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



Table of Contents 1. Introduction 1.1 Concerns about the security of electricity supply 1.2 The Energy Union and the Market Design Initiative 1.3 The Energy and Environmental Aid Guidelines 1.4 The sector inquiry: what has the Commission done so far? 1.5 Set-up of the Staff Working Document 2. Increased generation adequacy concerns 2.1 The electricity sector in transition 2.1.1 The liberalisation of electricity markets 2.1.2 Decarbonisation policies 2.1.3 Concerns about security of supply 2.2 Incentives for future investment in generation 2.2.1 Expectations about future development of generation and demand 2.2.2 Market and regulatory failures undermining incentives to invest 2.2.3 Conclusions on the lack of optimal incentives to invest 2.3 What is being done to alleviate imperfections of EU electricity markets? 2.3.1 Improving the functioning of the electricity market 2.3.2 Addressing residual market failures with a capacity mechanism

3. Member State interventions: overview and classification 3.1 Types of capacity mechanisms 3.1.1 Targeted mechanisms 3.1.2 Market-wide mechanisms 3.2 Capacity mechanisms in place in the 11 Member States 3.2.1 Tender for new capacity 3.2.2 Strategic reserve 3.2.3 Interruptibility schemes 3.2.4 Targeted capacity payments 3.2.5 Central buyer 3.2.6 De-central obligation 3.2.7 Market wide capacity payments 3.3 Conclusions 4. Adequacy Assessments and Reliability Standards 4.1 Introduction 4.2 Findings of the sector inquiry 4.2.1 Reliability incidents are rare 4.2.2 More adequacy problems are expected in the future 4.2.3 Member States carry out increasingly advanced adequacy assessments 4.2.4 Member State practice in setting reliability standards

4.3 Assessment 4.3.1 The absence of a common approach in assessing adequacy 4.3.2 Reliability standards are not used to ensure appropriate intervention 4.4 Conclusions 5. Design features of capacity mechanisms 5.1 Introduction 5.2 Eligibility 5.2.1 Eligibility criteria in capacity mechanisms 5.2.2 Findings of the sector inquiry on eligibility 5.2.3 Issues encountered in relation to eligibility 5.2.4 Conclusions on eligibility 5.3 Allocation Process 5.3.1 The role of the allocation process in capacity mechanisms 5.3.2 Findings of the sector inquiry on administrative allocation processes 5.3.3 Findings of the sector inquiry on competitive allocation processes 5.3.4 Issues encountered in relation to allocation processes 5.3.5 Conclusions on allocation processes 5.4 The capacity product: obligations and penalties 5.4.1 Capacity products 5.4.2 Findings of the sector inquiry

5.4.3 Issues identified 5.4.4 Conclusions 6. Assessment of the various types of capacity mechanisms 6.1 Necessity for intervention through a capacity mechanism 6.2 Appropriateness and market impacts for each type of mechanism 6.2.1 Tenders for new capacity 6.2.2 Strategic reserves 6.2.3 Interruptibility schemes 6.2.4 Targeted capacity payments 6.2.5 Central buyer mechanisms 6.2.6 De-central obligation 6.2.7 Market-wide capacity payments 6.3 Choosing the right type of capacity mechanism 6.3.1 The main adequacy problems 6.3.2 Long term concerns 6.3.3 Temporary concerns 6.3.4 Locational concerns 6.3.5 Concerns related to the responsive of the demand side 6.3.6 Capacity payments are unlikely to be the most appropriate option 6.4 Minimising the cost of capacity mechanisms

6.5 Capacity mechanisms and the decarbonisation objective 6.6 Conclusions Annex 1: Overview of respondents Annex 2: The participation of interconnectors and foreign capacity providers in capacity mechanisms Annex 3: Summary of Replies of the Public Consultation and Questionnaires to public bodies following the publication of the interim report Annex 4: References



1.Introduction 1.1Concerns about the security of electricity supply (1)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. (2)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. (3)Some Member States have reacted by taking measures designed to support investment in the additional capacity that they deem necessary to ensure an acceptable level of security of supply. These capacity mechanisms pay providers of existing and/or new capacity for making it available. (4)When introduced prematurely, without proper problem identification or in an uncoordinated manner, and without taking into account the contribution of cross-border resources, there is a risk that capacity mechanisms distort cross-border electricity trade and competition. For example, they may reward new investments only in certain types of generation or exclude demand response. They may also encourage investment within national borders when it would be more efficient to reinforce interconnection and import electricity when needed. 1.2The Energy Union and the Market Design Initiative (5)Concerns about the security of electricity supply have been raised by the Commission in the framework of the Energy Union. 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 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 and, secondly, on a review of the Directive concerning measures to safeguard security of electricity supply. 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. (7)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. 1.3The Energy and Environmental Aid Guidelines (8)The Guidelines on State aid for environmental protection and energy 2014 – 2020 ('EEAG') include specific rules for assessing capacity mechanisms. The Commission has already applied these rules to i.a. capacity mechanisms notified by the United Kingdom and France .

(9)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. (10)The present report rather aims to gather and present information on the functioning of capacity mechanisms and draw tentative conclusions which will help with the application of EEAG. The interim report and a previous version of this Staff Working 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 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 ; 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. 1.4The 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 developed in Europe. The Commission received in total 124 replies. An overview of the number of replies per Member State and a breakdown by respondent is provided in Annex 1. (14)Following the public consultation, the Commission received replies from 114 stakeholders from 19 Member States plus Norway and Switzerland. This number includes replies from 62 associations and 20 public bodies. A breakdown of the replies is provided in Annex 1. (15)On 15 June 2016, the Commission also organised a workshop with Member States to present the findings of the interim report. A particular focus of the workshop was on the issue of cross-border participation in capacity mechanisms. In addition, bilateral meetings have been held with several stakeholders to deepen the understanding of specific issues. Finally, the Commission has made use of a wide array of public sources of information as well as specialist literature and publications on the topic. 1.5Set-up of the Staff Working Document (16)It is the aim of this Staff Working Document to present the findings of the sector inquiry and to draw conclusions regarding the current practice applied by Member States when contemplating, adopting and operating a capacity mechanism. These findings and conclusions may be interpreted as guidance provided by the Commission as to its future assessment of capacity mechanisms under the State aid rules. (17)The present final report follows the same structure as the interim report. It updates the information of the interim report and elaborates on certain issues that have received particular attention in the public consultation or recent case practice. Chapter 2 presents an overview of the state of the electricity market in the EU as a whole and in particular in the eleven Member States under scrutiny. It explains why many Member States are concerned about the continued capability of their electricity system to meet demand at all times and are therefore using or considering to introduce capacity mechanisms. It subsequently assesses what drives investments in generation capacity and describes the market and regulatory failures that impact investment decisions in the electricity market. A number of market improvements are discussed as means to address the identified failures, whereby it is recognised that residual failures may persist. (18)In subsequent chapters the ability of capacity mechanisms to address these residual market and regulatory failures is analysed. Chapter 3 provides taxonomy of capacity mechanisms and categorises the capacity mechanisms that have been encountered in the eleven Member States subject to the sector inquiry. Chapter 4 provides an overview of the ways in which Member States assess their generation adequacy and the role of reliability standards in that assessment. Chapter 5 presents in a high level of detail the preliminary findings of the sector inquiry vis-à-vis the design features of the 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.



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

2.1The electricity sector in transition The liberalisation of electricity markets (20)Liberalisation and the creation of Single Market for energy have been at the heart of EU energy policy since the early 1990s. The Third Energy Package , adopted in 2009, has resulted in the complete unbundling of the supply and generation arms of vertically integrated undertakings from their transmission activities, thus creating fully independent transmission system operators (TSOs) and paving the way for competition to occur in the generation and supply segments of the sector. (21)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 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 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. (22)Liberalisation has implied a transition from central planning of investments in generation and capacity towards decentralised decision-making. On the one hand, investment decisions on generation capacity and on transmission capacity are no longer taken jointly. On the other hand, investment decisions in generation capacity are taken autonomously by private undertakings operating in electricity generation. This shift, together with the new organisation of the relation between generators and TSOs through unbundling, requires an adaptation of previous adequacy planning mechanisms, and a robust framework for regulatory supervision of generation adequacy, including a clear definition of the roles of the different actors in adequacy planning. Otherwise, the uncertainty about when and where investments in generation capacity will take place could be uncomfortable for TSOs from a technical perspective, but also policy makers who bear the ultimate political responsibility for secure electricity supplies. These considerations are particularly relevant given that Europe's generation fleet is ageing, potentially creating a need for investments in generation capacity. (23)Installed generation capacity has substantially increased over the last two decades, as a result of investments by both incumbent generators and new entrants. These investments focused notably on wind and solar technologies, but also on combustible fuel technologies, especially gas. Source: European Commission based on Eurostat data Decarbonisation policies (24)The energy sector is a large contributor to the EU's carbon footprint but also contributes in a variety of ways to realise emission reductions. Power companies and industrial installations in the EU are covered under the EU Emissions Trading System (ETS), which puts a price on carbon, ensuring that the costs of fossil fuels reflect their carbon intensity. The ETS is a market based system, in which power companies can choose whether to buy allowances on the market or to reduce emissions. As the overall 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 , 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. 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 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. 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 , the Large Combustion Plant Directive , and the Industrial Emissions Directive . Concerns about security of supply

(27)Security of supply is one of the three core objectives of EU energy policy. In the electricity sector, security of supply has a short term and a long term dimension. In the short term, it is important that the TSO, who is responsible for system security in real time, has sufficient instruments at its disposal to ensure balance between demand and supply. In the long run, the electricity system needs to be fit to provide sufficient electricity to meet demand at all times and in all parts of the system. (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. 2.1.1.1Margins 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 . 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%. 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. 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. 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.

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. 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. 2.1.1.2Capacity utilisation of conventional generation has decreased (36)The contribution of each technology to the effective generation of electricity does not match the share of each technology in the installed capacity mix. While in 2013 nuclear represented 13% of total installed capacity in the EU28, it produced 27% of all the electricity generated. This illustrates the fact that nuclear generation units typically run continuously most of the time during the year. (37)The opposite applies to hydro, wind and solar: in 2013 they represented 20%, 12% and 7% of total installed capacity respectively, but contributed just 13%, 7% and 3% to effective electricity generation. This illustrates the variable nature of these renewable technologies, which despite their low running costs cannot always generate due to their dependency on weather conditions. Source: European Commission based on Eurostat data (38)The deviations between the share of installed capacity of each generation technology and the share of electricity generated by each technology indicate different levels of capacity utilisation across technologies. One possible measure of capacity utilisation is the ratio between the average generation per hour and the installed capacity for each technology. Figure 11 shows this measure of capacity utilisation for the EU28 by generation technology. (39)As expected, nuclear exhibits the highest level of capacity utilisation, stable above 80% since 2000. Capacity utilisation of hydro has also remained broadly stable throughout the period, albeit at a much lower 30%. Wind and solar have gradually increased their levels of capacity utilisation over the last years, attaining 23% and 12% levels respectively in 2013. Of particular interest is the evolution of the capacity utilisation of combustible fuels, which has significantly decreased since 2005, from 50% to 40%. Hence, the increasing weight of intermittent wind and solar in the generation mix over the last decade has been accompanied by a lower level of capacity utilisation for combustible fuel technologies, in particular gas. 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-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.

Source: European Commission based on Eurostat data 2.1.1.3Profitability 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. 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. Source: Platts (43)The drop in electricity prices over the last 5 years is the result of a variety of developments, which includes the lower demand for electricity, the increasing proportion of renewable technologies with low marginal costs and the increasing margin between generation capacity and demand. (44)Lower electricity prices imply lower levels of profitability for generation technologies whose costs and capacity utilisation have remained largely stable, for instance nuclear generation. In the case of coal- and gas-fired plants, profitability depends on electricity prices and capacity utilisation, but also on the development of fuel prices. The clean spark spread and the clean dark spread 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. 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.

Source: European Commission, based on ICE data (46)Additional factors that might have contributed to the increase in the relative profitability of coal-fired power plants vis-à-vis gas-fired power plants in Europe are the massive shift to shale gas in the US and the switch from nuclear to gas in Japan,. (47)All these factors have contributed to make coal-based generation less costly on average than gas-based generation. Gas-based generation of electricity increased steadily until 2010, but has significantly decreased since 2011. Conversely, coal-based generation has increased since 2010, reflecting the change in the relative positions of gas and coal in the merit order curve. Source: European Commission based on Eurostat data (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. 2.1.1.4Ageing of coal and nuclear plants (49)A significant proportion of current installed generation capacity is approaching the limit of its operational life. Most nuclear plants have been in operation already for 20 to 30 years, and will be older than 30 years by 2020. In Europe, little investment in new nuclear plants is planned and a number of countries are phasing out their nuclear fleet. While investments are being made to extend the life of a number of nuclear plants, notably in France, a significant share of nuclear generation capacity may close in the coming decades. (50)Combustible fuel plants are more evenly distributed across age intervals, the oldest being mainly coal plants and the younger being mainly gas plants, especially combined cycle gas plants. Coal plants are candidates to be gradually phased out, not only due to their age, but also as a consequence of environmental policies. (51)Regarding renewables, most hydro plants are older than 30 years, but their operational life is not as limited as for nuclear and coal plants. They are expected to keep operating for many decades, provided the necessary maintenance investments are made. Wind and solar generation units are the youngest in the capacity generation mix, most of them having been operational for less than 20 years. Note: "2020 f" refers to forecasts for 2020. Source: Platts Power Vision 2.2Incentives for future investment in generation (52)Declining demand and increasing shares of renewables resulted in decreasing profitability of electricity generators, especially conventional flexible technologies. The trend to more generation from intermittent technologies constitutes an economic challenge for the business model of many established energy companies with a fossil fuel-based generation fleet . 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. (53)To the extent that low profitability reflects an excess of installed generation capacity, the resulting lower incentives to invest may be a sound economic signal to correct for overcapacity. However, if low profitability is the consequence of market and regulatory failures, then incentives to invest may prove insufficient to maintain adequate generation capacity in the medium and long term. It is therefore important to assess what drives investments in the European electricity markets of today and how that will influence the generation mix of the future. (54)This section presents the evidence obtained from the sector inquiry on the expectations of public bodies and market participants about future installed generation capacity and capacity margins, and discusses, on the basis of empirical evidence as well as economic literature on the subject, the market and regulatory failures that impact the incentives to invest in generation capacity.

Expectations about future development of generation and demand (55)The sector inquiry responses show that total projected installed capacity will increase at a slower pace than demand in six out of the nine Member States where data was available. 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. 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. 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. (59)Lower profitability for flexible conventional technologies resulting from these developments has a negative impact on incentives to continue investing in these types of technologies. The increasing risk perceived by investors as a consequence of the reduction of operating hours during which these technologies expect to have to recoup costs and get appropriate remuneration further contributes to erode incentives to invest. (60)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. 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. (61)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 (62)As in any other sector, investment decisions crucially depend on the returns that private investors expect to obtain. In the case of electricity generation, either through revenues from electricity trading/sales or other channels (e.g. selling ancillary services , or participating in capacity mechanisms or renewables support schemes). (63)Electricity markets where generators obtain revenues only from selling electricity, balancing power and providing ancillary services have been termed 'energy-only markets' in the economic literature. In such markets, generators take their decisions to invest in maintaining current capacity and installing new capacity on the basis of their expectations of future earnings obtained exclusively from these revenue streams. Hence, in an energy-only market, supply and demand for electricity determine the profitability of generation activities and the incentives to invest in future generation capacity.

(64)Current liberalised electricity markets in the EU are imperfect examples of energy-only markets, given that in most Member States some or all generators obtain revenues through channels other than market prices, for instance in the form of subsidies and payments that affect their incentives to invest in generation capacity. (65)The economic literature has extensively discussed whether different models of electricity wholesale markets can be expected to generate sufficient incentives to invest to guarantee adequate generation capacity. When this is not the case, a so-called 'missing-money' problem arises: the market proves unable to incentivise investment in adequate generation capacity because investors fear future revenues will not cover their fixed costs and will not appropriately remunerate their investment. (66)The missing-money problem is mainly related to the potential inability of electricity markets to deliver sufficiently high prices during periods of scarcity – as explained in the next Section – although other factors have been discussed in the economic literature that can also contribute to the lack of incentives to invest, such as the public good features of system reliability and the uncertainty about expected returns on investments in generation capacity. 2.2.1.1Factors undermining price signals in electricity markets (67)Prices in competitive electricity markets reflect to a large extent the operating costs of the generation plants that are activated to serve the demand for electricity. However, this is not always the case even in very competitive markets. In principle, wholesale prices in perfectly competitive electricity markets equal the marginal cost of the most 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. (68)The theoretical efficient functioning of this market design depends on a number of assumptions that are rarely satisfied in existing wholesale electricity markets, in particular that the demand can respond to variations of wholesale prices in real time and that generators do not enjoy a significant degree of market power. (69)The demand for electricity is typically insufficiently responsive to prices because currently prevailing technical features of electricity delivery do not allow most customers to respond to price variations in real time. As a consequence, there may be situations when the wholesale energy market cannot clear, because demand remains above available generation capacity independently of the price level. In such circumstances, some kind of regulatory intervention is needed to bring supply and demand in balance, e.g. by rationing demand and administratively setting a price. (70)Economic theory indicates, under certain assumptions, that during periods of rationing it is optimal to set a price at the level of the value of lost load (hereafter, 'VOLL'). VOLL is equal to the marginal consumer surplus associated with a unit increase in electricity supplied to rationed consumers. In other words, it expresses the value attached by consumers to uninterrupted electricity supply. A regulated price at the level of VOLL when the market does not spontaneously clear would in theory provide incentives to invest in generation capacity that reflect consumers' average willingness to pay for security of supply. (71)In most Member States price caps currently exist which are not based on estimates of average VOLL, but often on the technical bidding limits used by power exchanges. Although the national authorities in Denmark, France, Ireland, Italy, Poland, Portugal and Sweden have all made estimates of VOLL in their markets, only Croatia and Denmark indicated that price caps in their markets were influenced by the estimated VOLL. (72)Although VOLL has not been calculated in some Member States, many Member States that have calculated it report values that are well above day-ahead market price caps. Table 1 reports the price caps and estimates of VOLL in each of the 11 Member States, as obtained from responses to the sector inquiry. Wholesale Price Caps and estimates of VOLL (EUR/MWh) Country Day-ahead Intraday Balancing Estimate of VOLL Belgium 3,000 9,999 4,500 n.a. Denmark 3,000 No cap 5,000 Between 2,933 and 36,800 Croatia 3,000 No exchange trading. No OTC cap. No cap n.a. France 3,000 9,999 9,999 26,000 Germany 3,000 9,999 No cap n.a. Ireland 1,000 (moving to 3,000 in future) 1,000 (moving to 3,000 in future) No balancing market. Price cap TBC for future market design 11,017.98 Italy 3,000 3,000 3,000 3,000 Poland ~350 No cap ~350 Between ~1,250 and ~2,100 Portugal 180 180 No cap 3,000 Spain 180 180 No cap n.a. Sweden 3,000 No cap 5,000 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 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. 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. 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. (75)Regulators and competition authorities may find it difficult to distinguish instances of exercise of market power abuse and market manipulation from genuine scarcity conditions. In both cases the main observable market outcome is higher wholesale prices. Generators can for instance disguise withholding of capacity as technical maintenance or failure. It is not easy either to assess whether generators bidding above their running costs are legitimately seeking to cover their fixed costs, or are seeking to make windfall profits thanks to the lack of sufficient competition or demand response. (76)However, when asked whether concerns about market power had influenced decisions on price caps in their markets, only the Polish national authorities and the Spanish Regulator confirmed. Belgium, Denmark, France, Ireland, Italy, Portugal, the Spanish Government and Sweden denied. (77)A number of market-power mitigation measures have been applied in wholesale electricity markets – apart from permanent scrutiny by competition authorities and the increased monitoring of electricity trading under the REMIT Regulation – including forced capacity divestitures, long-term contracts, virtual power plants 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. 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. However, experience in several countries shows that wholesale market participants may be able to hedge against short-term price peaks, with limited additional costs for end consumers. (79)In response to the public consultation and inquiry questionnaires, stakeholders have identified other factors that may lead to price caps being set below VOLL. The system operator in Belgium and the national authorities in Denmark and Italy identified the Commission Guideline on Capacity Allocation and Congestion Management, which requires the establishment of 'a proposal on harmonised maximum and minimum clearing prices to be applied in all bidding zones which participate in single day-ahead coupling…[taking]… into account an estimation of the value of lost load' , 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.

(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. (81)Regarding the reasons why price caps have only rarely been reached, most Member States' national authorities that chose to comment suggested that this reflects that markets are currently well supplied and there have not been many occasions where electricity was scarce. 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 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. 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 constrain the commercial use of interconnection, preventing trade to and from the zone and undermining incentives for further investment in interconnection. (84)Finally, electricity prices may not properly reflect scarcity if generators self-constrain their offers to avoid a perceived risk of competition law enforcement. Although there are exceptions , 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”. 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”. 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. 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. (86)Furthermore, the presence of a second limb in the United Brands test signals that it is not sufficient for the antitrust authorities to show that the price charged is high compared to the costs actually incurred to conclude that such price constitutes an infringement to antitrust rules. Instead, the authorities also have to demonstrate that this price is unfair in itself or when compared to competitive benchmarks. The underlying idea is that even dominant undertakings may have legitimate reasons to charge high prices compared to their cost of production, not having to do with their dominant position. In the words of the United Brands judgment, the authorities therefore have to show that “the dominant undertaking has made use of the opportunities arising out of its dominant position in such a way as to reap trading benefits which it would not have reaped if there had been normal and sufficiently effective competition.” This might be done either by looking at competitive benchmarks or directly by estimating the economic value of the product. (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" . 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 not be recouped by a peaking plant at the end of the merit order curve bidding its short run marginal cost. 2.2.1.2Uncertainty on returns increases risk premiums required by investors (88)Generators' expectations about future returns on their investments in generation capacity are affected not only by the expected level of electricity prices, but also by several other sources of uncertainty, such as increasing price volatility, recurrent regulatory reforms and the uncoordinated decisions of competitors. (89)The increasing weight of intermittent renewable technologies makes prices more volatile and shortens the periods of operation during which conventional technologies are able to recoup their fixed costs. In such circumstances, even slight variations in the level, frequency and duration of scarcity prices have a significant impact on the expected returns on investments, increasing the risk associated to investing in flexible conventional generation technologies. (90)Since the onset of the liberalisation of electricity markets, regulatory frameworks have gradually evolved over time, and are expected to continue to change to respond to the political objectives of decarbonisation, affordability and security of supply. Given the relatively long time periods over which investments in generation capacity are typically expected to be recouped, the lack of a stable regulatory framework adds uncertainty regarding the expected returns on investments in capacity. (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. 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. (92)Investors factor in all these sources of uncertainty when making their investment decisions. Different authors give different weight to each of these factors, but they all contribute to increase risk for investors. If investors demand larger risk premiums, energy-only markets may not be able to generate sufficient incentives to invest even with high scarcity prices. 2.2.1.3Public good features of reliability lead to insufficient investment signals (93)The reliability of electricity systems has certain features of a public good. On the one hand, investments in capacity to increase the system's overall reliability to meet the preferences of the most demanding consumers also reduce everyone else's risk of supply interruption at no extra cost (in economic terms, this is the feature of 'no rivalry'). On the other hand, it is currently not possible for most individual final consumers to be selectively disconnected by the system operator on the basis of their 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. Conclusions on the lack of optimal incentives to invest

(95)European electricity markets suffer from a number of market and regulatory failures undermining investment incentives. Demand for electricity is largely inelastic due to technical factors and regulatory barriers, which implies lack of responsiveness of demand to price variation and leads to inefficient price signals. System operators use a variety of tools to force the market to clear in ways that supress market price signals. Price caps are often set below VOLL. Uncertainty about expected future returns on investment in generation capacity contributes to undermine incentives to invest. (96)Electricity markets in the eleven Member States share most of these characteristics. It is therefore understandable that authorities and stakeholders pose the question whether the current design, rules and structure of electricity markets may lead to problems of generation adequacy in the future, even though there may not exist such a problem today. Answering this question requires an in-depth assessment of the current situation of electricity markets, as well as of the expected evolution of both the demand and the supply sides in the coming years. 2.3What is being done to alleviate imperfections of EU electricity markets? (97)Against the backdrop of reduced investment incentives and increased concerns about reliability levels in the future, Member States can on the one hand attempt to alleviate imperfections of the current markets and on the other consider intervening in the market by providing additional incentives to invest via separate payments that directly remunerate capacity. This section assesses the improvements that have been proposed and are being carried out on a national and European level to address the market and regulatory failures in today's electricity markets and assesses to which extent residual generation adequacy problems may exist that can be addressed by capacity mechanisms. Improving the functioning of the electricity market (98)Both at national and European levels, efforts are underway to implement better market designs and regulation aimed at improving market functioning. There is general consensus that there exists room for improvement of the efficiency of electricity markets, most notably by enabling demand response, broadening supply-side participation and improving the efficiency of market outcomes, especially during scarcity events. 2.3.1.1Setting 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 . 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. 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, 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. Ireland is planning a similar change to its market design, where the balancing market will include an 'administrative scarcity price', the Belgian regulator has been exploring the possibility of taking a similar approach in Belgium, and the approach was recommended by the International Energy Agency in its 2016 'Repowering Markets' report. (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 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. 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. 2.3.1.2More 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 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), 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. 2.3.1.3More 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 , 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. (112)A document published by ACER in 2014 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. 2.3.1.4Further 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 and aggregators are facilitating participation in electricity markets – and for larger industrial consumers. (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. 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. 2.3.1.5Further 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 inclusion in balancing markets. Wind capacity is increasingly able to offer ancillary services and to adjust its output in the balancing timeframe . Balancing Responsibility for RES Country Balancing responsibility Belgium Yes Denmark Yes Croatia No France No Germany FIP Only Ireland Partly Italy Partly Poland Yes Portugal Yes Spain Yes Sweden Yes 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

2.3.1.6Further 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. 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 bidding zones if appropriate to reflect the different willingness to pay of consumers in different zones. 2.3.1.7More 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. 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. However, other authors stress that such reforms alone may not completely solve the missing-money problem. 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 measures to address a residual missing money problem and ensure generation adequacy. (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. (128)The following chapters describe and assess the capacity mechanisms applied or planned in the eleven Member States. 3.Member State interventions: overview and classification (129)There are various types of capacity mechanisms. They can be categorised to some extent based on their basic characteristics, and within each category further parameters can be set that determine the precise design. 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. 3.1Types 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. Source: European Commission

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. (133)For the purposes of the sector inquiry, we have identified three basic types of targeted mechanism. 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. 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. 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. (139)Further variations are possible within the different models depending on the detailed design. 3.2Capacity 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 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 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. (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. Source: European Commission based on replies to sector inquiry 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. 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. 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. 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. 3.2.1.1Eligibility (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 . 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 outside of the Member States' national territory, but only on the condition that they had dedicated transmission connections to the Belgian or Irish grid. 3.2.1.2Allocation 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. 3.2.1.3Capacity 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. 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. 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 capaci