in the
mechanisms –due for instance to the poor development of the electricity network
or of demand response– an administrative allocation process can be justified with
a view to minimise the costs of the system. According to market participant
respondents, this logic inspired the German authorities when designing the
allocation of the mandatory part of the network reserve.
5.3.4.3 An allocation process that does not identify the real value of capacity
sends misleading signals for market entry and market exit
(402) An allocation process that does not reveal the real value of capacity is unlikely to
send the proper signals for market entry or market exit.
(403) On the one hand, it can result in artificially keeping existing capacity in the
market or even in developing new capacity in situations of overcapacity. This is
for instance the case in the Spanish investment incentive mechanism which has
incentivised the commissioning of new generation even after the capacity margin
had been substantially exceeded. Price floors are in practice similar to
administratively set capacity prices and entail the same risks. In the planned
Italian central buyer mechanism, the price floor would be paid to all existing
capacity, even if offered in excess of the amount requested by the TSO. This
capacity is therefore artificially kept in the market. Moreover, as with capacity
payments, price floors prevent the capacity price from tending automatically to
zero in case of overcapacity.
(404) A low level of capacity remuneration set by a competitive process should be a
reliable signal that there is excess capacity that should close. However, if a low
level of remuneration is set administratively, it may not provide adequate
incentives for keeping plants in the market or for new capacity to enter the
market. The vast majority of respondents in the country where a capacity
payments mechanism has been established are of the view that the remuneration
provided under the mechanism is not sufficient to trigger investments in new
generation capacity. Moreover, the vast majority of market participants in Spain
believe that the level of remuneration under the availability incentive scheme is
not sufficient to recover the costs needed to keep the plants in the market.
(405) Linking the level of remuneration to a reliability standard, as in the Portuguese
investment incentive mechanism, can avoid the capacity mechanism sending
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misleading signals at times of overcapacity, provided that the adequacy standard
has been properly defined and the remuneration is amended accordingly.
However, the implementation of this solution does not address the issues that
arise from not having allowed the level of capacity remuneration to be
determined in a competitive manner in the first place.
5.3.4.4 Non-transparent capacity prices can negatively affect investment signals
and competition
(406) A low level of transparency characterises those capacity mechanisms where the
level of capacity remuneration is mainly bilaterally agreed, such as the French de-
central obligation scheme, as originally designed.
138
This lack of transparency can
affect investment signals. Some French market participants expressed this view.
(407) Furthermore, bilateral trading can lead to discriminatory treatment of different
capacity providers. The bilateral trading of certificates in the initial conception of
the French capacity mechanism could have favoured vertically integrated
operators, which can rely on intra-group trading to meet the supplier obligation.
There was in particular a risk that they applied more advantageous conditions to
their supply branch than to other suppliers. This view was supported by several
market participants.
(408) The mandatory auctioning of (specified volumes of) certificates on a public
exchange, as proposed by the French authorities, can minimise this risk by (i)
creating more transparency on the capacity price, (ii) increasing liquidity in the
capacity market and (iii) avoiding market manipulation by the dominant capacity
providers. Moreover, the exchange auctions' price will be used to set a cap for the
tender processes for new capacity.
(409) In Belgium market participants are concerned that the non-transparent criteria
used by the regulator to revise offers in the strategic reserve will create
uncertainty for companies as regards their expected revenues, in particular if
investments are needed.
5.3.5
Conclusions on allocation processes
(410) In Member States covered by the sector inquiry, all the new schemes that are
currently being implemented or planned to be implemented with a reasonable
138
This was one of the arguments leading the European Commission to open in-depth investigations into the
mechanism.
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degree of certainty include a competitive price-setting process
139.
This is case for
instance in France, Ireland, and Italy. Moreover, Ireland and Italy are moving
from an administrative to a competitive allocation process.
(411) A properly designed competitive allocation process minimises the costs of the
capacity mechanism, as long as its design ensures competitive pressure and
prevents the exercise of market power. This can best be achieved by allowing
many different existing and new capacity providers to compete. Besides the
allocation process design, eligibility criteria and capacity product features play a
crucial role in this respect as they explicitly or implicitly influence the number of
capacity providers that can take part in the process (see Sections 0 and 0
respectively).
(412) The implementation of a decentralised allocation process in a highly concentrated
market with vertically integrated undertakings is more prone to the exercise of
market power than a central buyer mechanism it allows the dominant vertically
integrated undertakings to discriminate against their competitors. Specific rules
may be required to prevent the exercise of market power and abuse of dominance.
(413) A competitive allocation process is more likely to reveal the real value of
capacity and therefore to send adequate signals for market entry and market exit,
as long as prices are transparently set.
(414) In general, respondents to the public consultation supported these conclusions
and pointed to the risk of over procurement and overcompensation when
administrative processes are employed.
5.4
5.4.1
The capacity product: obligations and penalties
Capacity products
(415) Once Member States have selected the capacity providers that could contribute to
addressing the identified adequacy problem, they need to design the most suitable
'capacity product' to achieve that aim. In other words, they need to develop the
rules determining what exactly capacity providers are required to do in the
capacity mechanism in return for receiving capacity remuneration (their
'obligation'), and what happens if they fail to do what they are required to do
(usually a 'penalty' of some kind). These obligations and penalties are important
to provide an 'incentive effect' on the capacity providers benefitting from capacity
139
The new Spanish support scheme for plants burning domestic coal should employ an administrative allocation
process. However, it is not yet clear whether Spain will implement this mechanism.
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remuneration, and ensure that they deliver secure and reliable supplies to
consumers.
(416) If Member States fail to design a capacity product to correspond to the specific
generation adequacy problem identified, the capacity mechanism will be unable
to attain its objective, or it will only be able to attain it at unnecessarily high
costs. The latter would for instance be the case where ill-designed capacity
products have the effect of unnecessarily restricting participation to the
mechanism.
(417) In view of the importance of capacity product design for the appropriateness of
capacity mechanisms, this section provides an overview of the obligations and
penalties found in the capacity mechanisms included in the inquiry and seeks to
identify the impacts that they have.
5.4.2
Findings of the sector inquiry
(418) All of the capacity mechanisms covered by the inquiry include some kind of
obligation to ensure the recipients of capacity payments do something to
contribute to security of electricity supply. However, these range from a very
basic obligation to build and operate a power station, through obligations linked
to fulfilling instructions from the TSO (e.g. turn on and generate), to more
complex obligations (e.g. reliability options requiring financial paybacks when a
strike price is exceeded by a reference price). There is also a wide range of
penalties. Some mechanisms simply exclude capacity providers from receiving
future payments if they fail to meet their obligations, but most require capacity
providers to return the payments earned or even pay an additional penalty on top
of this.
5.4.2.1 Obligations
(419) To some extent the design of the capacity product depends on the type of capacity
mechanism, but there are various common features of the obligations imposed on
capacity providers.
Period of obligation
(420) Some capacity mechanisms require capacity providers to fulfil obligations all
year round whenever needed, as in the German network reserve or the British
capacity mechanism. Others only require capacity to fulfil obligations during the
winter when electricity demand is generally highest. In the Swedish strategic
reserve, capacity must be available between 16 November and 15 March each
winter. In Italy the TSO defines the 'critical days' during which capacity providers
must be available in advance of each delivery year. In France, the obligation is
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even more limited, since capacity providers are only obliged to make their
capacity available in specific hours where demand is highest. These hours can
take place in a maximum of 25 days a year, and are announced day ahead by the
TSO.
Nature of obligation
(421) In strategic reserves the obligation for participating capacity providers is
normally to deliver electricity when instructed by the system operator by
generating electricity or reducing demand. And the initial trigger event for the
system operator to do this is often the day-ahead market not clearing.
(422) In the proposed French de-central obligation scheme certified capacity providers
must ensure they make their capacity available in peak demand hours, and
suppliers must ensure their demand in these hours is either reduced or covered by
capacity certificates.
(423) In the schemes proposed for Ireland and Italy, the capacity product is a reliability
option. The capacity provider will receive a regular payment (in the Italian and
Irish sytems, the clearing price set in the relevant capacity auction). In return for
this regular payment, the capacity provider that has sold a reliability option will
be required to pay the difference between a market reference price and a strike
price whenever the reference price goes above the strike price.
Figure 30: Overview of reliability option
Source: Commission for Energy Regulation (Ireland) and Utility Regulator (Northern Ireland)
(424) A reliability option does not in itself create a direct obligation for the capacity
provider having sold the option to do anything particular in the electricity market.
However, the potential paybacks under the option mean the capacity provider has
a strong incentive to make sure he sells electricity at the reference price so that he
has revenues to make any required contract paybacks. The extent to which a
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reliability option product provides incentives for flexibility depends on the
reference market chosen for the option contract, and the ability of this market to
signal scarcity. The reliability option capacity product also allows consumers to
be protected from potential high electricity prices at times of scarcity, since all
capacity contracted in a capacity mechanism with a reliability option product will
have to payback any excess revenues from the sale of obligated capacity above
the reliability option strike price.
(425) In Italy, the reference market is a basket of the day-ahead and ancillary services
markets. In addition to the payback requirement of the reliability option,
participants will also be obliged to place bids in the day-ahead market for 100%
of their contracted capacity. Any contracted capacity not taken in the day-ahead
market must then be bid into the ancillary services market. This is designed to
enable a reference to the ancillary services market which should provide better
signals of scarcity than the day-ahead market, while ensuring the day-ahead
market remains liquid.
140
(426) In the 2003 Irish tender capacity mechanism, selected generators were granted
Capacity and Differences Agreements (CADA). These function in a similar way
to reliability options, since when the market price is superior to the strike price
defined in the CADA the beneficiaries must reimburse the difference between the
market reference price and the strike price.
(427) In the French tender for new capacity in Brittany, the premium paid to the
beneficiary for being available is fixed and revenues generated from the sale of
electricity on the market are not taken into account.
Notice period
(428) The definition of a capacity mechanism obligation often features a warning or
notice period so that capacity providers have a clear signal to start warming up
ready to deliver electricity when they are needed. In strategic reserves (for
example in the existing Belgian, Polish and Swedish schemes and the on hold
Danish scheme), participants are obliged to run when instructed to do so by the
system operator, but receive a varying notice period. In Poland contracted plants
must be able to start generating their full output within maximum 17 hours; in
Sweden within 16 hours (while demand response receives 30 minutes' notice); in
140
Without the obligation to bid day ahead, participants may withhold their capacity until closer to real time to try
and ensure they have sold sufficient electricity at the reference price that they can afford to make any required
paybacks.
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Denmark within 10 hours; and in Belgium normally within 6.5 hours
141
(while
demand response receives 8 hours' notice).
(429) In market wide mechanisms it is not necessary to have a central notice period and
in some designs participants are required to react to market forces. This is for
instance the case in the planned mechanisms in Ireland and Italy where
participants will simply have to repay the difference between the market
reference price and the reliability option strike price whenever the reference price
exceeds the strike price. This means they have to judge for themselves the risk of
high reference prices and be warmed up and ready to deliver when necessary. By
contrast, a notice period is included in the French capacity mechanism: the hours
during which generators and demand response operators should be available are
communicated by the TSO day-ahead.
Limitations on use
(430) A capacity product could simply oblige all remunerated capacity to be provided
whenever needed and for as long as needed at any time throughout the period of
obligation (e.g. the year or the winter). This is, for instance the case for the
Portuguese availability incentive mechanisms. However, many designs include
limitations on the number of times a resource can be called, and/or the duration
for which a resource may have to provide its capacity continuously. In the Polish
strategic reserve for example, the system operator can only require capacity
providers to start from cold a maximum of 5 times per week, and resources are
only obliged to provide power for a maximum of 8 hours per day. There are also
maximum activation durations in the Belgian strategic reserve. In the Italian
targeted capacity payment mechanism, capacity providers are required to be
available only during 'critical days' defined in advance by the TSO. There are also
often different rules specific for demand response (see sub-section 5.4.3.2).
Testing
(431) Most capacity mechanisms include the potential for testing by the system
operator to ensure that contracted resources are actually capable of meeting their
obligations even in years when there are no periods where obligations apply. This
can be performed as a precondition for participation to the mechanism, and while
the mechanism is in place, to test that the selected providers remain able to meet
their obligations.
141
This is the maximum time allowed by the TSO, but justified deviations may be possible.
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(432) The testing of capacities during the capacity mechanism is for instance done in
the French de-central obligation scheme, the Spanish interruptibility scheme and
the Portuguese availability payments scheme. Demand response providers
replying to the sector inquiry also insisted on the barrier to entry that could be
created by excessive testing of demand reduction capacity. They argue that the
impact of testing the availability of power plants is not comparable to that of
testing demand reduction services, since in the latter case effective demand
curtailment is required.
New projects
(433) Capacity mechanisms can also include penalties and/or require collateral related
to the building of new capacity on time. In the French de-central obligation
scheme, for example, new demand response capacity must deposit a bank
guarantee in order to be certified. In Brittany, if the beneficiary does not make the
plant operational on time, penalties apply. In the planned Irish scheme, a range of
physical and financial requirements for bidders intending to develop new capacity
are being considered, in view of the risk that they fail to deliver or bid without a
firm intention to actually make the capacity available. Possible requirements are
the need to demonstrate that the plant can connect to the grid in time, that it has
the necessary planning consents, a sound business plan and a sufficient level of
creditworthiness.
5.4.2.2 Penalties
(434) Once the capacity obligation has been defined, to ensure capacity providers have
incentives to meet their obligations it may also be necessary to design penalties
that will apply if the obligation is not fulfilled. These can be implicit penalties –
for instance the need to pay back the difference between the strike price and the
reference price in mechanisms where the product is a reliability option – or
explicit penalties which can be charged in case the obligation is not met.
142
(435) Generally, in the Member States that apply explicit penalties, it is rare for
participants to be able to lose 100% of the remuneration they receive from the
various schemes. There are however some exceptions.
(436) In the Spanish 'availability incentive' capacity payments scheme, beneficiaries
can lose up to 75% of payments through penalties, and will be ineligible for
142
There can even be positive incentives, which allow for an extra payment on top of electricity revenues and the
capacity payment. This can be a useful way to correct for any inaccuracy in the intial 'de-rating' applied to a
capacity provider, since penalties and extra payments can adjust the overall level of capacity remuneration a
capacity provider receives based on their actual performance.
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future years if less than 60% of remunerated capacity was available on average
over the previous year. By contrast, in both of the Portuguese capacity payment
schemes, plants that are available less than 70% of the time will lose their entire
remuneration and providers that consistently fail to meet their obligations can
eventually be excluded from the mechanism.
(437) Also in the on hold Danish strategic reserve capacity providers that consistently
failed to meet their obligation could have lost 100% of the remuneration they
received from the scheme through penalties. Providers could also have lost more
than this since they potentially faced imbalance penalties on top of their capacity
mechanism penalties if they did not deliver their contracted strategic reserve
when called by the TSO.
(438) In the French de-central obligation mechanism, a capacity imbalance settlement
mechanism is used to incentivise capacity providers and suppliers to fulfil their
obligations. For the imbalance settlement, the volume of imbalances per capacity
provider/supplier is multiplied by the reference capacity price, increased (in case
of negative imbalances) or decreased (in case of positive imbalances) by a
correction coefficient meant to disincentive imbalances. In case there is a
structural negative imbalance of capacities (exceeding 2 GW overall), an
administrative reference price (in essence a penalty) is applied to all negative
imbalances. This price is intended eventually to reflect the CONE of an OCGT.
(439) In the planned Italian central buyer mechanism, capacity providers face a number
of penalties for failure to make bids in the reference markets corresponding to the
whole of their contracted capacity. In addition to paying the difference between
the reliability option reference price and strike price, they will not receive the
capacity payment for the whole month in which they did not fulfil their bidding
obligation. Furthermore, in case of a prolonged failure to meet the bidding
obligation, capacity providers will have to pay back capacity premiums already
received. Additional penalties apply if beneficiaries fail to pay back the
difference between the strike price and the reference price. This means that
capacity providers could face penalties that are potentially much higher than the
total capacity remuneration received.
(440) In almost all of the Member States included in the sector inquiry that apply
explicit penalties, these do not appear to be linked to VOLL or CONE. The only
exceptions are Italy, where the value of lost load has been identified to be 3,000
EUR/MWh and the reference price could potentially rise to this level, and the
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new French mechanism, where the penalty for capacity certificates imbalance
will rise to CONE.
143
Bridging the gap between the auction and delivery period
(441) Where auctions are held many years in advance of the delivery period, there is a
bigger risk that plants fail to remain in the market to deliver their obligations
because market circumstances can change. In Britain, wholesale prices and clean
spark and particularly dark spreads deteriorated to such extent in the period
between the first T-4 auction and delivery year, that capacity having secured
contracts in the first T-4 auction nevertheless decided to close, since their
expected losses (sometimes greatly) exceeded the non-delivery penalties they
faced. This in turn led the UK authorities to substantially revise its penalty regime
upwards. These closures risk higher costs for consumers where replacement
capacity has to be procured in a tighter market with a shorter lead time.
Thisexperience illustrates the importance of sufficient deterrents to non-delivery.
Allowable exceptions
(442) Penalties could be applied immediately and for any lack of delivery against the
obligation. However, there are usually exceptions to the obligation that reduce
risk for capacity providers.
(443) The on hold strategic reserve in Denmark would not have imposed penalties so
long as at least 85% of the capacity called by the system operator was delivered
(though electricity imbalance settlement penalties would still have applied).
Under the Spanish 'availability incentive', capacity providers only need to prove
that 90% of the capacity receiving availability payments was available in peak
periods.
(444) In Poland, capacity providers in the strategic reserve are allowed up to 1440
hours of planned outages in every two consecutive years, and up to 360 hours of
unplanned outages each year before any penalties are due. In the Swedish
strategic reserve, generation capacity providers in the strategic reserve must be
available for at least 95% of winter hours to avoid penalties. Similarly in Brittany
the new plant needs to be available for 95% of the time, whereas in the
abandoned Belgian tender an 80% availability during winter was required. In the
on hold Danish strategic reserve, capacity providers would have to be available
for 90% of overall hours in a year.
143
Note in reliability option schemes the penalty would be linked to VOLL if the introduction of the capacity
mechanism was accompanied by market reforms allowing the reference price to rise to VOLL.
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(445) Note in many schemes aspects of obligation design already effectively build in
exceptions before penalties apply – for example the notice period and limitations
on use (see section 5.4.2.1 above).
5.4.2.3 Reform of capacity products in the United States
(446) The capacity mechanisms in PJM and ISO New England, which each include a
market wide central buyer capacity mechanism, have both had the design of their
obligations and penalties overhauled recently in response to lessons learned
during the 2013-2014 'polar vortex'.
(447) During the polar vortex a large proportion of contracted capacity was not actually
able to deliver when it was needed because of a lack of firm fuel supplies or
failures to operate due to the cold weather. It was found that in some cases
contracted resources preferred to pay non-performance penalties than expensive
fuel supplies.
144
Since these events, the capacity products in both ISO-NE and
PJM have been reformed so that there are much stronger signals for delivery
("pay for performance") of contracted capacity when it is needed.
5.4.3
Issues identified
5.4.3.1 Strong penalties help ensure security of supply and simplify other aspects
of mechanism design, and do not necessarily increase the total system cost
(448) Capacity product design involves many complex detailed choices, and all of these
combine to determine the level of security of supply it provides. As respondents
to the consultation noted, capacity providers failing to meet their obligations
should face 'market-based' penalties, or face exposure to a market price.
Particularly as markets are reformed and market design ensures that scarcity is
reflected in electricity prices, exposure to the market price would mean that
capacity providers 'penalties' would reflect the costs to consumers of the failure to
meet the capacity obligation. In the absence of reformed market prices, or while
reforms are underway, penalties linked to VOLL are required to provide a
similarly strong incentive. Respondents also noted that more stringent penalties
can reduce the administrative complexity of a mechanism because they reduce
the importance of pre-qualification and physical checking.
(449) However, some consultation respondents also noted the need to ensure penalties
did not reduce participation or inflate the costs of procuring capacity. Capacity
product design can be tweaked in many ways to adjust the level of risk faced by
144
See:
http://www.ausenergy.com/2014/02/the-illusion-of-reliability-ne-isos-capacity-market/
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capacity providers. Notice periods, caps on use and allowances for maintenance
can all reduce the risks of participation, but they will tend to reduce the security
of supply provided by the capacity mechanism.
(450) Where the problem the capacity mechanism is targeting is clearly seasonal or
linked to a problem that only occurs in specific hours, a shorter obligation period
may be appropriate to reduce barriers to and risks of participation, and therefore
reduce costs
145
. A more limited obligation period should also reduce the need for
any exemptions related to the obligation, for example due to maintenance, since
beneficiaries should be able to schedule planned maintenance outside the
obligation period.
(451) Any reduced security of supply from more lenient capacity product design must
be considered against the potential risk and cost reduction for capacity providers,
and potential increased participation and therefore competition in the mechanism
which could reduce its costs. However, it is also important to bear in mind that
more limited capacity mechanism obligations may mean that more ancillary
services or additional measures are needed to ensure security of supply, alongside
the capacity mechanism. The whole system cost must therefore be considered.
5.4.3.2 Capacity products risk to distort electricity prices causing overcapacity
(452) Capacity mechanisms usually have a close link with electricity prices, since
electricity prices rise to provide a signal that there is scarcity in the market and it
is at these times that the capacity contracted through the capacity mechanism is
needed most.
(453) Once capacity mechanisms are introduced they will – in most cases – reduce the
extent to which local electricity prices remunerate capacity. Capacity will be fully
or partially rewarded separately through capacity remuneration. Most aspects of
capacity product design will not impact on cross border electricity market
functioning, but if a capacity product includes an obligation that: i) pays or
penalises capacity providers on the basis of capacity delivered
(payments/penalties per MWh); or ii) that introduces a price cap in the market,
then there is a greater risk of distortions to market functioning.
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A particularly time-limited obligation like that chosen in France and Italy can also increase
participation, particularly by demand response providers which may struggle to provide capacity over
longer durations.
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(454) Implicit market price caps could for example potentially be set by a
reliuncloearability option strike price that leaves no incentives for bidding above
that level. However, any capacity able to bid exceed its capacity mechanism
obligations in a particular period – for example by generating more than the de-
rated capacity for which it sold reliability options – would still be able to set
higher prices than the strike price.
(455) Where capacity penalties provide an incentive for the delivery of required
electricity when needed, these penalty signals may be considered to replace the
signals the electricity market would otherwise need to provide for delivery of
electricity at the right times. However, if a capacity mechanism acts as a
replacement for high electricity prices at times of scarcity, there will not be an
efficient signal for imports to the Member State having implemented that
capacity mechanism at times of need. Nor will there be an efficient incentive for
demand response participation in the electricity market outside the capacity
mechanism.
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Box 3: The 'slippery slope' effect
A strategic reserve that is dispatched before possibilities for the market to match supply
and demand have been fully tested can also act as a cap on market prices. This risk can
be avoided by dispatching the reserve only when the market has failed to clear despite
prices reaching an appropriate wholesale market price cap. This should still enable
capacity providers outside the reserve to receive scarcity prices and therefore enable
peaking plants to earn their fixed costs. If the reserve is dispatched more frequently or if
in times when the reserve is dispatched the market price is not set to the cap, then the
reserve will have created additional missing money by reducing the possibility of high
market prices.
Where missing money remains in the electricity market and is only corrected for
beneficiaries of the reserve, there is the potential for a strategic reserve to become bigger
and bigger as more plants close or threaten to close unless they are included in the
strategic reserve (sometimes called the slippery slope effect). This effect seems to have
occurred in Belgium where for winter 2014-2015 the government initially mandated the
TSO to contract 800 MW of strategic reserve, which was already four months later
increased to 1,200 MW
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, while for winter 2015-2016 the government mandated the
TSO to contract a reserve totalling 3,500 MW (i.e. 23.8% of total operational installed
capacity in Belgium in 2014)
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. Also the German Network Reserve increased from an
initial 1.4 GW in 2012/2013 to 4.8 GW for the winter of 2015/2016.
In Sweden, the reserve has actually become smaller over time – shrinking from 2 GW to
1 GW. However, it has not so far proved to be a transitional intervention. The reserve
was introduced in 2003 and is still in place in spite of plans to phase it out. In 2015, the
public authorities have announced to extend its duration once more from 2020 to 2025.
A linked problem identified for tender mechanisms is the 'wait for tender' issue, where
potential investors may prefer to wait for a tender to be launched than invest in the
market.
(456) Given the importance of electricity prices as a signal for efficient electricity
imports and exports within the Single Market, where capacity mechanism
penalties replace electricity scarcity prices fewer imports at times of scarcity
would be expected than would otherwise have been the case. This risks creating
an additional distortion since where fewer imports are expected additional
domestic capacity will need to be procured through the capacity mechanism.
Ultimately this would mean capacity mechanisms lead to too much capacity
being procured and mean the full benefits of the Single Market would be missed.
146
147
A total of 850 MW, consisting of 750 MW of generation reserves and 100 MW of demand response reserves,
was finally contracted.
In reality only 1535.5 MW, consisting of 1177.1 MW of generation reserves and 358.4 MW of demand response
reserves, could be contracted. Note that for Winter 2016/2017 the size of the Strategic Reserve was decreased to
750MW given the improved generation adequacy situation due to the increased availability and the prolongation
of the lifetime of the nuclear power plants in Belgium.
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(457) The risk of distortions can be reduced by ensuring that the electricity market
continues to function effectively – including by sending the right signals for short
term dispatch (and to a large extent therefore also for investment in flexibility) –
regardless of the introduction of a capacity mechanism. As underlined in Chapter
2, it is important to realize the necessary reforms to the electricity market that
enable these short term signals.
(458) The capacity product too will need to be designed carefully to coexist with high
electricity scarcity prices and avoid taking too much of the scarcity signal out of
the electricity price (and yet also to ensure an incentive effect on capacity
providers).
5.4.3.3 Benefits of reliability options
(459) The reliability option capacity product can be particularly valuable for coexisting
with high electricity scarcity prices because it leaves market signals intact and
once scarcity pricing is implemented does not require an additional penalty for
non-delivery to be provided through the capacity mechanism.
(460) An additional benefit of the reliability option product is the hedge it provides
consumers. Because paybacks are required to be made by capacity providers
whenever electricity prices rise above the reliability option strike price, capacity
providers cannot earn windfalls from a combination of capacity remuneration and
electricity scarcity prices. This can be particularly valuable where the capacity
mechanism offeres long commitment periods – over which it is difficult to
anticipate electricity revenues. This protection could also help enable a capacity
mechanism to limit opportunities for the abuse of market power in the electricity
market because if prices are inflated above the strike price then paybacks will be
required from capacity providers. These features of reliability options can help
give policy makers the confidence to implement market reforms that enable
appropriate scarcity pricing alongside the introduction of the capacity
mechanism.
5.4.3.4 Specific products for demand response
(461) Demand response is often treated differently to generation within the various
mechanisms included in the sector inquiry, for example because it is not always
possible for demand response to bid in the electricity market and earn electricity
revenues in the same way as a generator, and because of the need to establish a
consumption baseline from which to measure the amount of energy delivered by
demand response capacity.
(462) There are also often limitations on the obligations for demand response, for
example a more limited number of required consecutive hours of capacity
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delivery
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. Some consultation respondents pointed out that such discrimination
should always be avoided, since preferential rules for demand response may
mean demand response is selected for support in capacity mechanisms ahead of
more competitive generation. However, these differences may be justified since
they help support the development of demand response and should allow it to
play an increasingly significant role in the electricity markets of the future. This
discrimination in favour of demand response in particular may be justifiable
because it is a lack of demand response that contributes to the market failures
targeted by a capacity mechanism. By targeting the long term development of
demand response, a capacity mechanism can therefore help to ensure the market
develops so that the mechanism is not required in the longer term. However, any
different treatment between capacity providers needs to be carefully considered to
avoid any unjustifiable discrimination.
(463) The sector inquiry has furthermore revealed that certain types of capacity
mechanism may face very specific challenges to optimise full demand response
participation, by reason of their set-up. As such, the supplier obligation developed
in France required specific design solutions to accommodate two different types
of demand response participation: implicit and explicit participation. The former
refers to the reduction of the supplier obligation through "management" of –
mostly residential and SME – demand by electricity suppliers, whereas the latter
refers to the direct participation of large industrial users and demand response
aggregators to the mechanism, often through the certification of their capacity.
Since the French authorities specifically wanted to encourage also implicit
demand response participation, the availability obligation for both types of
demand response differed.
(464) Finally, in Member States where interruptibility schemes – capacity mechanisms
that limit participation to DSR only – are in force, these often co-exist alongside
other, more open capacity mechanisms, such as market-wide capacity
mechanisms (France, Italy) or strategic reserves (Germany). These other
mechanisms may equally be open to DSR, giving demand response operators the
choice to participate in either one of the schemes. For instance, an interruptibility
scheme may be dispatched on a regular basis, whereas a strategic reserve is only
dispatched in exceptional scarcity situations; depending on the business in which
the consumer is involved it may opt for one or the other mechanism. Where the
capacity product obligation in an interruptibility scheme does not overlap with
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Testing rules may also need to differ to ensure that demand response is not disadvantaged (though it
will be important to ensure that testing is sufficient to deliver confidence that all contracted resources
will be there in the hours they are needed).
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the capacity product obligation in a market-wide mechanism, operators should be
able to offer their capacity in both schemes. However, as an integrated approach
is generally better because it increases competition, a proper assessment of the
impacts of the simultaneous existence of more than one mechanism should be
carried out.
5.4.4
Conclusions
(465) Capacity product design involves a trade off between the level of security of
supply achieved and the cost of the capacity mechanism. But whole system costs
should be considered when making this trade off because lenient capacity
mechanism obligations and penalties may increase the cost of ancillary services,
or mean other interventions are required, to ensure security of supply.
(466) Obligations requiring the verifiable availability or delivery of capacity resources
in (potential) scarcity situations are necessary to encourage investment in
sufficiently flexible and reliable capacity.
(467) Unless these obligations are backed by penalties in which it is possible to lose at
least as much as you gain from the capacity mechanisms, there may be an
insufficient incentive. Testing may also be required if the use of the capacity
mechanism is expected to be limited to very occasional situations.
(468) There is a potential tension between capacity mechanism penalties and electricity
scarcity prices, since both provide incentives for investment in flexible capacity,
and the overall incentive for flexibility should not be more than VOLL. The
design of the capacity product should ensure the majority of signals for flexibility
remain in the (increasingly reformed) electricity market, so that the electricity
market provides efficient signals for electricity imports and demand response
even once a capacity mechanism has been introduced.
(469) The reliability option product can be particularly useful in this regard since it
leaves market signals intact and once scarcity pricing is implemented does not
require an additional penalty for non-delivery to be provided through the capacity
mechanism.
(470) Reliability option capacity products also protect against the potential for capacity
providers to be overcompensated from a combination of capacity payments and
electricity market revenues.
(471) In the mechanisms that include demand response there are usually different
obligations for demand response than for generation. Because of the long term
benefits of demand response, some differentiation in obligations and penalties
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between generation and demand response is justifiable in the short term to enable
the development of demand response.
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6.
A
SSESSMENT OF THE VARIOUS TYPES OF CAPACITY MECHANISMS
(472) Drawing upon the arguments presented and discussed throughout this Report,
Chapter 6 considers, within the framework of State aid assessment, to what extent
each of the types of capacity mechanism identified in Chapter 3 may be able to
address well-defined generation adequacy problems.
(473) The designs of capacity mechanisms vary widely, but all provide public support
for capacity providers and thus they may fall within the category of state aid
measures. They can therefore be subject to the European Union's rules on state
aid and their compatibility with these rules may have to be assessed by the
Commission. State aid principles provide an appropriate framework to assess the
need for capacity mechanisms, their ability to address potential capacity
shortages, as well as their potential market distortions.
(474) First, in assessing the potential compatibility of State aid measures it is necessary
to clearly identify the objective to be pursued. As explained in Chapter 3,
capacity mechanisms have the general objective of contributing to security of
electricity supply. However, in order to prove the necessity of State aid, Member
States need to provide further justification beyond stating this general objective.
There should be a detailed adequacy assessment which identifies, among others,
the amount, type, duration and location of the capacity needs.
(475) As discussed in Chapter 4, linking the reliability standard to the value consumers
place on being supplied with electricity, means that an economic efficient level of
protection is set and that expensive and distortive overprotection is avoided.
Therefore, a reliability standard based on VOLL should be the basis for guiding
any intervention in the market with the aim of ensuring security of supply.
(476) Once Member States clearly identify their adequacy problem, State aid rules
provide a framework for assessing the possible positive and negative effects of
the public intervention. Public support should be designed in the most appropriate
way to tackle the adequacy problem and to minimize potential distortions to
competition and trade in electricity markets.
(477) The remainder of this Chapter is structured as follows. Section 6.1 recaps the
actions needed to establish the necessity for a capacity mechanism. Section 6.2
discusses one by one the various types of capacity mechanisms, considering their
appropriateness to address particular adequacy concerns and the possible market
impacts arising from their implementation. This high-level assessment draws
upon best and worst practices identified in the sector inquiry. Section 6.3
provides an comparative overview of the types of capacity mechanisms identified
in the sector inquiry in light of their suitability to different problems. Section 6.4
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discusses the link between the objective of ensuring security of supply and the
one of decarbonisation and Section 6.5 concludes this final chapter.
6.1
Necessity for intervention through a capacity mechanism
(478) As explained in Chapter 2, a number of market and regulatory reforms have been
proposed and are being implemented to varying degrees in some Member States
to address concerns about electricity generation adequacy and security of supply.
Well-functioning markets have the potential to reduce the need for intervention in
the form of capacity mechanisms. Nonetheless, Member States may still consider
it necessary to implement capacity mechanisms.
(479) While capacity mechanisms can be justified when a residual missing money
problem is identified, they cannot replace the reforms pending to make electricity
markets more efficient. Each of the opportunities for reform identified in Chapter
2 are at the very heart of the effort, both at national and European level, to bring
about more efficient markets that provide reliable electricity to consumers at the
least possible cost. These reforms will allow exploiting as much as possible the
potential of competitive markets to efficiently deliver reliable electricity to the
benefit of final consumers. These reforms can therefore be neither neglected nor
delayed.
(480) Correcting market and regulatory failures that, to a large extent, contribute to
erode incentives to invest in capacity will reduce the concerns about the
reliability of EU electricity system. It will also reduce the need for additional
interventions like capacity mechanisms, minimising potential market distortions
and saving public resources. Finally, with or without a capacity mechanism these
reforms enable the price signals needed for efficient cross border energy trading,
and provide the most efficient signal for investment in the right mix of flexible
capacity to fulfil the needs of the system. Therefore, advancing in the market
reforms discussed above is warranted irrespective of whether the implementation
of any capacity mechanism is planned, and irrespective of the type of capacity
mechanism envisaged.
(481) As discussed in Chapter 4, the necessity of intervention should be established by
determining the necessary generation capacity that cannot be expected to be
provided by the market, even after alternative measures have been considered.
(482) Establishing the necessity for state intervention is an essential step in the
assessment of compatibility of any capacity mechanism with State aid rules. An
accurate generation adequacy assessment will identify in detail the particular
circumstances of each electricity market and the need for additional capacity,
including the amount and type of capacity required, the timing of any capacity
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problems and any particular locational capacity needs. For example, a Member
State can face a general capacity shortage, i.e. a systemic problem of insufficient
investment in new capacity possibly resulting from various factors undermining
price signals, risk aversion of investors, coordination failures or the public good
nature of reliability. Other Member States have a local capacity shortage due to
network constraints (cross-border or national) that cannot be addressed in due
time through alternative and, in the longer-term, more appropriate means, for
example by establishing appropriate bidding zones or investments in transmission
infrastructure.
6.2
Appropriateness and market impacts for each type of mechanism
(483) The various capacity mechanisms identified in Chapter 3 can be more appropriate
in some circumstances than in others. This can be due to either the ability of a
particular type of capacity mechanism to deal with certain types of capacity
shortage or to other market impacts particular types have. Member States face
different sitiuations because of the various stages of development of their
electricity market, the age and composition of their generation fleet. In each
specific case, the appropriateness of a capacity mechanism to address a well-
defined capacity need and its likely market impacts will have to be assessed.
(484) This section presents some tentative conclusions on the ability of each type of
capacity mechanism to address potential capacity shortages depending on the
problem identified, including if it is expected to be temporary or more permanent,
and location-specific or more general. It also discusses a number of likely market
impacts of capacity mechanisms, especially potential crowding-out effects
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on
investment and impact on market structure.
6.2.1
Tenders for new capacity
(485) As described in section 3.1.1, in a tender for new capacity the beneficiary
typically receives financing for the construction of a power plant that would bring
forward the capacity required to fill an identified gap.
(486) Tenders for new capacity have been used in Belgium, Croatia, France and
Ireland. In Belgium, the tender was intended to bring on new investment in gas-
fired capacity. In Croatia, a tender was launched to attract investment in a new
coal plant at Plomin. In France, the tender is intended to bring forward
investment specifically in a new CCGT plant in Brittany, where there is a risk of
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The crowding out effect refers to the potential for publically-supported investments to reduce the potential for
independent / private investments that might otherwise have come forward.
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insufficient local capacity. In contrast, the tender launched in Ireland in 2003 was
open to all types of thermal generation capacity. The Irish tender can be seen as
designed to address a temporary need while a more long-term intervention was
developed, namely the market wide capacity payment mechanism (see Section
6.2.4 below) which was introduced in 2007.
6.2.1.1 Ability to address capacity shortages
(487) While a tender can ensure new generation capacity is built, the security of supply
benefits it delivers may be offset by the impact the tender has on existing capacity
in the market, and on the incentives for future investment not supported by a
tender.
(488) A tender can attract investment in a particular location. This is an attractive
feature of the model, because it allows policy makers to implement a targeted
solution to a specific locational problem. For instance, in isolated regions the
need for capacity with specific capabilities – for instance to maintain grid
stability – may not come forward through market-based investments or market-
wide interventions.
(489) A tender for new capacity typically also has the advantage of providing for a
relatively quick and targeted solution to add new capacity, especially when
envisaged market reforms that alleviate the problem are known to take time to
implement. In particular, although time will always be needed to construct a new
power station, a tender is likely to take less time to develop and implement than a
more complex market-wide capacity mechanism and/or reforms to implement
appropriate bidding zones and scarcity pricing.
(490) However, as explained in sub-section 5.2.3.5, a tender does not correct the
underlying causes of a capacity shortage. In the longer term, security of supply
should be ensured through network development or by providing appropriate
incentives for local investment through higher electricity and ancillary services
prices in deficit regions. Where the requirement is for a local ancillary service,
TSOs should in general seek to competitively procure the required services
through an open, market-based competition, without the need for Government
involvement. Moreover, the decision of the location, the size and the product
requirements of the desired investment is taken by an administrative body (for
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instance the NRA or the ministry) instead of the market and therefore there is a
risk that a suboptimal solution is pursued.
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(491) As seen in sub-section 5.4.2.1 (under "New projects"), to ensure timely delivery
of the capacity some tenders include penalties for late delivery within the
beneficiary's control. Despite the potential for quick implementation, the long
contracts required to bring forward new investment (see sub-section 5.2.2.4) and
in some cases the characteristics of the particular technology benefitting from a
tender mean that this mechanism is likely to impact the market for many years.
6.2.1.2 Possible competition distortions and impact on market structure
(492) Tenders for new capacity produce a crowding-out effect, as can also be the case
with targeted capacity payments and strategic reserves. As explained in sub-
section 5.2.3.4, the appearance of new subsidised generation capacity in the
market is likely to depress electricity prices, and so will reduce the profitability of
other existing or planned capacity. As a consequence, some existing plants close
sooner than they would otherwise have or some investments that would otherwise
have taken place do not take place. This crowding-out effect can undermine the
efficacy of tenders for new capacity, if on the one hand, they incentivise
investment by their beneficiaries, but on the other, disincentivise investment by
other capacity providers.
(493) A tender may also incentivise opportunistic behaviour of potential investors.
Once the national authorities show that they are prepared to subsidise new
investment, investors may prefer to wait for a future tender rather than invest
purely on the basis of price expectations. As a result, tenders can either crowd out
new investment that would otherwise have come forward, or support the
financing of investments that might have taken place anyway, undermining the
incentive effect of the measure. A tender may even prompt premature
mothballing or closure decisions to access the support available through the
tender – similar to the slippery slope effect identified for the strategic reserve.
(494) As tender procedures typically offer long-term contracts they provide for
relatively great investment certainty and give stronger incentives to market
entrants. By lowering barriers to entry, they may therefore limit the market power
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Some stakeholders have noted that it can be difficult to administratively choose the most efficient option because
the all-in costs of different types of resources are difficult to compare and non-price terms can vary greatly. For
example, alternatives can vary in their available dispatch duration (more limited for DSR than for most
generation sources), some options are more reliable than others, or some resources would be able to operate for
many more years than others. All these considerations may be complex to be taken into account in an
administrative decision process.
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of incumbents and increase competition. In the Belgian tender, the authorities
sought to incentivise new entry by applying a 10% award criterion to take
account of the bidder's contribution to competitive market functioning in
Belgium. In Brittany, the tender was awarded to a market entrant. In Ireland, the
incumbent was not allowed to participate in the tender procedure and the capacity
product was designed to limit the possibility of the tender beneficiaries exercising
market power for the duration of their tender contract – see sub-section 5.4.2.1.
However, although new entry can increase competition in the electricity market, a
tender does not provide an enduring response to the potential to exercise market
power by participants in that market.
(495) Although they are usually domestic, tenders typically have cross-border impacts.
They will increase domestic capacity and therefore reduce opportunities for
imports. At the same time, they may slow down plans to improve connection with
other geographic areas.
6.2.1.3 Conclusions on tenders for new capacity
(496) A tender for new capacity may be an appropriate temporary measure to
incentivise investment (including in a specific location) and offer a route to
market for new entrants. A tender can be implemented relatively quickly even
though it typically takes several years to realise new generation investments and
it typically requires contract payments for several years.
(497) However, a tender does not effectively address longer term adequacy problems,
and is likely to exacerbate underlying market and regulatory failures unless
complementary reforms are also made. Hence, a tender can be an appropriate
instrument to bridge the time towards the implementation of a market-wide
capacity mechanism. Once the market-wide capacity mechanism is implemented,
it is generally more suitable to address local issues and stimulate new investment
through that mechanism rather than through a tender.
6.2.2
Strategic reserves
(498) As described in section 3.1.1, in a strategic reserve mechanism the additional
capacity needed on top of what the market is expected to provide is contracted
and then held in reserve outside the market. Capacity in strategic reserves
generally does not participate in the market and is dispatched only in case the
market does not clear, i.e. when there is a danger that demand will outweigh
supply.
(499) Examples of strategic reserves (excluding interruptibility schemes) exist in five of
the Member States included in the sector inquiry: Belgium, Denmark, Germany,
Poland and Sweden. All of the reserves are designed to keep existing power
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plants operational, so that they can be deployed when needed. Reserves are
generally only dispatched rarely (at most a few times a year) , but the German
network reserve is dispatched more regularly, namely in times where internal grid
congestion does not allow for the transmission from generation centres to demand
centres.
6.2.2.1 Ability to address capacity shortages
(500) While strategic reserves ensure that back-up capacity is available, the security of
supply benefits they deliver may be off-set by their impacts on capacity that
remains in the market.
(501) Generally, strategic reserves are seen as an instrument to keep capacity from
exiting the market and to develop a buffer for unforeseen scarcity situations.
During a period of overcapacity, as currently experienced in large parts of the
EU, market prices should give signals to prompt the closure of plants that are not
required. Strategic reserves can be used where there are good reasons that the
market does not (yet) deliver appropriate exit signals, to manage market exit of
conventional generation in a gradual way and prevent too many closures leading
to temporary local or general shortages. In market areas where market reforms
are still in the early stages of their implementation and market participants are
hesitant to invest on the basis of price signals alone, a strategic reserve can
provide an effective transitional measure on the road to market-based new
investment inspired by market reforms.
(502) Strategic reserves can also be designed to maintain capacity in specific
geographic areas. As described in more detail in sub-section 5.2.2.5, some
strategic reserves contract capacity located in specific regions within the
respective Member States.
(503) Whilst strategic reserves are able to address temporary shortages, they do not
address underlying market failures. As with other targeted capacity mechanisms,
the strategic reserves correct a missing money problem only for plants selected to
participate in them. Nor does a strategic reserve used for a local capacity problem
address the underlying issues that originally prevented local investment and
appropriate incentives need to be provided by reformed electricity prices (see
sub-section 5.2.3.5 of this report).
(504) From a timing perspective, strategic reserves must be transitional measures in the
sense that they delay the closure of some generation capacity and accompany
market reforms. Once the reforms are in place, the reserve should be phased out.
Hence, if longer term reforms require time to implement a reserve can be
appropriate as it offers an immediate option to prevent existing plants from
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shutting down. Moreover, it has the advantage (see next sub-section) that its
distortive effects can be limited if it is held outside the market. In view of the
objective of strategic reserves, generally there is no need for very long contracts
(see sub-section 5.2.2.4) because a strategic reserve is a tool for managing a
situation of overcapacity and risks of premature exit of existing plants, rather than
encouraging new investment. In market-wide capacity mechanisms, long term
contracts are sometimes used to allow new generation to compete on equal
footing with existing generation. The participation of new capacity and
availability of long term contracts are inappropriate for a strategic reserve that is
intended as a temporary means to manage market exit. Moreover, attracting new
capacity to a strategic reserve would necessarily require the organisation of a
tender for new capacity, which would reinforce the 'slippery slope' effect
described in sub-section 5.4.3.2 since it could cause potential investors to each
time await a tender for new capacity rather than invest on the basis of market
signals.
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6.2.2.2 Possible competition distortions and impact on market structure
(505) Strategic reserves are often held outside the market, which means that the plants
in the reserve cannot run and sell the power they generate in the market. The
market distortions that strategic reserves create are therefore in general less direct
and smaller than that of other types of capacity mechanisms, such as capacity
payments or market-wide volume-based mechanisms that foresee payments to
plants in the market.
(506) Nevertheless, the risk that strategic reserves distorts the market does exist and is
dependent mostly on the design of the mechanism. Reserves are typically called
to supply electricity when market prices increase above a certain threshold,
indicating extreme scarcity. If this threshold is set below VOLL, this limits the
ability of electricity prices to increase in moments of scarcity and risk reducing
incentives to invest in capacity which might, in turn, aggravate the initial capacity
shortage. Hence, similarly to tenders for new capacity and targeted capacity
mechanisms, the risk of a crowding-out effect on investment exists, reducing
their ability to address a potential capacity shortage. As explained in sub-section
5.4.3.3, this concern can be effectively addressed through a design that ensures
the reserve is only dispatched when the market fails to clear and setting market
prices, in these instances, to a VOLL price cap. Such a design leaves the
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These considerations do not apply to demand-side response. Where existing demand becomes flexible and
wishes to participate in a strategic reserve it should be allowed to do so. DSR does not require long investment
lead times nor does it require long term contracts. Hence, the argument of providing the necessary competitive
pressure in the allocation process does apply to DSR. The Swedish, Belgian and planned German strategic
reserves all allow for the participation of DSR.
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investment signals provided the electricity price intact. A strategic reserve design
that allows high electricity scarcity prices to form is also important to avoid
distortions of cross border markets, because imports will be attracted through the
price signal.
(507) Even if the reserve is only dispatched when the market fails to clear, investors
have expressed the concern that the reserve represents an additional regulatory
risk because the national authorities may be tempted to change the rules and
dispatch the reserve more often, for example in response to a prolonged period of
high electricity prices. Although investors will be best reassured by a track record
of non-intervention, this distortive effect can be partially mitigated by clear
communication that the reserve is intended to be a small, temporary intervention.
Only the highest degree of regulatory certainty will give new entrants the
confidence they need to invest.
(508) In addition to the crowding-out effect, a strategic reserve affects market structure
if it creates incentives for plants to announce closures that would not otherwise
have taken place, because the expected profitability for a certain plant is higher
within the strategic reserve scheme than outside the scheme. As a result, the
strategic reserve can in this case accelerate exit from the market. Belgium
provides a good example of how a strategic reserve can trigger this effect. Many
troubled generators announced their closure (legal precondition to enter the
reserve) in order to be able to enter the reserve so that the demand for the reserve
increased substantially from the first to the second year after its introduction (the
'slippery slope' effect described in Box 3 in sub-section 5.4.3.3). This reduced the
scope of the competitive market. Moreover, in particular gas-fired power plants
(which in Belgium are the main production segment where the smaller
competitors to the incumbent are active) risk being drawn into the growing
reserve. This can have additional impacts on the competitiveness of the
underlying electricity market, where the exit of plants into the reserve risks
increasing market power (see section 5.5).
(509) Another source of concern arises from the potential ability and incentive of an
incumbent with presence in the strategic reserve to withhold capacity in the
market to trigger a price increase and the activation of the strategic reserve,
provided that its profits from activating the reserve outweigh the cost of
withholding capacity. Finally, an additional source of concern can relate to the
exercise of market power when the candidates to be integrated into a strategic
reserve are very few. In this case, it can be that the tender for the reserve is not
sufficiently competitive, which would reduce the ability of a strategic reserve to
cost effectively address a transitional generation adequacy problem.
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(510) These concerns related to strategic reserves have to be balanced against their
potential merits. Several respondents to the Commission's public consultation
following the publication of the interim report of this inquiry, have pointed out
that compared to a market-wide volume based capacity market, the relatively
small, low upfront cost and quick-to-implement strategic reserve is in certain
circumstances the most appropriate form of intervention. These respondents point
in particular to the limited degree of market distortions that a well-designed
strategic reserve should cause if the capacity in the reserve is truly held outside
the market and only called upon when the market has failed to clear.
152
6.2.2.3 Conclusions on strategic reserves
(511) Based on the information gathered by the Commission during the various stages
of this inquiry, it can be concluded that strategic reserves, provided they are
accompanied by market reforms that directly and credibly target missing money
and provided the capacities are held truly outside the market, can be appropriate
transitional measures. Even if the reserve alone does not address underlying
market or regulatory failures, if well designed it has the potential to be a
relatively non-distortive insurance policy while required reforms are made.
(512) As a strategic reserve is unlikely to trigger investment in new generation capacity
it does not appear to be suitable in a market requiring such investment.
6.2.3
Interruptibility schemes
(513) As explained in subsection 3.2.3, interruptibility schemes are a particular type of
strategic reserve which only includes demand response capacity. Beneficiaries are
typically paid a fixed price for the demand response that they commit to make
available when needed, as well as a price for demand reductions actually
delivered.
(514) The sector inquiry found interruptibility schemes in seven of the Member States
covered by the inquiry: France, Germany
153
, Italy, Ireland, Poland, Portugal, and
Spain.
152
Though there is still a distortion to the merit order whenever prices in the market are set above the marginal costs
of plants held in reserve.
153
The German ABLAV interruptibility scheme (SA.43735) was assessed by the Commission under the
State aid rules. The Commission did not raise objections and judged the measure to be compliant with the
internal market.
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6.2.3.1 Ability to address capacity shortages
(515) There are various reasons why governments or TSOs develop interruptibility
schemes. Where used to procure demand response capacity to cover a general
capacity shortage – as opposed to ancillary services to manage short term
frequency deviations – interruptibility schemes can reduce incentives to invest in
flexible generation capacity, in the same way as strategic reserves do. Whether
interruptibility schemes actually have this effect depends to a large extent on their
design.
(516) Most of the interruptibility schemes currently in place are used by the TSO as an
ancillary service, i.e. as an instrument the TSO uses after intraday gate closure,
remotely and without any prior notice to the providers of the service. In such
cases, the impact of the schemes on market incentives is limited. Moreover, the
fact that more demand response potential will be activated thanks to the specific
support of the scheme is offset part of the need for additional flexible generation
capacity as underlined in sub-section 2.3.1.
(517) Ancillary services can be provided by other, competing sources of flexibility so
they do not necessarily have to be provided solely by demand response. A
scheme limited to demand response excludes other providers of flexibility and
therefore public authorities choosing to introduce DSR-specific measures should
ensure they can justify any limited eligibility criteria. One justification for
separate interruptibility schemes for ancillary services may be their potential to
unlock new demand response and thus create an instant type of flexibility that
would otherwise not have been at the TSO's disposal. If the objective is indeed to
unlock new demand response potential, then it would be appropriate to limit
participation to the interruptibility scheme to “immature” or “unproven” DSR
capacities
154
or to phase out the measure once a reasonable amount of flexible
loads have been unlocked. Although some Member States have considered
limiting the time an interruptible load can participate in their interruptibility
scheme, there is no evidence from the sector inquiry that interruptibility schemes
are used mainly or solely as transitional mechanisms. Allowing the continued
participation of “proven” demand response capacities in a (DSR-only)
interruptibility scheme shields those capacities from competition and may result
in the type of overcompensation to industry referred to in sub-section 5.2.3.3.
(518) Regarding their geographic scope, whilst interruptibility schemes generally apply
country-wide, their use can be local if the TSO sees a purely local need for
154
More “mature” or “proven” DSR capacities could then either participate in the energy market autonomously or in
a market-wide capacity mechanism (as in the UK).
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shedding loads, for instance in response to network constraints. This is the case
for the German interruptible load scheme which, as underlined in sub-section
3.2.3 can be used by the TSOs to manage congestions between the North and the
South while network reinforcements are made.
(519) From a timing perspective, the implementation of interruptibility schemes does
not in principle require long-term investments or commitments and therefore can
be seen as an appropriate measure if the problem is of transitional nature. For
instance, the relatively short contract times applied in interruptibility schemes
(see sub-section 5.2.2.4) have the advantage of allowing for amending demand
quickly. In view of the fact that ultimately demand response should be enabled
and able to compete with generation in the electricity and ancillary services
markets, and in any longer term market wide capacity mechanism, the need to
foster their development by means of a targeted interruptibility scheme will be
more difficult to demonstrate as market reforms take effect. In market areas
where a market-wide capacity mechanism is in place, this mechanism should in
principle allow for the participation of DSR and an integrated approach is likely
to deliver more efficient outcomes
155
.
(520) Interruptibility schemes should therefore be temporary measures that are phased
out once there is sufficient reason to assume that demand response will become
active on the basis of market signals or as capacity provider in a market-wide
capacity mechanism.
6.2.3.2 Possible competition distortions and impact on market structure
(521) Most of the interruptibility schemes currently in place are relatively small in size
and where this is the case their impact on electricity market functioning is
unlikely to be significant. Moreover, as underlined in Chapter 2, there is a
growing need for a flexible demand side and interruptibility schemes can be
appropriate to kick-start the development of demand response that will in future
be able to compete with other sources of flexibility in the wholesale and
balancing markets.
(522) However, despite their relatively small size, interruptibility schemes can be
expensive and their necessity is not always undisputed.
156
The effects of
155
For example because this would ensure maximum competition in the allocation process.
It has for instance been estimated that the Spanish interruptibility schemes costs around EUR 500 million per
year. Sources:
https://www.cnmc.es/es-
es/energ%C3%ADa/energ%C3%ADael%C3%A9ctrica/mercadomayorista.aspx,
ACER Market monitoring report electricity 2015, page 12:
156
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interruptibility schemes need to be monitored closely as they have the potential to
distort industrial markets if the selection criteria (and in particular minimum size
requirements: see sub-section 5.2.2.2) are unnecessarily restrictive. Where
schemes are devised by the government rather than independently by the TSO it
will be particularly important to ensure that they truly serve the purpose of
providing a service that is needed by the TSO at proportionate cost and without
disproportionately affecting competition with other sources of flexibility. When
this is not the case, these schemes risks becoming – as put forward by various
respondents to the sector inquiry – aid to the industrial energy users frequently
selected to provide the contracted demand response.
6.2.3.3 Conclusions on interruptibility schemes
(523) Whilst the benefits of unlocking additional demand response potential are clear,
the design of a scheme is essential to ensuring that it truly provides added value
to the TSO in ensuring system security in a cost-efficient way. Interruptibility
schemes do not appear to provide an enduring solution to a capacity shortage
problem, but in the short term can be appropriate to help develop demand
response. In the longer term, there may be an enduring need for particular
ancillary services procured by TSOs from demand response, but to reduce the
risk of over-compensating the providers of such services, beneficiaries should be
selected through competitions open to all potential providers able to meet
transparent technical requirements.
6.2.4
Targeted capacity payments
(524) As explained in sub-sections 3.1.1 and 3.1.2, in capacity payments models a
central body sets the price of capacity. In targeted capacity payments the centrally
set price is paid to a subset of capacity operating in the market, for example only
to a particular technology, or only to capacity providers that meet specific
criteria.
(525) The sector inquiry found targeted capacity payment schemes in Italy, Poland,
Portugal, and Spain (see sub-section 3.2.4).
6.2.4.1 Ability to address capacity shortages
(526) Targeted capacity payments are designed to address specific needs, making
payments accessible only to generators of certain types or in certain locations.
http://www.acer.europa.eu/Official_documents/Publications/Pages/Publication.aspx.
However, it appears to not be used frequently. Source: Platts European Power Daily, 15 April 2016
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However, while targeted capacity payments can be effective in keeping the
existing plants benefitting from the payment from closing or support investment
in eligible beneficiaries, as with the tender and reserve models they risk
worsening the situation for those that are not eligible. In Spain, the existence of
several targeted schemes suggests that no individual targeted capacity payments
mechanism has been considered sufficient to ensure generation adequacy (see sub
section 5.2.3.8). There are different capacity payments available to investors in
new plants, and to those operating existing capacity. Portugal also has two
capacity payments schemes, as well as a separate interruptibility scheme.
(527) The targeted capacity mechanisms mechanisms identified in this inquiry all limit
participation to specific technologies, but none pay only for capacity in a
particular geographic region. Alternative measures are often available to address
local shortages more efficiently than targeted capacity payments, like creating
locational electricity prices which provide longer term incentives not only for
local capacity investment but also investment in cross-zonal transmission and
signals for the use of existing transmission infrastructure.
(528) In any capacity payments model, the major challenge is the identification of the
correct level for the capacity payments without a competitive process. As
explained in detail in section 5.3, it is difficult to obtain through an administrative
process a level of remuneration that incentivises the right amount of additional
generation capacity. Setting the wrong level of payments leads to either under- or
over-investment in capacity, compared to the level desired. This greatly
compromises the ability of capacity payments to efficiently meet its objectives.
The administratively set price level is also impossible to justify in the same way
as a price emerging from a competitive process. That is why – whether they
consider the prices to be too high or too low – stakeholders are frequently
unhappy with the administratively set prices in these models. The lack of a
competitive process therefore makes these models inappropriate choices,
regardless of the capacity problem identified.
6.2.4.2 Possible competition distortions and impact on market structure
(529) As with tenders and strategic reserves, targeted capacity payments produce a
crowding-out effect. The appearance or maintenance of subsidised generation
capacity in the market is likely to be detrimental to the profitability of non-
subsidised generation capacity, by depressing electricity prices that remunerate
all capacity providers. This crowding-out effect can undermine the efficacy of
capacity payments if it deters investment by ineligible capacity providers.
(530) Moreover targeted capacity payments can distort technology choices of investors.
They support specific types of generation capacity as defined centrally by the
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authorities, to the detriment of alternative choices that market players could have
made in response to market signals
157
.
(531) More generally, some investors have raised the concern that even where capacity
payments schemes are open to new entrants, since there is no competitive process
in which new projects might come forward and take market share from existing
capacity providers, capacity payments contribute to keep in the market capacity
that would otherwise exit and therefore constitute a barrier to new investment in
generation. They therefore preserve the existing market structure and generation
mix.
(532) It is in principle conceivable that targeted capacity payments are paid only to new
entrants or smaller generators, but there are no examples of such a practice and it
would be difficult to justify on objective grounds. In Greece, for example, the
flexibility mechanism supports the gas-fired power plants of the independent
power producers as well as of the incumbent because both operate plants
fulfilling the technical criteria to ensure the necessary flexibility
158
.
6.2.4.3 Conclusions on targeted capacity payments
(533) Targeted capacity payments suffer from many of the drawbacks of the tender and
strategic reserve models, with the additional drawback that there is no
competitive price setting process which increases the risk of failing to deliver
security of supply or stimulating overcapacity, as well as making the level of
remuneration difficult to justify. They are therefore likely to be the least efficient
models of capacity mechanism.
6.2.5
Central buyer mechanisms
(534) As described in sub-section 3.1.2, in a central buyer mechanism the total amount
of required capacity is set centrally, and then procured by a central buyer through
a process in which potential capacity providers compete. This competitive
bidding determines the price paid to capacity providers.
157
Though the capacity product obligations in a capacity mechanism will always have some impact on
investors' technology choices.
158
While in general capacity payments models will not be considered appropriate, the Greek flexibility
mechanism was approved in 2016 as an exceptional temporary measure for a period of 12 months (see
SA.38968) while various market reforms where implemented (among other things to increase wholesale
and ancillary services price caps) and a more appropriate longer term central buyer capacity mechanism
developed.
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(535) Sub-section 3.2.5 explains that examples of central buyer schemes were found in
two of the Member States included in the sector inquiry: Ireland and Italy. Both
mechanisms are still in development and are not yet operational. Examples of
central buyer schemes are also found in the British capacity mechanism, and in
the United States including in the ISO New England and PJM systems on the East
Coast.
(536) These mechanisms are being introduced by Ireland and Italy because of concerns
that there are systemic electricity market failures that cannot be addressed – at
least in the medium term – only through reforms to the energy only market. The
UK presented similar reasons for the introduction of the British mechanism.
6.2.5.1 Ability to address capacity shortages
(537) A central buyer mechanism produces a competitive capacity price through an
auction for the total required capacity, as established by the central buyer. This
ensures that the desired amount of generation capacity is actually procured and,
provided the auction is competitive, ensures the cost of procuring such amount of
generation capacity is minimised. A central buyer mechanism can therefore
efficiently attain the desired level of generation capacity, if appropriately
designed.
(538) A number of design features can contribute to the competitiveness of the
procurement procedure and the efficiency of the outcome. Eligibility rules that
broaden the set of potential participants in the mechanism, for example, are likely
to contribute to this competitiveness (as explained in Section 5.2).
(539) An important aspect in central buyer mechanisms – as in other volume-based
mechanisms – is the need for a central body to estimate the required amount and
type of generation capacity to attain the desired level of system reliability. While
this minimises risks of insufficient provision of generation capacity, it risks
leading to excess capacity if risk-averse central authorities set the targets for
generation capacity at unnecessary high levels. This risk exists to some extent in
every capacity mechanism type, however, and should be mitigated by links to a
thorough and transparent adequacy assessment, and appropriate oversight of
regulators or independent experts to verify the parameters set by governments
and TSOs.
(540) Regarding the geographic scope of the intervention, with eligibility criteria open
to all potential capacity providers, a central buyer mechanism is able to address a
systemic missing money problem. Central buyer mechanisms can also be used to
address local shortages. For instance, to encourage sufficient investment in
different locations the central buyer mechanisms in ISO New England and PJM,
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and the proposed mechanism in Italy, the auctions discover zonal capacity prices
in different geographical areas covered by the mechanisms.
159
(541) Regarding timing in the implementation of central buyer mechanisms, the long
lead time between the auction and obligation period required to enable new
projects to be built, and the potential for longer contracts for new capacity, limit
the ability to quickly move from a central buyer model to an alternative market
design. These mechanisms may therefore be less appropriate as very short term
transitional interventions than tenders or strategic reserves. However, the
mechanism can correct itself because when more capacity is available and/or
investors expect future electricity revenues to fully compensate their investments,
the price of capacity will drop, in theory to zero when there is no longer any
missing money.
160
6.2.5.2 Possible competition distortions and impact on market structure
(542) So long as it is possible in practice for new projects to compete with the least
efficient existing capacity providers, a central buyer model can attract new
entrants. The possibility of competition from new entrants should also help
ensure that the market power of participants in the capacity auction itself is
limited.
(543) To assess the impact of this model on the market structure, the existence of
longer contract lengths for new investments is a key parameter (as discussed in
sub-section 5.2.2.4). Unlike the de-central obligation model, the central buyer
model can be designed more easily to accommodate multiple contract lengths.
This facilitates the participation of new projects needing to commit upfront to
high initial investment costs, but needs to be balanced against the potential
discrimination between different capacity providers due to different contract
lengths.
(544) The possibility of effective participation from new entrants in this type of
mechanism means that it can be designed in such a way that no barriers to entry
are added in electricity generation. The competitive threat from potential entrants
can be an effective constraint to incumbents with strong market positions, and the
eventual participation of foreign capacity would constitute an additional
159
160
Efficient rules for cross-zonal participation are needed in such a design to ensure appropriate incentives for
investment in additional transmission as well as generation and demand response capacity. In practice, these rules
may be no different to the rules required for foreign capacity participation (see Annex 2).
This depends on the capacity product. Where the product exposes participnts to particular risks, the price may
never reach zero. For example, a reliability option requiring paybacks from capacity providers. However, in an
efficient system consumers should be compensated for the cost of capacity by the paybacks received.
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competitive constraint.
161
Moreover, the capacity product in a central buyer
model can also be designed to limit market power in the electricity market. For
example, the reliability options being developed in Ireland and Italy should still
allow high prices to be set in the electricity market (which in turn will send
efficient signals for imports and demand response) while also limiting the extent
to which capacity providers that have benefitted from the capacity mechanism
can access these high prices at consumers' expense.
6.2.5.3 Conclusions on central buyer mechanisms
(545) A central buyer mechanism has the potential to solve a general shortage of
capacity efficiently, but its success depends greatly on appropriate eligibility
criteria and a design of the capacity product that ensures achieving a well-defined
objective with minimal distortions to the functioning of the electricity market. It
may be particularly useful where concerns about potential market power prevent
a more decentralised approach and/or longer contracts are required to bring
forward new entry.
(546) Some inefficiency may be unavoidable in any central buyer design, for example
due to the complexity of carefully assessing all the design features, the
dependence on central judgements by risk averse decision makers – though this
can be reduced by including a role for the regulator or independent experts in the
process – and the need to centrally determine the required flexibility
characteristics of capacity providers through the design of the capacity product.
6.2.6
De-central obligation
(547) As explained in sub-section 3.1.2, in a de-central obligation mechanism an
obligation is placed on electricity suppliers/retailers to contract with capacity
providers to secure the total capacity they need to meet their consumers' demand.
The difference compared to the central buyer model is that there is no central
bidding process, but market forces should still establish the price for the required
capacity volume.
(548) As explained in sub-section 3.2.6, the only de-central obligation mechanism
found in the sector inquiry is the capacity certificates market being introduced in
France.
161
Although a solution appears possible that would allow cross-border participation in central buyer and de-central
obligation capacity mechanisms (see Annex 2) until this is enabled there will be long term distortions to
locational investment signals, with stronger incentives for investment in capacity mechanism areas than in
neighbouring areas without capacity mechanisms or in new transmission linking the two (see sub-section
5.2.3.7).
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6.2.6.1 Ability to address capacity shortages
(549) Like the central buyer model, a supplier obligation is in principle suitable to
address a systemic, market-wide missing money problem, subject to appropriate
eligibility criteria and a suitable capacity product.
(550) It is less likely to be appropriate when generation capacity required is of a certain
type or in a certain geographic location. While in principle it is conceivable to
enable locational investment signals in a de-central obligation mechanism, for
example by obliging suppliers to purchase a proportion of their capacity
certificates from providers located in a particular geographical location, this
would result in significant added complexity and there are so far no precedents of
such type of mechanism.
(551) From a timing perspective, the complexity of designing and implementing de-
central obligation mechanisms seems to suggest they are unlikely to be seen as a
transitional intervention. However, compared to the central buyer mechanism the
absence of long contracts reduces the future costs of exit from the mechanism. In
a well-designed and competitive de-central obligation mechanism, once the
required level of generation capacity is attained, capacity prices should
theoretically fall to zero in the same way as in the central buyer mechanism.
(552) Contrary to the central buyer mechanism, a de-central obligation does not require
a central determination of the generation capacity required to ensure the targeted
level of system reliability. In a de-central obligation mechanism the central
authority establishes only the coverage rate of expected demand that market
participants need to attain through bilateral contracting, leaving the estimation of
expected demand to each supplier.
(553) This does not mean that the risk of over or under-procurement is absent. It can
materialize for instance if the design of penalties that apply for insufficient
procurement allow suppliers to strategically underestimate their expected demand
to reduce procurement costs, or are so high that suppliers overinsure themselves
by purchasing extra capacity. There can also be other administrative elements that
influence the overall level of security that will be achieved by such a
mechanism.
162
Other causes for over or under procurement are not specific to de-
central obligation mechanisms, like a genuine over or underestimation of medium
to long term capacity needs or the lack of visibility of suppliers about their future
162
The French mechanism includes an additional administrative element since suppliers' obligations are inflated by
a 'thermosensitivity factor' to ensure suppliers buy enough capacity to meet demand in a particularly cold winter.
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customers' demand, which can also occur when the required generation capacity
is determined centrally.
6.2.6.2 Possible competition distortions and impact on market structure
(554) While de-central obligation mechanisms are open to the participation of new
entrants, their effective participation depends on the possibility and appetite of
market players for engaging in longer duration capacity contracts, which in turn
is influenced by capacity price uncertainties. Almost two-thirds of market
participants responding on the French de-central obligation mechanism (including
mainly generators but also demand response aggregators) considered that it did
not provide sufficient incentives for new investment. For that reason, eventually
the French authorities agreed to include in the mechanism a central buyer
element, through which the TSO would contract competitive new capacities
longer term (see sub-section 5.2.2.4).
(555) The dependence on bilateral trading in a de-central obligation model without
mandatory exchange trading risks giving an advantage to vertically integrated
companies that can trade certificates internally between their generation and retail
businesses. This is likely to increase incentives for vertical integration and reduce
incentives for new independent market entry on the generation or retail side. A
de-central obligation mechanism may therefore not be appropriate if there is a
perceived risk that an incumbent with some degree of market power will abuse its
position in the trade of the obligations. Alternatively, the inclusion of specific
safeguards in the capacity mechanism may be envisaged to limit this risk. This is
particularly relevant in electricity markets with a significant degree of market
concentration.
(556) Cross-border participation is necessary to correct distortions to locational
investment signals that would otherwise be caused by the introduction of a de-
central obligation mechanism and ensure longer-term competition between the
domestic and foreign capacity that can both contribute to domestic security of
supply. The only de-central mechanism covered by the inquiry, in France, will
eventually include direct participation of foreign capacities following the
proposal described in Annex 2.
6.2.6.3 Conclusions on de-central obligations
(557) A de-central obligation mechanism has the potential to solve a general shortage
of capacity efficiently, subject to appropriate eligibility criteria and a suitable
capacity product. It does not require the amount of capacity needed to be
centrally determined, which is an advantage if market players are better suited to
identify the needs for capacity. However, risk of over- or under-procurement
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exists, especially if penalties and other administratively-set parameters are not
carefully designed.
(558) If possibilities to contract on longer-term basis are limited, this hinders the entry
of new generators to the benefit of incumbent capacity providers. This is however
not different to the situation in a market without any capacity mechanism where
longer-term contracting is uncommon. Even where new entry is not immediately
needed, mechanism designs that facilitate new entry can be useful to limit
potential market power of existing capacity providers. A pure de-central
obligation mechanism, without any specific provisions for new capacities, are
therefore not the most suitable in cases where there are concerns about barriers to
entry and exercise of market power by incumbents.
6.2.7
Market-wide capacity payments
(559) As in targeted capacity payments models, in market-wide capacity payments
model a centrally determined price is paid to capacity providers. The difference is
that while in targeted models only a subset of capacity receives the payments, in
market-wide mechanism all capacity expected to be needed to meet demand in
the market receives the payments.
(560) The sector inquiry found one market-wide capacity payment scheme in Ireland
(see sub-section 3.2.7).
6.2.7.1 Ability to address capacity shortages
(561) Market-wide capacity mechanisms avoid some of the drawbacks identified above
for the targeted capacity payments model, since they seem to avoid the need for
multiple mechanisms (since introducing a market wide capacity payment scheme
in 2007, Ireland does not appear to have needed additional interventions to ensure
generation adequacy).
(562) However, like targeted capacity payments models, market-wide capacity
payments suffer from the critical flaw that the administrative price-setting process
brings high risks that the measure will fail to efficiently meet its objectives.
6.2.7.2 Possible competition distortions and impact on market structure
(563) A market-wide capacity payment model does not appear to have the same
negative crowding out effects as targeted capacity payments, nor – so long as it is
open to all technologies capable of providing capacity – does it distort investors'
technology choices in the same way as a targeted mechanism.
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(564) However, the lack of competitive process serves as a barrier to entry and
therefore preserve the existing market structure and generation mix.
(565) In Ireland, to counter concerns that generators would receive a capacity payment
based on their fixed costs and then earn windfalls from high electricity prices,
market participants are required to bid at the level of their short run marginal
costs into the electricity market. This accompanying market rule risks causing the
capacity mechanism to become a permanent feature of the market (unless other
reforms are made) and risks undermining the efficiency of electricity prices as a
signal for imports at the right times.
6.2.7.3 Conclusions on market-wide capacity payments
(566) Although they have suffer from fewer drawbacks than the targeted capacity
payments mechanisms, market wide capacity payments do not competitively
reveal the value of capacity and come with high risks of failing to cost effectively
meet their objectives.
6.3
Choosing the right type of capacity mechanism
(567) The assessment of the effects of the various types of capacity mechanisms can be
used to draw conclusions as to which mechanism fits best in which situation.
Combined with a detailed adequacy assessment that precisely defines the
problem, the pros and cons of each mechanism type can help guide Member
States to choose the most suitable intervention and avoid the development of an
inappropriate mechanism, as well as the Commission in its State aid assessment
of the measure,.
(568) Note that the assessment framework presented in this section is of illustratory
nature only; the suitability of a capacity mechanism will always need to be
assessed against the specific background of the market area in which it is
introduced. The electricity market is rapidly evolving and many interventions are
new or still in development. The Commission will therefore need to remain agile
to respond as further lessons are learned and markets further developed.
(569) It is also critical, as highlighted by respondents to the consultation, that the
process to implement a capacity mechanism is transparent and consultative so
that market participants and consumers understand the rationale for the
intervention and its implications, and can contribute to ensuring an appropriate
design.
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6.3.1
The main adequacy problems
(570) The main adequacy problems identified so far in the sector inquiry and case
practice can be categorised in four groups:
1. concerns about the long term ability of the market to trigger sufficient
investments;
2. concerns of a temporary nature where the current market design fails to provide
adequate investment signals or risks producing uncontrolled market exit, but
where the market is expected to be effective in the longer term;
3. concerns of a local nature (i.e. in a specific location within a Member State) that
cannot be resolved quickly enough by investing in transmission or implementing
a better configuration of electricity bidding zones; and
4. concerns that without additional support, energy consumers (the demand side)
will not play a sufficient role in managing electricity demand and security of
supply.
(571) Before assessing the most appropriate response in each of these four situations, it
is useful to distinguish why certain Member States might conclude they face a
long term adequacy concern whereas others are convinced their concerns are of a
temporary nature only. Case practice demonstrates that the question whether a
reformed market will be able to trigger investments without any additional
support is often answered on the basis of policy considerations and the state of
the current market rather than pure economic analysis. Economic analysis
indicates that, under certain assumptions, prices reflecting VOLL in periods of
scarcity could trigger investment at the optimum level to achieve levels of
reliability that consumers are willing to pay for. However, none of the countries
in this inquiry have chosen to rely on an energy-only electricity market, and
examples of liberalised 'energy-only' markets outside the enquiry are relatively
rare. It may well be that a government is not, or not immediately, prepared to take
the risk of relying on a market without a capacity mechanism to deliver secure
supplies.
(572) As a government considers what approach to take, uncertainty is inevitably
transferred to market participants who will be hesitant to invest in the knowledge
that the government may choose to intervene in some way. For expectations of
high scarcity prices to have a true chance of triggering investments, it is essential
that the government not only ensures the required reforms make such prices
possible, but also clearly communicates its commitment to abstain from
intervening by capping prices in the future. As this stance is maintained,
confidence will be further increased.
(573) In some markets it is easier to take such a stance than in others. In particular,
where there is currently more installed capacity than required and there is no risk
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of large amounts of capacity closing suddently because it is nearing the end of its
technical lifetime, governments have a chance to upgrade and then rely on the
market in a way that a government in a country with an urgent need for new
investment cannot. Fortunately, in most of Europe there is currently overcapacity,
affording Member States to make the most of the opportunity to make the market
work.
(574) Adequacy assessments are able to quantify the extent of any current overcapacity
and the risks of plant closures to a large extent, but a degree of uncertainty
remains that may lead policy makers to opt for the insurance of a market-wide
capacity mechanism to support market reforms. Where policy makers on the
other hand are convinced that no intervention in the market is necessary or
appropriate, it should communicate this clearly because investors need the
confidence that the regulatory framework will not be adapted to their detriment
after they have made an investment.
6.3.2
Long term concerns
(575) In the first of the four cases, i.e. where a general missing money problem is
identified and confirmed by way of an adequacy assessment, the appropriate
response consists of a longer term intervention in the market that ensures new
investments and maintains existing capacity providers in the market to the extent
they are necessary to ensure security of supply. Strategic reserves and individual
tenders do not fundamentally change the investment climate of an electricity
market and so are not suitable to address a general missing money problem.
(576) In contrast, market-wide mechanisms can, if well-designed, create the confidence
existing and aspirant market participants need. For instance, the design of the
future Irish reliability options mechanisms (a central buyer mechanism) creates
certainty about future returns for generators by ensuring them a fixed payment
throughout the year for being available in exchange for uncertain scarcity rents.
As described in Chapter 2.2 there are multiple market reforms that should
mitigate concerns around a general missing money problem and the assessment
of their added value as well as their implementation are prerequisites for the
implementation of any form of market-wide mechanism. These reforms are
required to help ensure the State aid required through the capacity mechanism is
kept to the minimum.
6.3.3 Temporary concerns
(577) For a temporary adequacy concern, where policy makers are convinced that in the
long run the market can be reformed to ensure a healthy investment climate exists
that will trigger the right type of investment, long term interventions are not
necessary. In such instances, intervention should be temporary, does not have to
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trigger new investment because there is confidence that the market will do that,
and should ensure that the developing market is distorted as little as possible.
(578) A strategic reserve is likely to be the most appropriate response in such
circumstances because it can prevent too much capacity leaving the market while
necessary reforms are made. Market distortions will not not absent but can be
reduced if the reserve is well designed to keep it as small as possible. This is best
achieved by ensuring the reserve is held completely outside the market and
allows appropriately high prices to emerge in the electricity price when electricity
capacity is scarce. Such a design maintains incentives to remain in the market,
and therefore reduces the risk of a slipperly slope. Moreover, strategic reserves
should be accompanied by a clear end date which helps to preserve future
investment signals. Clearly, the optimism about the market's ability to ensure
appropriate investment signals needs to be based on a solid assessment including
implementation of the reforms necessary to ensure future electricity prices
support future investment in the market area concerned.
(579) A strategic reserve can also be used as a tool to fill a looming capacity gap while
a volume-based market wide capacity mechanism is being introduced. In this
way, it can be valuable to avoid short auction lead times for the market-wide
mechanism. At the same time, there may be a benefit in introducing a market-
wide mechanism straight away to avoid devising and implementing a transitional
mechanism of a different type.
6.3.4
Locational concerns
(580) The third concern – temporary or long term worries about generation adequacy in
a specific location in the market area – sometimes arises in relatively isolated
areas such as islands or peninsulas (e.g. Brittany), but is also a concern in
relatively well-connected mainland areas (e.g. south Germany, or south Sweden).
(581) In the long run, a durable solution needs to be found through investments in
transmission and a better connection of the region. Where that is not possible or
feasible, for the reasons set out in Section 2.2.2 the creation of additional bidding
zones should be the solution. Whatever the most appropriate longer term solution
is, the situation in the short to medium term needs to be remedied.
(582) Where longer term adequacy concerns have been identified and a market-wide
mechanism is being introduced, a market-wide mechanism can sometimes be
tailored also to solve a local adequacy problem: Italy is planning, to create
capacity price zones within a market-wide capacity mechanism to provide signals
for local investment.
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(583) A more targeted measure can also be suitable to address a local adequacy concern
– including the inability to bring forward required local ancillary services without
Government intervention. A strategic reserve can be limited to a specific region
only, as can a tender for new capacity. These targeted mechanisms can be sized to
the identified local capacity gap. Because of the long contracts required to
stimulate investments in new capacity through a tender, and the additional market
distortions that arise because benefitting capacity participates in the electricity
market, tenders must be limited to circumstances in which there is a proven need
for new investment.
(584) To avoid an unacceptable distortion where local capacity value is extracted from
electricity prices and moved into the capacity mechanism, whichever mechanism
is used the local problem needs to be solved in the longer term through
transmission investment or by reconfiguring electricity bidding zones.
6.3.5
Concerns related to the responsive of the demand side
(585) Finally, the fourth concern is about the insufficient development of a flexible
demand side, which may lead a Member State to introduce an interruptibility
scheme (or to introduce specific rules to stimulate demand response within a
volume based market wide scheme where one is introduced). Based on the
assessment of the eight schemes in operation in 7 of the 11 Member States, these
schemes can be justified in view of their modest but nevertheless significant
contribution to both short term and long term security of supply.
163
Demand
response can prove useful for balancing the system in the short run, while a fully
responsive demand side has the potential to entirely eliminate the need for
capacity mechanisms in the long run since it would enable consumers to pay for
different levels of reliability and therefore reduce the political justification for
intervening to ensure security of supply on consumers' behalf.
(586) However, the appropriateness of interruptibility schemes – and therefore their
compliance with EU State aid rules – depends crucially on how they are designed
and how they function. Where a demand response scheme allows for broad
participation from large and small industries and from demand response
aggregators, does not procure excessive capacity, is based on competitive
procurement, and is designed not to influence the formation of appropriate
electricity scarcity prices, it may be acceptable for a limited period of time to
kick-start demand response, although it can create some market distortions and
163
Note that such assessment within the sector inquiry cannot replace the need for individual assessment of any
State aid measures, and this statement should not be interpreted to mean that schemes that have not yet been
assessed and subject to a Decision of the Commission will be found compatible.
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although State aid rules normally require capacity mechanisms to be open to all
technologies. It should however be shown that such schemes provide additional
value compared to existing ancillary services schemes. On the other hand,
demand response schemes in which too much capacity is procured from only a
subset of large industrial beneficiaries are unlikely to be approved under State aid
rules. They risk subsidising energy intensive industries without providing
corresponding value in terms of increased security of supply to other electricity
consumers.
6.3.6
Capacity payments are unlikely to be the most appropriate option
(587) Finally, with respect to 'capacity payments', the sector inquiry shows that these
mechanisms are unlikely to set the right price for capacity since they do not allow
the market to competitively set the right price, but rather depend on an
administratively set price. They are therefore unlikely to correctly reflect the
actual scarcity situation. They imply a high risk of under- or over-procurement of
capacity – especially as such schemes tend to react slowly to changing market
circumstances. And the level of remuneration is often challenged by stakeholders
since it is impossible to justify in the same was as a remuneration level emerging
from a competitive process. The general presumption is therefore that price-based
mechanisms are unlikely to be an appropriate measure regardless of the specific
concern identified.
6.4
Minimising the cost of capacity mechanisms
(588) The support given through capacity mechanisms is typically financed from public
resources and therefore ultimately borne by final consumers. Assessing the cost
of capacity mechanisms is an important but challenging exercise.
(589) Capacity mechanisms involve the transfer of financial resources from public
budgets to investors in capacity, either directly or indirectly (like in de-central
obligation mechanisms). In all cases, taxpayers or final consumers are the source
of these financial resources.
(590) Assessing the net cost of capacity mechanisms is not easy, because it requires
examination not only of the budgetary payments made by public authorities, but
also of any potential savings stemming from the capacity mechanism. This
includes the avoidance of load losses for consumers due to electricity supply
disruptions, and the reduction in electricity wholesale costs arising from the
existence of the capacity mechanism and the transfer of revenues from electricity
scarcity prices to capacity payments. Differences in the necessity, design and
market impact must be taken into account comparing costs across mechanisms.
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For instance, a small but unnecessary capacity mechanism with relatively low
expenses can be more costly overall than a larger but necessary mechanism.
(591) Despite the complexity of assessing the true costs of a capacity mechanism, it is
important that Member States do their best to properly estimate the expected
costs and savings of any capacity mechanism they implement, both ex-ante and
ex-post, to ensure the cost-effectiveness of their public intervention. Member
States must also be as transparent as possible about this assessment to allow for
democratic scrutiny of their policy choices. The information received by the
Commission in the context of the sector inquiry demonstrated that cost benefit
assessments and evaluation of capacity mechanisms are the exception rather than
the rule.
(592) The sector inquiry has also identified a number of ways to limit the cost of
capacity mechanisms through a thorough and comprehensive adequacy
assessment and an appropriate design:
The adequacy assessment should exclude capacity mechanisms whenever there is
overcapacity or no real need. An adequacy assessment that compares the existing
and future capacity to a reliability standard based on VOLL will help keep costs
on check and procure capacity volumes reflecting consumers willingness to pay.
The adequacy assessment should identify alternative solutions and measures for
achieving the objective. By looking at the adequacy problems in a holistic way a
comprehensive adequacy assessment can minimise costs by identifying the least
costly measure or combination of measures and avoid ending up with multiple
capacity mechanisms and reduce the risk of continuous reforms. Targeted
mechanisms for instance appear cheaper than market-based capacity mechanisms,
but if the adequacy problem is general it might be less costly to establish a single
market-based capacity mechanism than bearing the cost of a multiplicity of
targeted mechanisms.
In terms of design, open and broad elegibility criteria that allow all capacity
providers to participate in the market and a competitive allocation process are
crucial for ensuring that costs are justificable and kept to the minimum necessary.
6.5
Capacity mechanisms and the decarbonisation objective
(593) The various types of capacity mechanisms have been assessed in this Staff
Working Document mainly against their ability to cost effectively address
problems of generation adequacy and their potential to create distortions to the
functioning of the Single Market in energy.
(594) However, as already explained in Chapter 2, current EU energy policy also
encompasses the objective of decarbonisation. Significant private and public
efforts have been made to advance in this area. By having an impact on
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generation capacity and on the generation technology mix, capacity mechanisms
interact with policy instruments
164
designed to foster decarbonisation and may
impact the achievement of their objectives. It is important that Member States,
when they design capacity mechanisms are aware of these interactions, in line
with the EEAG.
165
Chapter 5 of this Staff Working Document identified instances
where eligibility or allocation criteria already take into account decarbonisation
objectives, and in future Member States may wish to develop capacity-based
remuneration for renewables, allowing them to compete alongside other capacity
in a competitive process for delivering decarbonisation and resource adequacy
objectives. When demand side management measures are being considered, such
as interruptibility schemes, the Member States should take into account their
potential environment and climate policy benefits in their overall assessment.
6.6
Conclusions
(595) Given the on-going developments in and reforms of EU electricity markets, the
Commission will continue to carefully monitor the evolution of capacity
mechanisms and to refine the guidance set out in this Communication and the
annexed report in the light of its evolving case practice. But based on the sector
inquiry, the Commission draws eight overall conclusions.
(596) First, it has become clear that despite current overcapacity in the EU as a whole,
there are widespread concerns that insufficient generation capacity will remain in
the market or come forward in time to ensure adequate security of supply.
(597) Second, electricity market reforms are indispensable since they help to address
concerns about inadequate security of supply. However, most Member States
have yet to implement appropriate reforms. The Commission's Market Design
Initiative therefore proposes a number of reforms to improve the functioning of
EU electricity markets and the Commission will require Member States to
implement reforms to accompany the planned introduction of any capacity
mechanism.
(598) Third, even if a reformed market in principle has the potential to deliver secure
supplies, significant uncertainty persists about whether an increasingly volatile
164
165
For example the EU ETS.
See para. 233(e) EEAG: "The measure should […] give preference to low-carbon generators in case of
equivalent technical and economic parameters" and para. (220) "Aid for generation adequacy may contradict the
objective of phasing out environmentally harmful subsidies including for fossil fuels. Member States should
therefore primarily consider alternative ways of achieving generation adequacy which do not have a negative
impact on the objective of phasing out environmentally or economically harmful subsidies, such as facilitating
demand side management and increasing interconnection capacity."
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market price and rare scarcity situations can drive long-term investment
decisions. Some Member States have therefore decided to introduce capacity
mechanisms to ensure security of electricity supply. These mechanisms involve
State aid and must be notified to the European Commission under State aid rules.
These mechanisms will be approved if Member States demonstrate their necessity
and if the distortions of competition that they generate are minimised in line with
State aid rules, taking account the outcome of the sector enquiry as summarised
in this Communication.
(599) Fourth, a rigorous adequacy assessment against a well-defined economic
reliability standard is crucial for identifying risks to the security of supply and for
determining the necessary size of any capacity mechanism. Such a rigorous
assessment will significantly reduce the risk of over-procurement and help to
limit the distortions of competition that capacity mechanisms create. Further EU
harmonisation of adequacy assessments will help to increase transparency and
build confidence in the results of these assessments. The Commission's Market
Design Initiative therefore proposes to develop an enhanced EU-wide adequacy
assessment methodology, and annual adequacy assessments to be conducted by
the European Network of Transmission System Operators for Electricity.
(600) Fifth, the type of capacity mechanism chosen should suit the problem identified:
(i) Where a Member State identifies a long-term risk that there will be
insufficient investment, market-wide capacity mechanisms (like those
introduced in the UK and France, and planned in Ireland and Italy) are
likely to be the most appropriate form of intervention. Market reforms
should also be made to limit the State aid needed through the capacity
mechanism.
(ii) Where a Member State identifies a temporary risk, a strategic reserve is
likely to be the most appropriate form of intervention, as it is designed to
deal with situations where the market will deliver security of supply in the
longer term, but concerns exist about capacity in the short to medium
term. Strategic reserves should only be deployed in emergency situations.
They should be held outside the market to minimise distortions to its day
to day functioning. Strategic reserves must be transitional measures,
which accompany market reforms and are phased out as soon as the
reforms take effect.
(iii)Where a Member State identifies a local generation adequacy issue, the
choice of mechanism will depend on the specific market conditions. In the
long run however, the local problem should be solved by better grid
connections or by more appropriate bidding zones that introduce local
electricity prices reflecting the balance of local supply and demand .
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(iv) Where a Member State is concerned about insufficient development of a
flexible demand side, an interruptibility scheme can be an appropriate
solution, though attention must be paid to avoid the scheme developing
into a subsidy for energy-intensive industries.
(v) Administrative capacity payments are unlikely to be appropriate,
regardless of the specific issues facing a Member State, because the lack
of a competitive process means a high risk of failing to achieve the
capacity objective or of over-compensating.
(601) Sixth, capacity mechanisms should be open to all types of potential capacity
providers. This, combined with a competitive price-setting process, ensures that
competition minimises the price paid for capacity. The only exceptions are
mechanisms for demand response, given their particular ability to address
underlying market failures, and strategic reserves, which should not be open to
new generation capacity to minimise market distortions.
(602) Seventh, market wide capacity mechanisms must be open to explicit cross-border
participation in order to minimise distortions to cross-border competition and
trade, ensure incentives for continued investment in interconnection and reduce
the long-term costs of European security of supply.
(603) Finally, the sector inquiry has shown that a number of capacity mechanisms
already exist and that they do not all comply with State aid rules. The
Commission will work with Member States to bring all existing capacity
mechanisms gradually into line with State aid rules, bearing in mind the
conclusions of the sector inquiry. This will help to give certainty to capacity
providers and other economic actors, and ensure that the right signals are
provided to investors.
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A
NNEX
1: O
VERVIEW OF RESPONDENTS
1. Replies to first
round of eQuestionnaires (21 May - 24 June 2015)
1.1. Overview of respondents to the
first round of eQuestionnaires
7
9
4
15
France
Poland
Spain
15
11
Belgium
Germany
Ireland
12
15
Italy
Sweden
12
12
12
Denmark
Portugal
Croatia
1.2. Breakdown – type of respondents per Member State
1
5%
1
5%
Replies in BE
Generation
4
20%
6
30%
Demand response
Supply
Trading
4
20%
4
20%
Power exchange
Storage
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1
3%
1
3%
1
3%
Replies in DE
Generation
4
13%
3
9%
4
12%
6
19%
Supply
Trading
Demand response
6
19%
6
19%
Association
Storage
Distribution
Interconnector
Power exchange
Replies in DK
1
6%
1
7%
Generation
4
27%
Supply
Demand response
Trading
3
20%
4
27%
Association
Power exchange
2
13%
1
2 3%
6%
3
8%
4
11%
7
20%
Replies in ES
Generation
10
29%
Supply
Trading
Association
Distribution
8
23%
Storage
Demand response
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1
3%
2
7%
2
7%
1
3%
Replies in FR
Demand response
7
23%
Generation
Supply
Trading
6
19%
6
19%
Association
6
19%
Storage
Interconnector
Power exchange
Replies in HR
1
20%
1
20%
Generation
Interconnector
Supply
1
20%
1
20%
1
20%
Trading
Other
Replies in IE
1
6%
2
12%
3
19%
3
19%
4
25%
Generation
Association
Demand response
Trading
3
19%
Supply
Storage
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1694399_0174.png
2
6%
1
3%
1
3%
Replies in IT
Generation
8
25%
Supply
Trading
Demand response
Interconnector
7
22%
3
9%
3
10%
7
22%
Storage
Association
Distribution
1
4%
2
8%
4
15%
Replies in PO
Generation
8
31%
Trading
Supply
Demand response
5
19%
Association
6
23%
Power exchange
Replies in PT
1
8%
1
8%
3
25%
4
34%
Generation
Supply
Trading
Demand response
3
25%
Storage
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2
9%
1
1 4%
4%
1
4%
Replies in SE
Supply
Generation
6
26%
Trading
Distribution
Demand response
Association
2
9%
5
22%
5
22%
Power exchange
Storage
2. Replies to public consultation of Interim Report
(13 April – 6 July 2016)
Individual replies:
2
3
1
Energy companies*
RES producers
Large consumers
3
2
3
18
Power exchange
Private persons
Manufacturers
Academics
* involved in generation, supply, trade, DSR and/or storage
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Associations/Interest organisations:
1 1
2 2 2
EU**
Energy industry associations***
14
21
Consumer/EIU associations
RES/cogen + green/climate
DSR
Manufacturers
Raw materials (coal, gas)
19
other°
** ACER/CEER (joint reply) and ENTSO-E
*** Associations of generators, suppliers, traders, DSR and/or storage providers, incl.
public utilities
° Friends of the Supergrid & Regulatory Assistance Project
Public bodies:
1
6
Government
TSO/IC
13
Regulator/NCAs
3. Replies to second
round of eQuestionnaires (29 June - 19 August 2016)
Public bodies (Government, TSO, NCA and/or regulator) from all 11 Member States
covered by the inquiry replied to the follow-up eQuestionnaire. No breakdown is given
since many public bodies provided joint replies.
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A
NNEX
2: T
HE
PARTICIPATION OF INTERCONNECTORS AND FOREIGN CAPACITY
PROVIDERS IN CAPACITY MECHANISMS
1.
Introduction
This annex examines and aims to establish a potential design for effective cross-border
participation in capacity mechanisms. The analysis presented here was originally
discussed with Member States in June 2015, and was publically consulted as part of the
sector inquiry.
The sector inquiry has found that cross-border participation is not yet enabled in the
majority of capacity mechanisms, and with different Member States developing different
solutions for their already different national capacity mechanisms there is an emerging
risk of increasing fragmentation in the market.
166
The outcome of the working group with
Member States is therefore presented below to stimulate discussion and support the
development of solutions that can mitigate this risk.
This annex compiles the requirements in the Guidelines on State aid for environmental
protection and energy (EEAG) related to the participation of interconnectors and/or
operators in other Member States in capacity mechanisms, and recaps the importance of
this aspect of capacity mechanism design (sections 1 and 2). Section 3 describes the
challenges to accessing reliable capacity across borders, and section 4 identifies some of
the main design questions that must be addressed by a Member State seeking a solution.
Section 5 considers the possible benefits of a more harmonised approach to this issue and
presents the potential high level form that common rules could take and some of the
questions that would need to be addressed to further develop such an approach. Given the
number of Member States currently seeking to develop solutions for cross-border
participation in volume based market wide mechanisms (France, Ireland, Italy and UK)
the discussion in the working group and this paper focus primarily on the challenge of
enabling cross-border participation in the central buyer and de-central obligation capacity
mechanism types
167
. However, the other capacity mechanism models are also briefly
discussed in section 6.
2.
What do the guidelines require?
The EEAG include the following requirements related to cross-border participation in a
generation adequacy measure:
(226) The measure should…take into account to what extent interconnection capacity
could remedy any possible problem of generation adequacy.
166
167
See sections 5.2.2.6, 5.2.3.6, 5.2.3.7 and 5.2.3.8 of the Staff Working Document.
For a description of different capacity mechanism types, see Chapter 3 of the detailed sector inquiry report.
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(232) The measure should be designed in a way so as to make it possible for any
capacity which can effectively contribute to addressing the generation adequacy
problem to participate in the measure, in particular…
(a) the participation of…operators offering measures with equivalent technical
performance, for example…interconnectors.
(b) the participation of operators from other Member States where such
participation is physically possible in particular in the regional context, that is
to say, where the capacity can be physically provided to the Member State
implementing the measure and the obligations set out in the measure can be
enforced (footnote: schemes should be adjusted in the event that common
arrangements are adopted to facilitate cross-border participation in such
schemes).
(233) The measure should:
(a) not reduce incentives to invest in interconnection capacity;
(b) not undermine market coupling, including balancing markets.
Figure A2.1: Summary of EEAG requirements related to the cross-border
participation
Summary
EEAG requirement
(226)
Objective
1. Should take the contribution of interconnection into
account.
2. Should be open to interconnectors if they offer equivalent
technical performance to other capacity providers.
3. Where physically possible, operators located in other
member states should be eligible to participate.
(233)
4. Should not reduce incentives to invest in interconnection,
nor undermine market coupling.
(232)
Source: European Commission
3. Aim of these requirements
The more participation in a capacity mechanism, the more competitive it should be and
therefore the higher the chance that the mechanism provides value for money for
consumers. This is why the EEAG include a general requirement for all types of capacity
provider to be able to participate in capacity mechanisms.
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If the contribution of imported electricity is not taken into account when capacity is
procured through national capacity mechanisms, this would result in significant
overcapacity. Note overcapacity will also result if the participation of cross-border
capacity is not fully enabled
168
.
If cross-border participation in capacity mechanisms is not enabled, there will be greater
distortion of the signals for where new capacity should be built, and an increase in
overall system costs. And capacity mechanisms will fail to adequately reward investment
in the interconnection that allows access to capacity located in neighbouring markets.
If cross-border participation is enabled by requiring physical delivery of electricity into a
particular market, or capacity payments are made (or penalties related to non-delivery are
levied) per MWh to generators participating in a capacity mechanism, there is a risk that
the market coupling rules (which ensure the most efficient use of interconnection) are
undermined. There is also a risk of distorting the merit order in neighbouring markets.
Therefore the aim of these requirements is to maximise competition in capacity
mechanisms, ensure efficient signals for investment in the right overall level of capacity
in the Single Market, and in the right types of capacity and network infrastructure where
they are most needed, and enable market coupling to continue to deliver the most
efficient use of existing resources in real time.
For the findings of the sector inquiry on the importance of cross-border participation in
capacity mechanisms, please see section 5.2.3.6.
4. Background
4.1. Where does electricity flow at times of scarcity
169
?
In synchronous electricity networks, such as that in continental Europe
170
, electricity
flows to where it is demanded as long as the underlying network is strong enough. EU
wholesale electricity markets are arranged into bidding zones, within which supply and
demand is matched to create a single bidding zone price. These bidding zones should
reflect the capacity of the underlying network to transport electricity. Within each
168
169
170
The net benefits of avoiding self-sufficiency and making efficient use of the
Single Market
for security of
supply have been estimated at up to EUR 7.5bn per year in the period 2015-2030. See Booz & Co, 2013, 'Study
on the benefits of an integrated European energy market':
https://ec.europa.eu/energy/sites/ener/files/documents/20130902_energy_integration_benefits.pdf
Throughout this annex the term 'scarcity' is used to indicate a situation in which a bidding zone has insufficient
supply to meet demand. In a bidding zone where a capacity mechanism is in operation, the term also implies a
situation in which contracted/certified capacity resources are required to meet their capacity obligations and there
is the potential for penalties to apply.
Alongside the continental European synchronous system, Norway, Sweden, Finland and part of Denmark operate
a synchronous system, Great Britain operates as a synchronous system, as does the island of Ireland (Ireland and
Northern Ireland). Latvia, Lithuania and Estonia are currently part of the same synchronous system as Russia,
Ukraine and Belarus.
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1694399_0180.png
bidding zone market participants are allowed to contract power with any capacity
provider without limitations – i.e. without accounting for any network constraints that
might impact the ability to transfer power between sellers and buyers within the bidding
zone.
Bidding zones in the European Union are being 'coupled', in line with the target model.
Market coupling aims to ensure the interconnectors that link bidding zones are used most
efficiently to send power between markets to where demand is greatest.
Most of Europe is now coupled day ahead with implicit allocation of cross-border
transmission capacity. This means that prices and interconnector flows are jointly
determined in a single step, for each hour of the following day. This is established
through the matching of bids and offers across the power exchange/s operating in
Europe. Roughly characterised, the prices for each hour in neighbouring markets are then
compared, and the capacity of interconnectors is used to allow power offered in the lower
priced zone to be matched with bids in the higher priced zone until either the prices in the
two zones converge, or all available interconnection capacity is exhausted.
The Commission Guideline on Capacity Allocation and Congestion Management, which
came into force in mid-August 2015, obliges each Member State to develop market
coupling rules for day-ahead markets as well as intraday markets
171
.
This price-matching process creates flow schedules for the interconnectors in real time.
As intraday market coupling is introduced this will adjust any day ahead scheduling to
reflect any differences in prices that emerge in intraday trading.
171
http://eur-lex.europa.eu/legal-content/EN/TXT/?qid=1445614788889&uri=CELEX:32015R1222
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Figure A2.2 – Day ahead market coupling status in November 2015
Participants in coupled markets will continue to be able to buy hedging products: called
'physical transmission rights' (PTRs) and financial transmission rights (FTRs)
172
.
Physical transmission rights will enable the holder to nominate a flow on the relevant
interconnector at the day ahead stage. However, if this nomination is for a flow from a
higher priced zone to a low priced zone and the price difference is sufficient, the market
coupling algorithm will reallocate the full interconnector capacity (including the
nominated amount) to flow power from the low to the high priced zone.
Financial transmission rights allow the holder to be paid the difference in price between
two coupled markets, but do not give any nomination right or allow the holder to
influence the flow of energy between coupled markets.
Although EU rules require TSOs to resolve network congestions without limiting
commercial transactions (including across borders), TSOs can under certain conditions
curtail nominations to preserve system stability
173
. Also relevant is Article 4(3) of the
Security of Electricity Supply Directive
174
, which states that 'Member States shall not
discriminate between cross-border contracts and national contracts'. This rule requires
172
173
174
These will be defined in the guideline network code on Forward Capacity Allocation.
See Article 16(3) of the Regulation (EC) No 714/2009 of the European Parliament and of the Council on
conditions for access to the network for cross-border exchanges in electricity of 13.7.2009.
Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006.
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TSOs to allow market coupling to determine flows, even if this means that in a situation
where two coupled markets are both facing scarcity, the result of market coupling could
be more severe scarcity in one country or zone because the price of electricity is higher in
the neighbouring zone
175
.
Market coupling is an effective way of ensuring the most efficient use of interconnection,
but creates a certain challenge for enabling foreign participation in capacity mechanisms
in Europe, because interconnectors have no influence over which direction power flows
between markets, and individual capacity providers in a coupled market have very little
influence on which direction power flows. With market coupling, it is not possible for a
generator or demand response provider in a neighbouring zone to guarantee that its
power will flow to consumers in another bidding zone. Under market conditions
176
,
power will flow to the bidding zone which offers the highest electricity price
177
.
4.2. Which resources provide capacity across borders?
As explained in section 5.2.2.6 of the detailed sector inquiry report, the contribution
foreign capacity makes to a neighbour's security of supply is provided partly by the
foreign generators or demand response providers that deliver electricity, and partly by the
transmission (interconnection) allowing power to flow across borders. Depending on the
border, there can be a relative scarcity of either interconnection or foreign capacity.
This further complicates the design of an efficient solution for enabling cross-border
participation in capacity mechanisms since it requires the chosen design to enable an
appropriate split of capacity remuneration between interconnector and foreign capacity to
reflect the relative scarcity of each. It also ideally requires this split to adapt over time –
for example through a design that increases the reward for foreign capacity and reduces
the reward for interconnection if over time the proportion of interconnection increases.
175
176
177
Curtailments of cross-border flows are nevertheless frequent, see ACER Monitoring Report 2014, page 162
(observing limitations of cross-border interconnection to solve internal congestion at 56% of all interconnectors).
In its market design initiative and when developing network codes the Commission will further specify the
framework for when Member States or TSOs can intervene in market transactions in response to emergency
situations.
In emergency situations, Member States may intervene in the market-based coupling process and curtail cross-
border flows; solutions for this situation are being developed in the framework of the
market
design
initiative.
Once capacity mechanisms are introduced they will reduce the extent to which local electricity prices remunerate
capacity. Capacity will be fully or partially rewarded separately through capacity payments.
The extent of this impact depends on how the capacity mechanism is designed. If a capacity mechanism acts as a
replacement for high electricity prices at times of scarcity, there will not be an efficient signal for imports to the
capacity mechanism zone at times they are needed. Nor will there be an efficient incentive for demand response
participation in the electricity market outside the capacity mechanism. Distortions can be reduced by ensuring
that the electricity market continues to function effectively even if a capacity mechanism is introduced.
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5. Main design options – overview
5.1. Consideration of imports in the generation adequacy assessment
When the demand requirement is set in a capacity mechanism, the total capacity
demanded can be adjusted to account for expected imports (at times of scarcity). This is
sometimes called 'implicit participation'. This reduces the risk of domestic over-
procurement and recognises the value to security of supply of connections with the
Single Market for energy. However EEAG 232 requires explicit cross-border
participation (see 4.2 below). Implicit participation does not remunerate foreign capacity
for the contribution it makes to security of supply in the capacity mechanism zone. If
only domestic capacity receives capacity payments, there will be a greater incentive for
domestic investment than investment in foreign capacity or interconnectors resulting in
less than optimal investment in foreign capacity and in interconnector capacity.
For the GB Capacity Market (SA.35980), the UK used implicit participation for the first
year of operating the mechanism, but the approval of the scheme included a commitment
that from the second (2015) auction interconnected capacity would be able to directly
participate in the Capacity Market. In the second auction that took place in December
2015 interconnectors were admitted and were secured 1.8 GW of capacity agreements,
corresponding to approximately 4% of the total auctioned capacity
178
.
5.2. Explicit cross-border participation
If the locational investment signals are to be corrected, the contribution of imports to the
capacity mechanism zone must not only be identified, but the providers of this foreign
capacity need to be remunerated for the security of supply benefits that they deliver to the
capacity mechanism zone. This requires the 'explicit participation' of foreign capacity in
the capacity mechanism.
This section considers four aspects of design that need to be considered in an explicit
participation solution:
Identifying the amount of foreign capacity that can participate / receive
remuneration, through establishing the contribution of potential interconnector
and foreign capacity participants.
Designing the obligations and penalties that will apply to interconnector and
foreign capacity participants.
Identifying the counterparty for a cross-border capacity contract – ie.
interconnectors, foreign capacity providers, or both could be signed up to capacity
contracts.
178
National Grid, 'Provisional Auction Results: T-4 Capacity Market Auction for 2019/20', Figure 4.
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If foreign capacity providers are to participate, which foreign capacity providers
should be eligible?
5.2.1 Establishing the contribution of interconnectors and foreign capacity
The EEAG require the inclusion of foreign capacity 'where the capacity can be physically
provided to the Member State implementing the measure'. It may therefore be justifiable
to exclude providers if it can be shown that their location means they could never be
expected to deliver the required service. Effective cross-border participation requires an
evaluation of the expected actual contribution of a capacity provider at times when it is
required. This evaluation is often referred to as 'de-rating'.
If cross border capacity is the counterparty, unlike for domestic capacity
179
the
required evaluation would include assessing not just the capacity provider's
ability to provide electricity when needed, but also their access to interconnection
capacity.
If interconnectors participate directly as a counterparty then their available
capacity needs to be calculated.
Calculation of the availability of interconnection capacity is critical as conservative
assumptions will lead to overcapacity, and overly generous assumptions could lead to
adequacy standards not being met.
The technical capacity of interconnectors represents the maximum amount of power
which can flow through the interconnector at any one time. There is always some
probability that this will not be available – either because of the technical availability of
the interconnector, and/or because the technical capacity of the interconnector can be
used to flow electricity both as imports to the capacity mechanism zone, but also as
exports from the capacity mechanism zone, depending on the balance of supply and
demand in the zones connected by the interconnector. Therefore it may be necessary to
de-rate the interconnectors according to expected contribution to the capacity mechanism
zone at times when imports are needed to avoid scarcity
180
.
However, interconnectors can flow power in two directions, and the same generation (or
demand response) assets can contribute to security of supply in two regions if peak
demand occurs at different times. In fact this is one of the chief security of supply
benefits of the Single Market. Conversely, if peak demand occurs at the same time, the
179
180
Though domestic capacity also requires domestic network access.
Note an alternative capacity mechanism design might enable participants to 'self de-rate' rather than relying on
central de-rating. Such a design may require high penalties with no or very limited exceptions and a robust
testing regime to avoid participants selling more capacity than they could reliably provide, but could avoid the
difficulty of centrally establishing appropriate de-rating.
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generation (or demand response) assets can only benefit one of the regions (see Box A2.1
for a more detailed explanation).
It is in consumers' interest to ensure the full value of interconnection is taken into
account, otherwise excess capacity will be built across Europe at unnecessary cost. De-
rating of resources across borders will likely require good cooperation between TSOs,
and common rules or guidance on de-rating of interconnectors may be required. It may
be necessary to task ENTSO-E with establishing common principles for de-rating and the
appropriate methodology for calculating suitable capacity figures for each border.
It may also be necessary to task ENTSO-E with coordinating work to establish common
rules for the de-rating of foreign capacity resources for the purpose of participation in
capacity mechanisms, so that a MW of capacity in each country/zone is comparable.
In addition, to ensure judgements about the level of imports that can be expected are not
overly conservative, it may be necessary to define common rules for all TSOs to apply in
scarcity and emergency situations, and for example exactly what procedures are followed
when there is concurrent scarcity in two neighbouring markets. This work also appears
essential to prevent any contradiction between TSOs' rules and the requirements of EU
law in relation to cross-border electricity trading.
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Box A2.1: How much do interconnectors contribute to security of supply?
The interconnector's technical availability is one important consideration (ie. is the line
itself operational or not?). The long term average technically available capacity of the
interconnector could be identified and offered to participants seeking to sell capacity into
a cross-border capacity mechanism
181
. This de-rating should reflect the extent to which
the interconnector is expected to be unavailable for maintenance or otherwise technically
unavailable at times of scarcity.
However, the extent to which an interconnector can reliably provide imports to the
countries it connects depends not just on the line's technical availability but also on the
potential for concurrent scarcity in the connected markets.
If zone A only has a winter peak demand problem and connected zone B only has a
summer peak demand problem, each may expect 100% imports from the other at times of
local scarcity. However, if countries A and B are neighbours with similar demand
profiles and some similar generation types there may be some periods of concurrent
scarcity where neither can expect imports from the other.
Where two connected markets both operate capacity mechanisms, one approach would
be to take the full capacity of the interconnector and allocate it between the two
connected capacity mechanisms. This would enable capacity providers to make a choice
between participation in either their domestic capacity mechanism or a neighbouring one.
For example, if there was a 2 GW link between zone A and zone B, 1.5 GW of capacity
could end up being sold to providers located in B wishing to participate in the capacity
mechanism of zone A, and 500 MW to providers located in A wishing to participate in
the mechanism of zone B.
The problem with this approach is that, with the two markets considered together as a
system, the interconnector is assumed to make a net zero contribution to security of
supply. In this situation, the domestic capacity demanded in the national capacity
procurement process in zone B would be increased by 1 GW to compensate for the net
capacity contracted to deliver cross-border to zone A. This would only be an efficient
outcome for the system if zone A and zone B always experienced coincident scarcity and
the interconnector indeed delivered no net security of supply benefit.
In practice, however, it is extremely unlikely that scarcity events will be perfectly
correlated between two neighbouring countries. So, to avoid a situation where overall
less value contribution by imports to security of supply is assumed for imports than is
truly the case, a statistical judgement – de-rating of the interconnector/s on each border to
reflect expected maximum long-run average import capacity at times of scarcity – is
181
The interconnector's technical availability must already be assessed in the context the CACM Regulation, where
tradeable capacities for the different market timeframes are determined in a comprehensive way.
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needed for each capacity mechanism about the value of imports at times of scarcity. The
amount of capacity demanded domestically should be reduced by this amount, and this
capacity is then available for allocation to foreign capacity providers.
5.2.2 Obligations and penalties for interconnector / foreign capacity
As discussed in section 5.4 of the detailed sector inquiry report, there are various ways of
designing obligations and penalties in a capacity mechanism.
Capacity providers may be required to either be available by declaring that they are
available to the TSO, or by placing a bid to deliver electricity, or they may be required to
verify their availability by actually delivering electricity regardless of whether the market
price is sufficient to cover their running costs. For cross-border capacity, a delivery
requirement could require a foreign capacity provider to deliver electricity into its local
market, or it could require that capacity provider to deliver electricity in its local market
and require the interconnection between the two markets to be sending electricity
towards the market where the capacity mechanism is operating. With market coupling in
operation, however, it is clear that an individual foreign capacity provider will in most
cases have a very minor influence on the direction of flows across an interconnector (and
the interconnector operator would have no influence over the flow direction).
Different capacity mechanisms also apply different penalties when obligations are not
met. They could apply a flat rate financial penalty, for example, or a penalty linked to the
value of lost load. Over delivery payments may also apply – as is increasingly seen in US
markets operating the 'pay for performance' principle.
In principle, if the allocation process for capacity contracts allows interconnector or
foreign capacity to compete directly with domestic capacity, the obligation and penalties
faced by the interconnector or foreign capacity providers should be the same as the
obligations and penalties faced by the domestic capacity providers.
However, there are issues with imposing obligations and penalties on interconnectors or
foreign capacity providers. In particular, in coupled markets even if foreign capacity
providers face additional incentives from a capacity mechanism to deliver capacity into
their local market, in most cases this will not significantly increase the chances of
delivery in a particular direction across a constrained interconnector.
Any obligations, penalties or over delivery payments that result in the delivery of
capacity that would not otherwise have delivered may impact on market coupling. For
example, if a generator in zone B is penalised if not delivering energy into zone B
whenever there is scarcity in zone A, this means that generator's decision to run is no
longer based only on its marginal costs and the price of electricity in zone B. It is also
based on the cost of the penalty that will be levied by the zone A capacity mechanism if
it does not produce. This could create additional distortions since it may mean this plant
runs out of merit, displacing other plants in the local merit order.
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In practice, in a situation where there is scarcity in zone A and the possibility of penalties
for capacity providers located in zone B participating in zone A's capacity mechanism,
the price in zone A should rise high enough to ensure the interconnector flows 100% in
the direction of zone A. In this situation a delivery obligation on the capacity providers in
zone B would have no impact.
Some obligations, testing and penalties may still be required to ensure that foreign
capacity is at least a verifiable and reliable source of capacity in its local market. But
because of the potential for delivery obligations to create distortions and the fact that
anyway such obligations can only incentivise actions which are likely to have a very
limited effect on cross-border flows, delivery obligations may not be appropriate for
interconnectors or foreign capacity. Establishing a relatively simple availability product
instead makes cross-border participation much more readily implementable and avoids
creating distortions to merit order dispatch that might be created with delivery
obligations.
Another issue that will arise with cross-border participation is the need to levy penalties
on foreign resources. There appear to be various ways in which this could be enabled, for
example through an appropriate governance regime tied to the agreement to participate in
the capacity mechanism.
5.2.3 Counterparty for a cross-border capacity contract
The Third Energy Package and EU Network Codes require that interconnectors are
treated as transmission capacity, and fully unbundled, and that the flow of energy across
borders is determined solely by electricity price differences. Member States are however
considering explicit participation designs that enable the direct participation of
interconnector operators, foreign capacity, or a combination of the two.
As identified in the sector inquiry and explained in section 3.2 of this annex, an efficient
design for cross-border participation should ensures the revenues from the capacity
mechanism that end up being paid to the interconnector and the foreign capacity reflect
the relative contribution each makes to security of supply in the zone operating the
capacity mechanism.
Including foreign capacity providers directly in a capacity mechanism can reveal the
value (from a generation adequacy perspective) of additional interconnection capacity.
For example, if a zonal auction for capacity in a neighbouring zone cleared at a lower
level than the main capacity auction, the difference between the two clearing prices
would reflect the value of increased interconnection capacity between the two zones.
Member States should ensure that interconnection investment reflects these signals. This
could be achieved by rules ensuring that the interconnector could receive the difference
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between the zonal capacity prices
182
. This would mean that the principle of separation of
generation and supply from network operation could be maintained. Competition should
ensure that if there is plentiful supply of cheap capacity in the neighbouring market
relative to the amount of interconnection, then the interconnector receives most of the
capacity revenue – sending signals for investment in more interconnection.
183
If capacity contracts are awarded directly to an interconnector operator, the extent to
which foreign capacity is appropriately rewarded may depend on the obligations and
penalties associated with the capacity contract. With a delivery obligation (obligation for
power to flow to the capacity mechanism zone at times of scarcity) and high enough
penalties, the interconnector may seek to contract with capacity providers in the
connected market to pass on the delivery risk to counterparties better able to manage this
risk (since the interconnector operator has no control of the direction in which electricity
flows) and capacity providers in the connected market at least have some influence
(though this may also be marginal)
184
. However, in a model with interconnectors as a
counterparty with a capacity payment for availability and no delivery obligation (or
obligation to 'subcontract' with foreign capacity providers) it is not clear how appropriate
revenues would be awarded to foreign capacity providers. In this model, it seems likely
that all the capacity revenue would accrue to the interconnector itself, regardless of the
relative scarcity of interconnection and foreign capacity.
In some situations there may be a justification for including interconnectors as a
counterparty – for example, where there is a very large supply of foreign capacity and the
interconnector is clearly the scarce resource. Some respondents to the public consultation
– particularly TSOs that control transmission capacity – felt that an interconnector-led
participation model would in practice tend to deliver the same outcome as a model where
foreign capacity participates and would offer benefits in terms of increased simplicity.
But the concern in the previous paragraph, combined with the potential distortions of
imposing delivery obligations across borders (see section 4.2.2 of this annex), probably
means that the most efficient solution would require foreign capacity to participate
directly across borders, rather than the interconnector participating.
182
183
184
Just as for congestion rents earned where electricity prices differ in neighbouring interconnected markets. For
regulated interconnectors, any capacity congestion rents earned would need to be appropriately regulated (eg.
refunded to consumers in the connected markets if the interconnector's revenues – including the capacity
revenues – are above its regulated cap). See Regulation 714/2009 Articles 16 and 17.
If there is abundant interconnection capacity and not much foreign capacity available, the foreign capacity would
receive the bulk of the capacity revenues – sending signals for increased investment in foreign capacity.
Likewise, if capacity can be most efficiently provided by building more domestic capacity this should be the
outcome – signalled by the foreign capacity bidding too high to be competitive in the neighbouring capacity
mechanism.
In addition, any such hedging by interconnector operators may be challenging to enable in compliance with the
restrictions on trading activity by interconnector operators under the rules of the third package. See Directive
2009/72/EC Chapter IV.
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5.2.4 Which foreign capacity providers should be eligible?
In principle the same eligibility rules as apply in the domestic market should apply to
foreign capacity – with foreign demand response and storage eligible to compete
alongside generation
185
.
A major question to address is whether capacity providers should be able to offer
capacity into more than one capacity mechanism for the same time period. Limiting
participation to a single mechanism might at first sight appear to be necessary, and some
respondents to the public consultation – particularly generation companies – argued that
capacity resources should only be allowed to participate in a single mechanism. This
approach would however lead to system-wide over procurement if every zone in the
system operates a capacity mechanism (assuming the capacity mechanisms require
people to fulfil a capacity obligation at any time for eg. the winter, or for the whole year).
This example illustrates the problem:
Zone A wants to buy 10 GW of capacity. It wants it to be available all year.
Zone B wants to buy 10 GW of capacity. It wants it to be available all year.
There is 5 GW interconnection between these two zones.
Zone A identifies that it can count on 4 GW of imports from B at times of
scarcity in A.
Zone B identifies that it can count on 2 GW of imports from A at times of
scarcity in B.
Zone A procures 10GW of capacity. It might procure up to 4 GW of this from
zone B if the capacity there is cheaper.
A month later, Zone B procures 10 GW of capacity. If participation was only
allowed in one capacity mechanism, Zone B could only procure the 10 GW from
resources that have not contracted to provide capacity to zone A.
The total capacity procured by A+B would be 20 GW. So unless there was
perfectly correlated scarcity between A and B there would be over procurement.
Also, if both countries had an equally attractive capacity mechanism then in
practice there would probably be no cross-border participation.
185
Harmonised rules for de-rating, baselining, testing and verifying demand response may need to be developed to
enable this although we recognise that this is difficult even at national level as individual DNOs often have their
own procedures.
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Therefore, to avoid system-wide over procurement, the participation of capacity
providers in more than one capacity mechanism for the same time period must be
enabled.
Concerns about the potential for a lack of reliability stemming from multiple
participation should be mitigated by the initial de-rating that sets a maximum level of
participation on each border, and also by the need for multiple penalties to also apply to
encourage participants to make a rational judgement about whether they want to take on
overlapping capacity obligations.
5.3. Conclusions
Although it mitigates some negative effects, simply accounting for imports when
establishing demand for capacity does not actually enable cross-border
participation in a capacity mechanism.
Cooperation between TSOs may be needed to establish common rules for
adequately de-rating cross-border resources and calculate transmission capacities
for cross-border participation in CRMs.
Common and transparent rules for Member State and TSO actions in scarcity and
emergency situations are required to avoid the current lack of trust about the
potential for imports at times of concurrent scarcity.
Availability obligation models probably do not distort market coupling, nor distort
foreign markets (except possibly for some distortions due to any required testing).
With the interconnector as counterparty, it is not clear that an availability model
delivers appropriate revenues to foreign capacity providers.
The most appropriate design choices may therefore be to enable foreign capacity to
participate directly, with availability rather than delivery obligations imposed on
the foreign capacity providers and the interconnector operator.
To avoid system-wide over procurement, capacity providers must be able to
participate in more than one capacity mechanism for the same time period.
6. Towards a common approach to integrate volume based market wide capacity
mechanisms
Designing appropriate rules for cross-border participation in capacity mechanisms is
challenging. Given the different capacity mechanism designs already emerging across
Europe, there may be value in developing common rules at least for cross-border
participation in these different mechanisms. Building on the design options presented
above, this section presents, a potential high level approach to cross-border participation
in capacity mechanisms.
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Although a harmonised capacity product used in each national capacity mechanism
would no doubt simplify the design challenge and potentially increase overall efficiency
by simplifying the range of rules investors, market participants, regulators and system
operators across Europe have to understand, a harmonised product is not necessarily a
pre-requisite for cross-border participation in capacity mechanisms. However, a
harmonised set of principles or rules specifically for cross-border participation, including
defining a common product to account for the capacity to be supplied from neighbouring
markets may be required to facilitate cross-border participation
186
.
Although there would be a cost to the time spent developing and implementing such a
proposal, it could deliver a number of benefits, for example:
i)
reducing complexity and the administrative burden for market participants operating
in more than one zone.
ii) removing the need for each MS to design a separate individual solution – and
potentially reducing the need for bilateral negotiations between TSOs.
iii) enabling the link with market coupling to be addressed jointly – and ensuring the
rights of MS with and without CMs are protected.
iv) leaving market coupling and all the work on the target model intact and ensuring that
the distortions of uncoordinated national mechanisms are corrected and the Single
Market able to deliver the anticipated benefits to consumers.
6.1. High level approach
One way to achieve the above benefits could be to:
a) Define the way in which the amount of imports that can be relied upon at times of
scarcity in each zone operating a capacity mechanism should be calculated
(interconnector de-rating);
b) Identify the capacity providers that could be eligible to provide capacity into a
capacity mechanism in a neighbouring market;
c) Define the obligations and penalties that would apply to those who hold capacity
contracts in relation to a capacity mechanism in a neighbouring market;
d) Define a competitive process for offering this import capacity to eligible capacity
providers;
e) Define rules for the trading of this import capacity once allocated;
186
Note such a product would not necessarily match the product contracted in the different capacity mechanism/s
connected by these common rules.
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f) Define any obligations and penalties applicable to the interconnector operator,
including rules on the enforcement of penalties across borders;
g) Influence flows in the direction of the capacity mechanism if market coupling
cannot deliver sufficient certainty;
h) Allocate the costs of foreign capacity to consumers;
i) Appropriately remunerate the interconnectors that enable the participation of
cross-border capacity; and
j) Ensure compliance of TSOs.
Market-based rules for participation in capacity mechanisms should complement
European rules for effective coordinated management of actual simultaneous
physical
scarcity situations in the grid.
Following the analysis in the first half of this annex, the presented model is based on
foreign capacity providers participating directly across borders, rather than involving the
direct participation of interconnection. In addition, the capacity product is based on
availability rather than delivery.
a) Interconnector de-rating
As explained in section 4.2.1 of this annex, a statistical judgement – de-rating of the
transmission capacity across each border to reflect expected maximum import capacity at
times of scarcity – is needed for each capacity mechanism. The amount of capacity
demanded domestically would be reduced by this amount, and this capacity is then
available for allocation to foreign capacity providers.
b) Eligible foreign capacity providers
The eligibility of foreign capacity, and any de-rating applied, could be decided based on
the criteria in the capacity mechanism for which capacity is being procured, or common
rules could be established. The determined eligibility in either case would need to meet
the requirements in the EEAG requiring all potential capacity providers to be able to
participate
187
.
As explained in section 4.2.4 of this annex, to avoid overcapacity in the system,
individual capacity providers could be eligible to offer their capacity into more than one
capacity mechanism for the same obligation period.
187
See
http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_working_group_4.pdf.
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1694399_0194.png
Common rules and methodology requiring TSO cooperation in the de-rating of capacity
in neighbouring markets are likely to be beneficial to ensure that a MW of capacity has
comparable value regardless of its location.
A common registry may be helpful to facilitate de-rating and any certification, pre-
qualification and testing of foreign resources, and could also facilitate secondary trading
of capacity contracts.
c) Obligations and penalties on foreign capacity providers
Given the potential distortions that could arise with a delivery obligation, the obligation
on capacity providers would likely need to be a relatively simple availability obligation.
Ideally, this would be developed in cooperation with the neighbouring TSO, however,
even without such cooperation suitable a suitable product definition might be found
enabling the verification of availability without requiring any obligations that might
introduce distortions to neighbouring markets. A local market bidding requirement might
be one way of enabling a foreign capacity provider to demonstrate that they have made
capacity available – though further consideration would be needed to determine exactly
how an individual plant bid might be distinguished from the bids of all generators in a
portfolio. Careful design of the availability obligation and no or very limited exceptions
to it, along with a clear set of procedures for cooperation (and any appropriate
remuneration) between TSOs for testing capacity resources would be required to ensure
the reliability of contracted resources (and avoid the problems encountered in US
markets with resources paid for availability and benefitting from various exceptions)
188
..
Following the de-rating rules described above, each participant would be required to
make available its full de-rated capacity in periods in which there was scarcity in the
foreign capacity mechanism.
In a model where capacity providers could choose to sell into more than one capacity
mechanism, the penalties that apply when they do not provide the contracted service
would serve an important function in ensuring participants have the right incentives to
participate – or not – in more than one mechanism.
A capacity provider that has sold capacity into the domestic capacity mechanism and a
foreign capacity mechanism would need to meet its obligation to both mechanisms to
avoid paying a penalty. Assuming the capacity provider is reliable, this could be possible
if scarcity events in the connected markets are not correlated, since the obligations would
not overlap. However, if a capacity provider has chosen to sell into two capacity
mechanisms and there is an hour of concurrent scarcity:
188
See section 5.4.2.3 of the Staff Working Document for more on this.
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1694399_0195.png
If they meet their domestic obligation, unless they also make available enough
capacity to the local market to meet their foreign obligation, they would need to
pay a penalty to the foreign capacity mechanism zone.
If they fail to meet their domestic and foreign obligations, they would need to pay
two penalties – one to the domestic capacity mechanism and one to the foreign
capacity mechanism.
The participation in more than one capacity mechanism, even if two penalties could be
applicable, raises a question about potential overcompensation. If there is no concurrent
scarcity, there is no overcompensation to these providers because they help resolve
scarcity in both / all markets. However, if there is concurrent scarcity, then with
insufficient penalties there is a risk of overcompensation to generators that sell into more
than one mechanism. And the general direction in capacity mechanism development
seems to favour verifiable physical capacity and relatively low penalties supported by
testing
189
, rather than high penalties.
However, any potential overcompensation should be eroded by competition – ie.
participants should be willing to commit to an additional capacity obligation at a low
price if the reward exceeds the risks. This should mean the price for foreign capacity
would be competed down to a low level and most of the revenue would go to the
interconnectors rather than the foreign capacity. If in fact the risk of concurrent scarcity
turned out to be higher than expected, the price in future should adjust so that a higher
share goes to the capacity providers. This should help ensure the allocation of capacity
value between interconnectors and foreign capacity providers would remain a reliable
signal of the relative contribution each makes to security of supply
190
.
Allowing capacity providers to participate in more than one mechanism would also act as
a way to reveal any overly conservative central assumptions that were made about the
chance of concurrent scarcity and therefore the level of imports that should be expected
across each border. However, the central determination of the maximum amount of
foreign capacity that can participate in a capacity mechanism plays an important role in
ensuring that the overall level of system security required by Member States is reached.
In other words, the level of security provided by the foreign capacity should not be
189
190
This seems to be for two reasons: i) political reasons, where there are suggestions that politicians responsible for
security of supply wish to have a verified / proven source of capacity contracted, rather than a capacity
mechanism potentially being open to financial market participants; and ii) to enable financing, since the potential
for high penalties may mean capacity contracts are less suitable as a basis for seeking financing.
There may also be an added benefit of relatively low capacity mechanism penalties in that they leave space for
the underlying electricity market to provide the main signal for flexibility (through high prices when electricity is
scarce). This enables the electricity market to continue to provide the import signals required for the efficient
operation of the
Single Market
.
In a system where capacity providers were only able to participate in a single capacity mechanism, competition
in this price setting process would be artificially constrained and the allocation of costs would be less reliable.
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affected by the possibility of capacity selling into multiple mechanisms because each
zone has in any case limited the amount of foreign capacity that can participate. The level
of security in a model with the potential for explicit participation of capacity providers in
more than one capacity mechanism is in fact the same as the level of security provided by
a statistical (implicit) approach to interconnector participation.
Any capacity obligation should be complemented by robust penalties for non-availability.
At a minimum, parties that consistently fail to meet their obligation should be able to lose
100% of any revenue earned through capacity contract payments (though this may not be
sufficient and higher penalties may be required, particularly to ensure participants make a
sensible judgement about the possibility of participating in more than one mechanism).
As a starting point for discussion, the penalty applicable to foreign capacity that fails to
meet its cross-border obligation could be set at the imbalance settlement price in the
capacity mechanism zone applying the penalty for each MWh not made available.
Capacity providers could reduce any penalty due by trading with other capacity providers
that are available and not delivering into the local capacity mechanism.
With different capacity mechanisms in Europe already applying different contract
lengths, it may not for the time being be possible to choose a single rule for cross-border
capacity that matches each current national model. However, short contracts for cross-
border participation would avoid fixing the remuneration between interconnectors and
foreign providers for long durations, and allow more easily for future adaptation or
removal of the cross-border participation model if required. It would also ensure that the
de-rating of an interconnector or the ‘expected imports’ from a particular market could be
updated annually to account for changing dynamics within that market and more closely
reflect the real contribution of imports.
More granular time-bound products may also be appropriate – for example to allow
capacity providers to deliver capacity for one period (eg. during summer but potentially
even for specific balancing periods) in one mechanism, and another period in another
mechanism. These more granular products could emerge through secondary trading.
d) Trading of cross-border capacity
Under the present approach, foreign capacity providers would be able to trade their
capacity contracts within the same bidding zone to allow them to manage risks of
changing circumstances (for example required maintenance or unplanned outages).
Foreign capacity providers would therefore be free to trade their contracts to other
eligible providers that have not already sold all of their (de-rated) capacity into the
relevant capacity mechanism (ie. the mechanism for which the contract is being traded).
Some kind of registry and/or notification procedure is likely to be required to enable this.
e) Obligations and penalties on interconnector operators
Under the present approach, interconnectors would have an obligation to be operational
(technically available) at times of system scarcity in either connected zone.
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Interconnectors have no control over the direction of flows on the interconnector so it
would not seem justified to penalise them if the flows over the interconnector are not
what was expected when the de-rating based on expected flows was carried out.
However, the risk of interconnector operational availability is mainly within the control
of the interconnector operator. If not technically available, they should therefore face the
same penalty as foreign capacity providers (and foreign capacity providers should not be
penalised in periods when the interconnector is unavailable).
Since interconnector operators would potentially be 'involuntary' participants in each
measure and would have no direct control over the capacity price they receive (since the
price left for interconnection would be determined by the voluntary bids of foreign
capacity providers to participate) it would be appropriate to cap the maximum penalties
that could be levied on interconnectors for lack of availability.
f) Competitive cross-border bidding process
The import capacity established for each interconnector (into each capacity mechanism)
could be competitively allocated in various ways:
explicit auction: where TSOs (or exchanges, or even the interconnector operators)
auction the available cross-border capacity in advance of any capacity allocation
process within a national capacity mechanism. Effectively, they would be
auctioning a ticket allowing entry into the related capacity mechanism, in the
same way as interconnector capacity can be auctioned explicitly – separately from
electricity. Those successful in the ticket auction would then be able to bid into
the capacity auction in the related capacity mechanism (if a central buyer model)
or offer their capacity in the market to suppliers needing to fulfil their obligations
(if a de-central obligation model).
implicit auction (central auction model): where foreign capacity bids directly into
a national capacity auction, which establishes a price for each cross-border
capacity zone. This is similar to the way interconnector capacity is implicitly
auctioned along with electricity in coupled markets.
implicit auction (de-central obligation model): where an auction is held in which
foreign capacity providers offer their capacity and domestic suppliers offer to buy
it. This could for example be hosted on an exchange.
direct selling to suppliers (only in a de-central obligation model): where foreign
capacity providers offer their capacity directly to suppliers in a capacity
mechanism seeking to fulfil their obligation. Exchanges may be able to help limit
trade to the maximum import capacity – for example if foreign capacity providers
were required to trade only on exchanges. Ensuring the interconnector operator
also receives remuneration for its service could be challenging in such a system.
It might be possible for the interconnector to offer a 'capacity rights' product on
an exchange, and for capacity providers to be required to simultaneously buy
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these capacity rights at the same time as an offer to provide capacity is accepted.
If the transactions cannot be concluded simultaneously some basis risk (see
below) will remain.
With an explicit auction, the gap between the entry ticket auction and the domestic
auction would create an additional risk ('basis risk') for participants, since when
competing in the ticket auction they would be uncertain about the value of capacity in the
system for which they were bidding to participate. This could result in a lower price
being bid for the entry tickets to compensate for this risk and/or reduced competitive
pressure, as this risk presents a barrier to entry.
An implicit auction appears likely to be the most efficient solution since it eliminates any
basis risk.
g) Influencing interconnector flows (without distorting market coupling)
Market coupling combined with more integrated balancing markets should ensure
electricity flows where it is needed in times of scarcity. Member States should take the
necessary steps to ensure market rules function in this regard by implementing the third
package, including applying network codes and ensuring balancing markets work
properly and electricity prices can rise to reflect scarcity.
In the event of a scarcity event in two Member States at the same time that brings prices
to in both markets to the market coupling price caps (currently 3000 EUR/MWh for the
purposes of day ahead market coupling and below most estimations of the value of lost
load) rules could be developed to enable electricity flows in proportion to cross-border
capacity contracts held rather than the current default of equal sharing of curtailment.
However this would only be appropriate as long as the market coupling price cap is
significantly lower than the value of lost load, as otherwise such a system would
discriminate against energy only markets.
h) Paying for foreign capacity
It would seem appropriate to pay foreign capacity in the same way as domestic capacity.
If foreign capacity participates through an implicit auction or directly through contracts
with obligated suppliers, this approach would appear straightforward. If it participates
through an explicit auction, financing arrangements would have to be designed to
allocate the costs to the suppliers (ultimately consumers) benefitting from the capacity
mechanism.
Any penalties paid by foreign capacity providers could be refunded to the suppliers that
paid for the capacity.
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i) Appropriately remunerate interconnectors
In a central buyer model where foreign capacity participates directly through an implicit
auction, interconnectors could be rewarded with the difference between the zonal
(foreign) capacity price and the overall (domestic) capacity clearing price.
In a de-central obligation model, the difference between an implicit auction clearing /
average price and a reference price for capacity in the domestic market would need to be
paid to the interconnector operators by the beneficiaries of the capacity mechanism.
Additional design questions arise from this since it would be necessary to collect this
money from consumers in the capacity mechanism zone and transfer it to the
interconnector operators. Alternatively, an explicit auction of entry tickets would allow
the interconnector to access revenues directly from the foreign capacity providers, but
would create inefficiency in the form of basis risk (as described in section 5.7 of this
annex).
Any penalties paid by interconnectors could be refunded to the suppliers that paid for the
capacity.
j) Ensuring compliance with the common rules
Despite existing legislation preventing interference to stop exports at times of scarcity
except in specific situations (see section 3.1 of this annex) some fear potential action by
Member States or TSOs to limit exports if necessary to prevent local unmet demand.
Irrespective of the validity of the argument, this is an issue that would need to be tackled
with or without capacity mechanisms. More harmonised, transparent protocols for TSOs
and clear rules for Member States to limit their interventions in cross-border flows could
avoid this problem along with appropriate sanctions for any infringement, to ensure
everyone has confidence that market coupling delivers electricity to higher priced zones.
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1694399_0200.png
7. Cross-border participation in other capacity mechanism types
7.1. Cross-border participation in strategic reserves
Unlike other capacity mechanisms that allow beneficiaries of capacity remuneration to
continue to compete in the electricity market, if strategic reserves are designed to truly
keep their capacity outside the market there may not be the same need to enable explicit
cross-border participation.
To avoid a distortion to cross-border flows (and the creation of missing money and
distortions to investment signals locally and in neighbouring markets) a strategic reserve
should in principle only be dispatched once all possibility for the market to deliver has
been fully tested and exhausted, the market price cap has been reached because there is
still unmet demand, and there is no more potential for imports. To avoid cross-border
distortions once intraday markets are coupled, this would mean that a strategic reserve
could only be dispatched after gate closure when all possibility for intraday imports had
been tested and there was still scarcity. In this situation the use of the reserve should also
presumably be priced into the imbalance settlement calculation at the value of lost load to
avoid creating missing money
191
.
If a reserve is not designed in this way, however, and does impact on investment signals,
for example by acting as a replacement for scarcity prices when dispatched before the
market has had a full opportunity to solve a supply shortage and/or at a price that does
not reflect the value of lost load, there is a distortion to correct.
Strategic reserve capacity could be procured in a neighbouring bidding zone. However,
this would only appear to help security of supply in the zone paying for the reserve in
certain circumstances.
Figure A2.3 shows a scarcity event in zone A, which has contracted a strategic reserve in
zone B. Zone B either has less scarcity than zone A, or has a lower price cap. The reserve
is dispatched because A is experiencing scarcity. However, if the interconnector between
A and B was already sending power from B to A, the dispatch of the reserve will make
no difference to security of supply in A.
191
In discussion on the interim report, some stakeholders identified the following distortion where a strategic
reserve is employed, which would be an issue even when the reserve is only dispatched after intraday gate
closure. Since reserves hold capacity outside the market the merit order is always distorted when the market price
is set by capacity with higher running costs that the capacity held in reserve (since if the reserve capacity
participated in the merit order then in some hours it would have set a lower price). Although some will argue that
capacity in reserve would have closed if the reserve contract had not been made available, this may mean that
electricity prices in a market with a strategic reserve are generally higher than they would have been had the
reserve not been introduced. Unlike the distortions created by market wide capacity mechanisms, however, this
potential distortion would not reduce incentives for investments in capacity in neighbouring bidding zones, nor in
transmission between the strategic reserve zone and its neighbours.
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1694399_0201.png
Figure A2.3: Cross-border strategic reserve – no benefit to A
Source: European Commission
In general, it is to be expected that the dispatch of the strategic reserve would push prices
in the market to the price cap, because this should reflect the value of electricity at a time
when delivery of the reserve capacity is required (and because if it is dispatched at a
lower price it may create missing money in the market where it is located). However, if
the dispatch of A's strategic reserve into B would set market prices in B to the price cap
in A then the establishment of a cross-border reserve may have to be limited to situations
in which two countries share the same price cap.
The dispatch of such a reserve may also need to be limited to situations in which the
price caps were reached in both A and B to avoid distortions in B. Similar rules to those
proposed in section 5.8 of this annex could however be used to ensure that, in a situation
of concurrent scarcity in two Member States which have the same price cap, the power
contracted in the reserve could be used to send power from zone B to zone A (see Figure
A2.4).
Figure A2.4: Cross-border strategic reserve – forced flow to A
Source: European Commission
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If zone B also had a capacity mechanism, however, any capacity contracted from
capacity providers in zone A would presumably also have to be taken into account before
interconnector flows were adjusted in favour of A by the dispatch of the strategic reserve.
It therefore appears that the situations in which cross-border reserve capacity could
actually be useful to a capacity mechanism zone are limited unless interconnector
capacity was reserved specifically to allow the reserve to be dispatched across border.
This however would be inefficient because it would permanently reduce the amount of
interconnection capacity available commercially for market coupling.
Some respondents to the public consultation agreed that there may be a limited need for
cross border participation in strategic reserves, and agreed that in practice it may not be
readily possible to implement. However, other respondents felt that if cross border
participation in market wide volume based capacity mechanisms was required then cross
border participation should also be required in all other capacity mechanisms. However,
they do not explain how in practice such participation might be enabled.
In the future, the design of strategic reserves may adapt, and as energy markets become
more regional it would also be possible to design more regional strategic reserves that
might overcome the limitations of current designs. Even where designs remain basically
national, where neighbouring Member States are open to the participation of their
capacity resources in a neighbour's strategic reserve (ie. where they would accept
capacity being removed from the local market for use only in a concurrent stress event to
the benefit of the neighbour), the Member State creating the reserve could make
arrangements to include this cross border capacity in the competitive process for
establishing the reserve. Where a foreign resource would only be expected to be useful
25% as often as a domestic resource because of the conditions described earlier in this
section, the strategic reserve may however only choose the foreign capacity above
domestic capacity where the foreign capacity is for example at least four times cheaper
than the domestic capacity (depending on its risk aversion).
7.2. Cross-border participation in tenders for new capacity
A tender could be opened to cross-border capacity. The sector inquiry found that the
2003 tender in Ireland, and the 2014 tender in Belgium, were both open to foreign
capacity providers that were prepared, if successful, to connect permanently to the
capacity mechanism bidding zone. In the Irish example, the successful beneficiaries of
the tender were located in the Irish bidding zone, and the Belgian tender was abandoned,
so there are no examples we are aware of in which a tender for new capacity has actually
been used to pay for foreign capacity.
Although opening a tender across borders would remove the immediately distortive
impact on locational investment signals of a tender only for domestic capacity, it would
not remove the longer term distortive effects of the tender but potentially increase them
(since now potentially not only domestic capacity providers but also foreign capacity
providers may be prompted to close earlier than otherwise because of competition from a
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new, efficient competitor subsidised by the tender. These potential impacts of a tender
are discussed in more detail in section 6.2.1 of the detailed sector inquiry report.
7.3. Cross-border participation in price based capacity mechanisms
Although in the existing Irish capacity payments scheme, remuneration is available to
foreign capacity providers, the mechanism for enabling this (effectively an addition paid
for imports and levy on exports) may not be compatible with market coupling since
market coupling requires electricity flows to be determined on the basis of electricity
prices, not capacity prices. Ireland is in any case adapting its market arrangements,
including transitioning from the existing capacity payments model to a new central buyer
capacity mechanism.
Given the downsides of a capacity payments approach in which capacity remuneration is
set without a competitive process, which are described in section 6.2.4 of the detailed
sector inquiry report, and the trend away from these approaches in Europe, the potential
for including foreign capacity in these models is not considered further here.
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Appendix 2.1: Summary of a possible approach for cross-border participation in
central buyer and de-central obligation capacity mechanisms
Design area
1) Amount of
foreign capacity
to include
Proposal
For each neighbouring bidding zone, the TSO would
calculate the expected average long run amount of
imports expected into the capacity mechanism zone at
times of scarcity in the capacity mechanism zone.
All potential capacity providers in the neighbouring
system would be eligible, except possibly some
exceptions if necessary to avoid overcompensation.
Foreign capacity providers would be de-rated in the
same way as domestic capacity providers, taking into
account their technical long run reliability.
Capacity providers would be able to participate in more
than one capacity mechanism to avoid system-wide over
procurement.
Zonal auctions on each border in which foreign capacity
providers would offer their capacity and the amount
determined in 1) be selected based solely on the EUR /
kW price bid. If there is not enough capacity offered
below the capacity mechanism zone price then less
foreign capacity would be accepted (ie. the maximum
price paid for foreign capacity would = the national
price).
The foreign capacity would be paid the clearing price.
The interconnector operator would be paid the difference
between the zonal clearing price and the capacity price
in the capacity mechanism zone – with revenues
regulated appropriately.
All cross-border certificates / contracts would be
allocated for only one year.
Foreign capacity providers would need to be available in
the foreign zone for any period in which there is scarcity
in the capacity mechanism zone. They would need to
demonstrate their availability by placing a bid in their
local market. There would be no (or very limited)
exceptions to this obligation (eg. related to maintenance,
2) Identifying
eligible capacity
providers across
border
3) Allocating
capacity
certificates /
contracts to
foreign capacity
4) Obligations and
penalties for
foreign capacity
providers
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1694399_0205.png
fuel supplies etc).
For any period in which foreign capacity providers are
not available, they would pay a penalty, eg. the
imbalance price in the capacity mechanism zone.
If a capacity provider has chosen to sell into two
capacity mechanisms and there is an hour of concurrent
scarcity:
o
If they meet their domestic obligation, unless they
also
make available enough capacity to the market to
meet their foreign obligation, they would need to pay
a penalty to the foreign capacity mechanism zone.
o
If they fail to meet their domestic and foreign
obligations, they would need to pay two penalties – to
both the domestic capacity mechanism and to the
foreign capacity mechanism zone.
Foreign capacity providers would be tested by the local
TSO if they did not deliver during the capacity
certificate / contract period to ensure they are actually
able to deliver electricity. Fines would apply for failed
tests.
Interconnectors would have an obligation to be
operational (technically available) at times of scarcity in
either connected zone.
Since interconnector operators will potentially be
'involuntary' participants in each mechanism and would
have no direct control over the capacity price they
receive (since the price left for interconnection would be
determined by the voluntary bids of foreign capacity
providers to participate) it would be appropriate to cap
the maximum penalties that could be levied on
interconnectors for lack of availability.
There would be no possibility for interconnector flows
to be influenced by capacity contracts until market
coupling price caps are reached.
Rules could be developed to ensure electricity flows in
proportion to the cross-border capacity contracts held in
an episode of concurrent scarcity where market coupling
price caps are reached in two interconnected countries
5) Obligations and
penalties on
interconnector
operators
6) Influencing
interconnector
flows (without
distorting market
coupling)
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1694399_0206.png
and these price caps do not reflect the value of lost load.
7) Trading of
capacity
certificates /
contracts
Foreign capacity providers would be able to trade their
capacity contracts within the same bidding zone to allow
them to manage risks of changing circumstances (for
example required maintenance or unplanned outages).
Trading would be limited to other eligible providers that
have not already sold all of their de-rated capacity into
the relevant capacity mechanism (ie. the mechanism for
which the contract is being traded).
A registry is likely to be required to enable this.
The consumers in the capacity mechanism zone would
cover the costs of capacity contracted in that capacity
mechanism (including foreign capacity).
Any penalties paid by foreign capacity providers would
accrue to the consumers that paid for the capacity.
8) Financing
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Appendix 2.2: Pre-requisites to enable the possible approach described in section 5
Requirement
National TSO to
identify the amount of
foreign capacity that
contributes on each
border
Are harmonised rules a pre-requisite?
No, TSOs are already doing this in existing national
mechanisms.
Harmonised rules would however be beneficial to avoid
overly conservative assumptions and ensure transparency.
In the absence of harmonised rules to determine how this
calculation should be made, the methodology used should
be scrutinised and agreed by the regulators in the capacity
mechanism zone and the neighbouring zone.
In addition, harmonised rules on TSO protocols for dealing
with concurrent scarcity situations would help reduce
uncertainty (and therefore conservative judgments) related
to the establishment of the expected contribution of cross-
border capacity.
Identifying eligible
cross-border capacity
No, a declaration could be required that the provider is not
in receipt of support designed to remunerate its full
investment costs.
No, but harmonised rules would be helpful to increase the
accuracy of de-rating and ensure the way resources are de-
rated is consistent and transparent across the EU.
Potentially, though it may also be possible in the interim
with bilateral arrangements between TSOs (and maybe
DSOs). Arranging for appropriate meter data is likely to be
challenging. Harmonised rules in this area may be a pre-
requisite.
No, but cooperation with the neighbouring TSO would be
required to ensure periodic testing of capacity providers
and avoid paying for capacity that can never actually
deliver. Harmonised rules may be helpful to make it easier
for TSOs to agree on testing requirements and procedures.
No, a registry for trading could be established unilaterally
or in cooperation with the neighbouring TSO. A
harmonised registry may have advantages in the longer
term as more market wide mechanisms are introduced but
the costs and benefits would need further consideration.
De-rating cross-
border capacity
Including cross-
border demand
response capacity
Testing foreign
capacity providers
Trading of capacity
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A
NNEX
3: S
UMMARY OF
R
EPLIES
Q
UESTIONNAIRES TO PUBLIC BODIES
INTERIM REPORT
OF
THE
P
UBLIC
C
ONSULTATION
AND
FOLLOWING THE PUBLICATION OF THE
1. Approach
The Commission published its interim report of this sector inquiry on 16 April 2016 for
public consultation until 6 July 2016. As summarised in Annex 1, 114 stakeholders from
19 Member States plus Norway and Switzerland have submitted observations.
This Annex summarises the feedback received through the public consultation and
indicates how the Commission has taken into consideration the main messages received
in this final report. This summary refrains from tallying the replies, mainly because the
responses cannot be given the same weight and providing scores would not be a fair
representation of the opinions expressed.
2.
2.1.
Feedback received during the public consultation (13 April – 6 July 2016)
The role of the market and the need for capacity mechanisms
The interim report argued that capacity mechanisms may be appropriate instruments to
tackle persistent market failures. At the same time, it made clear that important market
reforms and regulatory improvements could reduce the need for capacity mechanisms.
With respect to this proposition, a large number of respondents expressed the view that
the Commission was too sceptical about the ability of the market to deliver the right
investment signals, and too quick to conclude that capacity mechanisms might be
required.
The Staff Working Document accompanying the final report has been amended by giving
more attention to the necessary market reforms especially in Chapter 2.3. Furthermore, in
Chapter 4, related to the necessity assessment, the 'last resort' nature that capacity
mechanisms must have – as underlined by many market participants – has been further
emphasised.
2.2.
Adequacy assessments must improve
The responses to the public consultation show particularly strong support for the tentative
conclusion that adequacy assessments should be improved so as to provide a more
objective and transparent picture of the adequacy situation to justify the introduction of a
capacity mechanism. Metrics such as LOLE, VOLL and CONE should be used and based
on common definitions. While there is recognition that security of supply may be valued
differently across the EU, the need for more transparency and objectivity in assessing the
security of supply situation can avoid expensive and unnecessary overprotection. Various
respondents raised the fact that current adequacy assessments do not contain an
assessment of the future economic viability of their generation fleet which may
compromise the usefulness of an adequacy assessment for identifying the future need for
a capacity mechanism. The Commission has included these observations in Chapter 4
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and proposes to strengthen and harmonise adequacy assessments as part of the Market
Design Initiative.
2.3.
Preferred design types
As regards the design and types of capacity mechanisms, the consultation replies echoed
support for the Commission's observations related to the benefits of open, technology-
neutral, volume-based and market-wide capacity market schemes. The large majority
also shared the Commission's critical assessment of price-based capacity payments.
However, an important part of respondents indicated that the interim report had not given
sufficient weight to the benefits of the strategic reserve model. Respondents especially
from Nordic countries argued that the distortive effects of strategic reserves are small if
such reserves are well-designed. These respondents generally agree with the Commission
that strategic reserves may not be useful in terms of addressing a missing money problem
or incentivising new investment. However, they underline that that may not be the main
goal of the measure, which should rather be seen as an insurance that backs up market
reforms.
The Commission agrees that where strategic reserves are dispatched only after the market
has failed to clear and where a sufficiently high price cap has been reached (and this sum
is payable by market participants that were not in balance at the scarcity moment) the
strategic reserve should not significantly undermine investment signals. The Commission
has reflected these observations in an updated Chapter 6 of the Staff Working Document.
2.4.
Common European Framework for CMs?
Several respondents were in favour of establishing a European capacity mechanism
framework. However, they diverge on the degree of harmonisation needed. A majority of
the respondent in favour of a common framework believe that rules should be established
at EU level setting the minimum requirements to be met by capacity mechanisms. These
include technology neutrality, procurement through a competitive process and the
participation of cross-border capacities. Those respondents also pointed out that in case a
common framework is not established, the EU should at least ensure that cross-border
participation in capacity mechanism is always made possible. Other respondents went so
far as to propose that all Member states should implement the same type of capacity
mechanism, while others proposed a staged approach with the implementation of
regional solutions in a first phase and of EU-wide capacity mechanism once the Single
Market for energy has been completed.
In contrast, some market participants defended Member States' discretion to tailor
capacity mechanisms to their specific needs although some were more open to move to
regional and EU-wide solutions in the long run.
In the interim report, the Commission proposed a possible approach to cross-border
participation in capacity mechanisms. The large majority of respondents were in favour
of such an approach. As part of the market design initiative, the Commission proposes to
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require Member States to implement cross-border participation along these lines, and
proposed the development of a harmonised capacity product for cross border trade.
National capacity mechanisms and domestic capacity products may still be varied to suit
the individual circumstances in different Member States.
2.5.
Bidding zones
In relation to bidding zones, some respondents mentioned problems caused by lack of
infrastructure and price zone configuration in large price zone areas. Respondents from
the Member States that already operate multiple price zones said the smaller zones in
their markets were a good thing but that even these zones too often followed national
borders rather than transmission constraints. Other respondents downplayed the
importance of bidding zone configuration, arguing that bidding zones were only one
issue guiding investment choices.
As part of an expanded discussion of the market reforms needed to ensure markets can
deliver to the fullest possible extent, the Commission has included additional
considerations on bidding zones in Chapter 2 of this Staff Working Document,
emphasising the dependence of reliable electricity price formation on bidding zones that
reflect transmission constraints.
2.6.
Demand response participation
Roughly a quarter of the respondents to the consultation raised specific remarks related to
demand response. The most frequent message was that demand response should be
included in market-wide capacity mechanisms. Some respondents also pointed out that
the function of demand response in an interruptibility scheme is different from that in a
market-wide capacity mechanism and more similar to an ancillary service than to a long
term generation adequacy service. Whether an interruptibility scheme can be regarded as
a capacity mechanism and when ancillary services may be capacity mechanisms are
assessed in Chapter 3 of this Staff Working Document.
A small number of respondents pointed out that regardless of the question of its
eligibility participation in the capacity mechanism, the participation of demand response
on the wholesale market should be further enabled and encouraged.
Most respondents were supportive of the proposed approach in the interim report to
accept interruptibility schemes specific for demand response given the long term benefits
of demand response. However, some respondents felt that this could not be justified and
a level playing field between all technologies should always be maintained.
2.7.
Cross-border participation
Many respondents were supportive of the proposed approach to cross-border
participation and the proposal to harmonise this aspect of capacity mechanism design.
However, some respondents felt that interconnectors should be paid directly, not receive
a 'congestion rent', some felt that cross border capacity agreements should be firm (ie.
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potentially overrule market coupling), and some respondents felt that participation in
more than one CM for the same time period should not be allowed .
The Commission has considered all of these arguments, but firm capacity cross border
agreements are not appropriate as they would undermine the signals for cross border
trade that make the Single Market for energy work. Although interconnector-only
participation can reduce complexity, such a model would fail to reward the resources that
actually provide security of supply on some borders, so would not be appropriate. These
issues are discussed in more detail in Chapter 5 and Annex 2 of this Staff Working
Document.
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