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Coordination Mechanisms for Accommodating Increasing Amounts of Wind and Solar in the Power Market

November 4th, 2014 by Jacques de Jong, Clingendael International Energy Programme

European power markets are being confronted with an unprecedented transition process toward a low-carbon power system. The speed and complexity of this shift are raising serious challenges and operational difficulties. The successful increase in the deployment of variable renewable electricity technologies is bringing the EU objective of raising the share of these technologies in its energy mix to 20% by 2020 closer to an attainable reality. But there are deep concerns about the continuing impacts of this transition, especially as it is further expanded to include a substantially larger share of renewables by 2050.

Concerns centre on the increasing costs for consumers and tax payers, on how to manage operation when there are large degrees of variability within the energy mix, and on the uncertainty of supply security due to generation and system adequacy risks. More generally, this transition demands a more fundamental rethinking of the role of the state and the role of the market, with due regard for the still prevailing paradigm of an internal EU electricity market with increasing cross-border flows and market integration.

European power markets are being confronted with an unprecedented transition process toward a low-carbon power system. The speed and complexity of this shift are raising serious challenges and operational difficulties. The successful increase in the deployment of variable renewable electricity technologies is bringing the EU objective of raising the share of these technologies in its energy mix to 20% by 2020 closer to an attainable reality. But there are deep concerns about the continuing impacts of this transition, especially as it is further expanded to include a substantially larger share of renewables by 2050. Concerns centre on the increasing costs for consumers and tax payers, on how to manage operation when there are large degrees of variability within the energy mix, and on the uncertainty of supply security due to generation and system adequacy risks. More generally, this transition demands a more fundamental rethinking of the role of the state and the role of the market, with due regard for the still prevailing paradigm of an internal EU electricity market with increasing cross-border flows and market integration.

In a recent report we offer a number of reflections: on how to enhance investor confidence in a continuing market-based context with effective long-term oriented coordination mechanisms; on how to apply and implement support schemes for investing in new low-carbon generation technologies; on understanding market dynamics in the interaction between generation and the networks and in its day-to-day system operation, with the need for deploying effective regulatory adaptations in a pragmatic way; and on maintaining the necessary operational back-up capacities and longer-term-oriented generation adequacy. Our report starts with three observations: a substantial increase of VRE (Variable Renewable Electricity) will not cause subsidies for new investments in certain types of renewable energy to end, as wholesale prices have decreased faster than production costs and may decrease further, especially at times of VRE generation; second, network costs will increase, depending on many aspects like the degree of curtailment that will be accepted or the degree of demand-side management that could be achieved; and third, long-term adequacy may only be available at much higher total costs. These observations require further analysis and discussion, but would need already now some new approaches. As the actual power system has not been developed to deal with a large share of VRE, it is being confronted with challenging transitional problems. It is not the large share of VRE as such that is causing problems, but its occurrence in a power system that has been gradually developed and optimized under completely different circumstances.

To a large extent the transitional problems can be solved within the prevailing market-based context. One needs to realize, however, that markets are always dynamic and complex, and often even impossible, to predict. It also means that in the quest to find an effective and efficient mix of policy and regulation, one has to develop new avenues as well, resulting in new policies, instruments and regulations. This process will have to be one of learning by doing, where sometimes policies and instruments that are not delivering will have to be abandoned. Learning by doing can be successful if the long-term ambition remains unambiguous and if it is accepted that national approaches alone will not be sufficient, meaning that European approaches will be required, while also understanding and accepting that within the EU many structural and physical differences will necessarily remain. All-EU solutions will not always be possible or even desirable. Hence a more regionally oriented model, such as the one of the developing NW-EU energy market, could be more successful.

Investments in generation
In order to decarbonize the power sector by 2050, the overall EU approach will have to change fundamentally before 2030-35. In rethinking how to stimulate investments in new generation in the prevailing market-based context, the most important existing policy instruments are investigated, both the general ones (the Emissions Trading Scheme, ETS, and Contracts for Difference, CfDs) and those which are more VRE-specific (feed-in tariffs, FiTs, and feed-in premiums, FiPs, as well as auctions and supplier obligation schemes). In addition, three others that are under discussion in policy debates are looked at: Emissions Performance Standards (EPS), Capacity Remuneration Mechanisms (CRMs) and the Regulated Asset Base (RAB) methodology. The essay also includes some thoughts about long-term arrangements and on facilitating investor confidence in planning and licensing procedures.
No single policy instrument will be sufficient to allow policy makers to achieve their policy goals. A mix probably will be needed. Choices will be based on the particular market situations and the weight policy makers attach to their different national preferences. The first option would be to improve ETS, which, despite the actual shortcomings, is still the only market-based EU policy instrument. A strengthened ETS has to be supported by additional instruments for a longer time than is often realized. The subsidy schemes should therefore have a clear preference for the more market-based approaches such as FiPs. Regulation such as EPS is something worth exploring more actively. Quantitative supplier obligations for renewable energy could also be an option. More radical interventions with CRMs, perhaps in connection with a RAB, may be useful as well if other approaches are less successful.

A more extended and deliberate transition period than currently is envisioned might be advisable as well, as temporization in large-scale investments combined with learning from technology and policy innovations could decrease costs. In all cases, one has to accept that the power system will become more expensive. Attaining the low-carbon aim is a difficult and, at least in the next decade, costly endeavour.

Networks
In the transition towards a mix with high shares of VRE, the operational and regulatory designs will have to be adapted to fit the physical characteristics of the networks and their economic implications. Energy networks are capital-intensive and have long lifetimes and a monopolistic nature. Investments in these networks take time; more VRE requires additional investments in grid extensions and a substantial intensification of the management of the electro-technical balance.
We recommend a rethinking of the grid-generation paradigm, placing more emphasis on the role and operation of the infrastructures, including applying technology neutrality and considering a more energy system-integrated orientation. Reconsidering this ‘grid-follows-generation’ paradigm could also lead to higher social-economic benefits. A more precise cost allocation for grid users, more innovative demand-response mechanisms and the introduction of (cross-border) market mechanisms (including ones for operating reserves) could further decrease additional network costs in a market-based way. Enhancing operational efficiency requires technology neutrality in balancing, with an extension of the ‘flexibility space’ (focusing particularly on the role of gas and its regulatory conditions), and with a cross-border expansion of balancing zones in which system operation and network usage are guided by market-based arrangements. Decentralized generation and/or new demand-side orientations will increase their shares in the balancing market. TSO/DSO interactions will become increasingly important, and more specific roles for the DSOs and other Distributed Energy System (DSEs) providers could lead to a rethinking of their regulatory space. All of this would require regulatory innovation, perhaps including experimentation with regulatory exemptions.

Adequacy
System and generation adequacy are, together with supply security, high on today’s policy agendas. Adequacy of the system can no longer be guaranteed, however, as existing flexible generation is closing and new investments in back-up are not being made. Concerns are being expressed about the investment climate and the low rewards for investing in new capacity, questioning the role of the prevailing Energy-Only Market (EOM). Options for capacity payments, whether in a market-based context or not, are therefore emerging. Many options have been more extensively discussed elsewhere, but the specific questions in the context of our reflections focus on the long-term coordination requirements. Flexibility of prices and additional room for demand-side integration, the certainty that no price cap will be used, the further development of market coupling, intraday and balancing markets and markets for ancillary services diminish the eventual need for dedicated mechanisms to stimulate back-up capacity. It would be unwise to abandon the Energy-Only Market before all options to increase its effectiveness have been explored. The academic literature draws no final conclusions about whether separate capacity rewards are needed, as the possible improvement of adequacy has to be weighed against costs. Furthermore, uncertainty will increase, as nobody knows how long the policy debate on CRM will last or how future politicians will implement the rules. However, politicians and regulators don’t like to take any risk with real or perceived in-adequacy. When they would consider the introduction of a CRM, the least they could do is to do this jointly in a regional context. The same is true for any another option to improve adequacy, i.e., developing adequate storage capacity (especially long-term).

Regional approach
All of the issues discussed in this essay will require a European approach. A number of them could be tackled with national policies, but with cross-border interactions EU rules are applicable. One has to realize that policy implementation will become too complicated if ‘all-EU’ solutions are attempted. Hence, regional approaches, such as the Pentalateral Energy Forum, which includes the Benelux, France, Germany and now others, should be the goal. The Netherlands could take more initiative in bringing a number of the policy issues to the Penta agenda: issues such as assessing generation adequacy, VRE integration in the grids, expanding market-based balancing options and zones, coordinating VRE support schemes, enhancing joint cooperation between the TSOs, and even more ambitiously, a more general approach to the fuel mix policies, including the role of gas. Wherever possible, these issues could be supported by an enhanced German-Dutch bilateral cooperation, and where appropriate by a Belgian-Dutch approach.

The state and the market
In all, this essay does not suggest that the energy market has to move one-dimensionally back to the state. Instead, it suggests that the state must be aware of being part of a process in which it stimulates and facilitates investments of clean energy in general and VRE in particular. A state trying to implement effective and efficient policies is well advised to investigate how markets can perform better and how private entities can play their role. The energy market has two different coordinating functions, i.e. the daily operation and facilitating new investments in the medium and longer term. This distinction has to be accepted and therefore requires some mix of new or improved policy instruments on the road towards a more carbon-neutral power system that incorporates VREs by 2030/35: policy instruments that have a clear impact on the market and on the investment decisions required. There is no other alternative for the investment function than that the state continues to be involved. But market forces for intraday balancing can be developed more than they are today, both on the demand side and on the side of the operating reserve. This is the operational part. Markets could also be obliged to operate faster by allowing them to work (very) closely to real time before balancing. Improving these markets will decrease the additional costs of a power system with larger shares of VRE. A better interaction between the grid and generation will further diminish the additional costs. As local cooperatives and local initiatives by well-informed citizens, asking for more involvement and promoting local strength, are becoming more and more visible and apparent, and as the energy industry is starting to re-invent itself by developing new business models and approaches, the uncertainty of the outcome has to be accepted. It goes without saying that government and its regulatory agencies are part of this process and should reflect in this dynamic policy environment in more effective and adaptive decision-making procedures.

The future is open, but not completely formless. Some of the options are easier to implement than others or are already being explored in individual countries. More flexibility of the system could start with the direct implementation of the recent EU Guidelines on State Aid. A further policy package could be developed quickly with improved ETS, adaptation of feed-in tariffs into premiums, programme responsibility for all generation sources (except the smaller ones), more demand-side integration and an increased role of balancing and intraday markets. A new way of dealing with the generation-network interaction and an introduction of EPS could bring about system improvements, but this needs further consideration. Capacity Remuneration Mechanisms, maybe in combination with a broader introduction of a Regulatory Asset Base, could be necessary, but other flexibility options have larger net benefits and could be introduced much more quickly. Finally, the state should act judiciously, allowing markets to perform their tasks wherever possible.

Pieter Boot, Jacques de Jong and Nico Hoogervorst, Clingendael International Energy Programme

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