Market Design

Market Design
Market Design

Summary

With the Energiewende the current electricity market comes to its limits. In future it will also have to provide security of supply and investment incentives.

The Energiewende implies a new design for Germany’s electricity market. The 1998 liberalized energy market deals exclusively with volumes of electricity; this is why it is often referred to as “energy-only” market. It is undisputed that the energy-only market will ensure that the cheapest power plants satisfy a given demand. Controversial however is whether the existing electricity market’s signals generate sufficient investment – both for new conventional power plants as well as for new renewable energy plants, such as wind turbines or photovoltaic systems.

In order to ensure security of supply in the few hours of peak load, sufficient capacity must always be available. This can be non-fluctuating renewable energies, fossil backup capacity, power storage, and sliding loads. There is an intense debate among economists whether the existing energy-only markets are capable of ensuring security of supply. In other words, will energy-only markets always have access to enough power to meet peak-load electricity demand? In many countries and regions with liberalized markets (such as on the east coast of the United States, Brazil, Spain, Great Britain, Russia, and South Korea), electricity market regulators have introduced additional tools to ensure reserve capacity, such as a capacity market. The reason is that supply security is a public good that benefits all electricity users. However, there is a high risk that the energy-only market cannot ensure an adequate security of supply.

The Energiewende exacerbates this issue: Even with ever increasing amounts of renewable energy Germany will require almost as many fossil fuel plants as we have today in order to compensate for low-wind and sun-deficient hours (for example, during winters) and to meet demand. However, many of these plants will operate only a few hours a year. Moreover, the question of necessary capacity to ensure security of supply in Germany has a special relevance. From 2015 to 2022 all of the remaining nuclear capacity will be phased out, relieving the system of twelve gigawatts (GW) of capacity. And most of that capacity (8 GW) will go offline in a very short period, namely from 2020 to 2022.

In addition, there is the question of whether the energy-only market will ever be in a position to refinance wind power and solar power, even if their total costs are below those of coal or gas power plants. For the problem of wind power and photovoltaic systems, based as they are on the marginal-cost-determined spot market, is that they price themselves out of the market. When the wind blows and the sun shines, all the wind and PV systems within the same weather zone produce electricity at the same time. Once a certain number of wind turbines and PV systems are in the system, this impacts the price on the electricity market. Thus, when the wind blows and/or the sun shines, a lot of power is available with a marginal cost of zero, the market price decreases because power plants with more expensive marginal cost won’t be needed and power plants with lower marginal costs will determine the market price (the so-called merit-order effect). As a consequence, wind and solar power cannot refinance themselves on today’s break-even market.

In this context, Agora Energiewende is addressing the question of how an “Energiewende market” could look like. The task of a new Energiewende market must be to simultaneously enable existing power plants to operate cost efficiently and to create incentives for the necessary investments to ensure security of supply. Moreover, it has to foster the continued expansion of renewable energy according to the existing Energiewende targets.

Core results

  1. Renewable energy investments are more capital intensive than investments in fossil-fired power generation.

    They are also much more sensitive to political and regulatory risks. This is highly relevant when addressing Europe’s 2030 renewables framework consisting of a binding EU target without binding Member States targets.

  2. The costs of capital for renewables vary widely between Member States.

    Perceived ex-ante risks translate into country specific premiums on the costs for renewable energy investments that have nothing to do with technology risks or weather conditions.

  3. Equalising costs of capital throughout the EU would save taxpayers at least 34 billion Euros to meet the 2030 renewables target.

    It would also allow for broader sharing of the social, economic and health benefits of renewable energy investments, and would particularly benefit EU Member States with lower than average per capita GDP.

  4. The revised EU Renewable Energy Directive should address differences in cost of capital by establishing an EU Renewable Energy Cost Reduction Facility.

     This could empower Member States that choose to use the facility to develop their renewable energy sources at costs currently enjoyed for renewable investments in Germany or France.

  5. An EU Renewable Energy Cost Reduction Facility would support decarbonisation and help facilitate the common energy market.

    This would be done by broadening the support for renewable energy investments amongst Member States and facilitating the further convergence of national renewable energy frameworks.

  1. Europe needs a “Renewable Energy Cost Reduction Facility (RES-CRF)” to fill the high-cost-of-capital-gap which currently exists in many member states in Central and South-Eastern Europe.

    Wind and solar are today cheap technologies that are on equal footing with coal and gas. However, high cost of capital oftentimes hinders renewables projects from going forward, even when there is excellent potential. Bridging that gap, a RES-CRF will bring significant cost savings to consumers and taxpayers in those countries

  2. The RES-CRF would provide a fifty-fold leverage of private-sector finance and will phase-out automatically as market confidence in high cost of capital Member States increases.

    The risk of the financial guarantee underpinning the RES-CRF ever being called is very small. We propose a set of concrete safeguards to ensure only high quality renewable energy investments will benefit and to avoid over-commitments.

  3. The next EU Multiannual Financial Framework should be used to finance the RES-CRF as a cheap support for the 2030-targets.

    Committed public funds to implement Article 3.4 of the new EU Renewable Energy Directive would create scope for establishing the RES-CRF. This would help Europe to meet its 2030-renewable energy target and enable all Member States to benefit from low-cost renewable energy.

  4. A pilot project should be launched before 2020 for proof of concept.

    A key design feature of the RES-CRF is its flexibility. Being largely based on contractual arrangements, it can be tested in specific sectors or Member States before a wider roll-out. Launching a pilot project before 2020 would help strengthen confidence in the instrument. A pilot can be financed from the running EU budget.

  1. Wind and solar PV drive power system development.

    As part of Europe’s renewable energy expansion plans, the PLEF countries will strive to draw 32 to 34 percent of their electricity from wind and solar by 2030. The weather dependency of these technologies impacts power systems, making increased system flexibility crucial.

  2. Regional European power system integration mitigates flexibility needs from increasing shares of wind and solar.

    Different weather patterns across Europe will decorrelate single power generation peaks, yielding geographical smoothing effects. Wind and solar output is generally much less volatile at an aggregated level and extremely high and low values disappear. For example, in France the maximum hourly ramp resulting from wind fluctuation in 2030 is 21 percent of installed wind capacity, while the Europe-wide maximum is only at 10 percent of installed capacity.

  3. Cross-border exchange minimises surplus renewables generation.

    When no trading options exist, hours with high domestic wind and solar generation require that generation from renewables be stored or curtailed in part. With market integration, decorrelated production peaks across countries enable exports to regions where the load is not covered. By contrast, a hypothetical national autarchy case has storage or curtailment requirements that are ten times as high.

  4. Conventional power plants need to be flexible partners of wind and solar output.

    A more flexible power system is required for the transition to a low-carbon system. Challenging situations are manifold, comprising the ability to react over shorter and longer periods. To handle these challenges, the structure of the conventional power plant park and the way power plants operate will need to change. Renewables, conventional generation, grids, the demand side and storage technologies must all become more responsive to provide flexibility.

  1. The European power system will be based on wind power, solar PV and flexibility.

    The existing climate targets for 2030 imply a renewables share of some 50 percent in the electricity mix, with wind and PV contributing some 30 percent. The reason is simple: they are by far the cheapest zero-carbon power technologies. Thus, continuous investments in these technologies are required for a cost-efficient transition; so are continuous efforts to make the power system more flexible at the supply and demand side.

  2. Making the Energy-Only Market more flexible and repairing the EU Emissions Trading Scheme are prerequisites for a successful power market design.

    A more flexible energy-only market and a stable carbon price will however not be enough to manage the required transition to a power system with high shares of wind and solar PV. Additional instruments are needed.

  3. A pragmatic market design approach consists of five elements: Energy-only market, emissions trading, smart retirement measures, stable revenues for renewables, and measures to safeguard system adequacy.

    Together, they form the Power Market Pentagon; all of them are required for a functioning market design. Their interplay ensures that despite legacy investments in high-carbon an inflexible technologies, fundamental uncertainties about market dynamics, and CO2 prices well below the social cost of carbon, the transition to a reliable, decarbonised power system occurs cost-efficiently.

  4. The Power Market Pentagon is a holistic approach to the power system transformation. When designing the different elements, policy makers need to consider repercussions with the other dimensions of the power system.

    For example, introducing capacity remunerations without actively retiring high-carbon, inflexible power plants will restrain meeting CO2 reduction targets. Or, reforming the ETS could trigger a fuel switch from coal to gas, but cannot replace the need for revenue stabilisation for renewables.

From study The Power Market Pentagon
  1. Netzengpässe sind in manchen Regionen die neue Normalität. Ihre Behebung bedarf regionaler Flexibilität. Das sind die Lehren aus den steigenden Redispatch- und Windstromabregelungsmengen. Ergänzend zum bundesweiten Strommarkt sind deshalb neue regionale Smart Markets notwendig.

    Sie haben zum Ziel, regionale Flexibilität zu mobilisieren und damit die Effizienz des Systems zu erhöhen. Sie dienen der Vermeidung und Behebung von Netzengpässen. Damit reduzieren sie Redispatch- und Einspeisemanagementmaßnahmen.

  2. Die Netzregionen stehen vor unterschiedlichen Herausforderungen, deswegen eignen sich unterschiedliche Smart-Market-Modelle je nach Netzregion.

    In winddominierten Gebieten entlasten Smart Markets Netzengpässe durch den Einsatz von Nachfrageflexibilitäten wie Power-to-Heat. Hier eignen sich Modelle mit Flexibilitätsbezug durch den Netzbetreiber. In last- und photovoltaikdominierten Regionen geht es darum, Engpässe durch hohe Gleichzeitigkeit von Lasterhöhung (zum Beispiel Nachtspeicherheizungen, in der Zukunft Aufladen von Elektroautos) oder von Stromeinspeisung in die unteren Verteilnetzebenen zu verringern. Hier eignen sich eher Quotenmodelle, die auch mit Sekundärmarkt ausgestaltet werden können.

  3. Der Kosten-Benchmark für Smart Markets sind die derzeitigen Redispatch- und Einspeisemanagementkosten – diese müssen sie unterbieten. Deswegen stellen die hierfür gezahlten Vergütungen auch die Preisobergrenze für regionale Flexibilitätsprodukte dar.

    Mittelfristig stellt sich bei einer hohen Verbreitung von Elektroautos die Frage nach dem optimalen Mix aus Netzausbau und Netzengpassbehebung – und wer dabei welche Kosten trägt.

  4. Smart Markets sind eine No-Regret-Option, für deren Umsetzung regulatorische Hemmnisse abgebaut und Ansätze bereits bestehender Regelungen weiterentwickelt werden müssen.

    Zentral ist hierbei auch eine Reform der Entgelte, Steuern, Abgaben und Umlagen, da sie entscheidenden Einfluss auf die (regionale) Bereitstellung von Flexibilität haben. Vor allem sind Interaktionen mit bestehenden Strommärkten, eine Weiterentwicklung in der Netzplanung sowie in der Koordination zwischen den Akteuren bezüglich Datenaustausch und Steuerung zu beachten.

  1. Effizienz und Flexibilität wachsen zusammen zu einem gemeinsamen Konzept: Flex-Efficiency.

    Denn mit immer mehr Erneuerbaren Energien in der Stromversorgung bekommt Effizienz eine zeitliche Komponente: Wenn die Sonne nicht scheint oder der Wind nicht weht, steigen die Strombörsenpreise – und Stromeffizienz wird wertvoller als in Zeiten hoher Erneuerbare Energien-Stromproduktion.

  2. Flex-Efficiency wird zum Paradigma für Design und Betrieb von Industrieanlagen.

    Mit zunehmenden Anteilen von Wind- und Solarstrom werden die Preisschwankungen an der Strombörse steigen. Bei der Entwicklung neuer Industrieanlagen sollten Energieeffizienz und Flexibilität schon heute gemeinsam gedacht werden, um in Zukunft von den Stunden mit niedrigen Preisen zu profitieren.

  3. Die Flexibilitätsmärkte und deren Produkte sollten weiter verbessert werden.

     Marktzugang, Marktstrukturen und die richtigen Produkte (zum Beispiel abschaltbare Lasten und weiteres Demand Side Management) sind entscheidend dafür, dass Marktpreissignale einen aus Systemsicht optimierten und zugleich wirtschaftlichen Betrieb der Anlagen oder entsprechende Investitionen anreizen.

  4. Investitionen in Flex-Efficiency brauchen eine Kombination von marktlichen und anderen Anreizen.

    Marktpreise generieren gute Anreize für die Optimierung und den Betrieb großer, energieintensiver Anlagen. Sie versagen jedoch oft bei „durchschnittlichen“ Prozessen, Speichern und Querschnittstechnologien. Ergänzende Instrumente sind erforderlich, um dieses Potenzial zu heben.

From study Flex-Efficiency
  1. Short-term markets in Central Western Europe are characterised by a rather inefficient patchwork of flexibility enabling and disabling design elements.

    Some key design elements of intraday and balancing markets as well as imbalance settlement rules distort wholesale power price signals, increasing the cost of providing flexibility. This highlights the need to adjust key market design elements and requires continuous political momentum to coordinate efforts regionally.

  2. Current market designs are biased against demand side response and renewables.

    Restrictive requirements for market participation, mainly relating to demand response and renewables, constrain the flexibility potential. In the balancing markets, small minimum bid sizes and short contracting periods would be required. A regulatory framework enabling independent aggregation should be implemented for fully tapping the flexibility potential.

  3. Balancing market rules show large differences across the region, leading to inefficient pricing in preceding day-ahead and intraday markets.

    A joint balancing market design in the PLEF region with short product duration, late gate closure and marginal pricing would enable efficient cross-border competition for flexibility services. Getting the pricing right in balancing mechanisms is important as it support sefficient pricing in preceding day-ahead and intraday markets – where most of the flexibility is traded.

  4. Cross-border intraday trading needs reform to improve efficiency and enhance liquidity.

    Intraday markets are critical for integrating wind and solar, as they allow for trades responding to updated generation forecasts. Today, explicit cross-border capacity allocation as well as misalignments in gate closure times across the region and differing product durations result in inefficient intraday energy and interconnector capacity allocation. Thus, harmonised rules and improved implicit cross-border allocation methods are needed, e.g. improved continuous trading or intraday auctions.

  1. Das derzeitige System der Stromkennzeichnung wird dem Transparenzanspruch gegenüber dem Verbraucher nicht gerecht.

    Das reale Beschaffungsverhalten der Versorger wird nicht abgebildet, es fehlen Klima-Kennwerte und die Anteile des EEG-geförderten Stroms am Unternehmensmix unterscheiden sich, obwohl private Endverbraucher die gleiche EEG-Umlage bezahlen. Das ist nicht vermittelbar und  führt zu rechtlichen Risiken. Eine Revision der Stromkennzeichnung ist erforderlich.

  2. In einer Welt von absehbar mehr als 50 Prozent Erneuerbaren steigt das Interesse der Verbraucher an konkreten Energiewende-Stromprodukten.

    Der Ausbau der Erneuerbaren ist als Gesellschaftsprojekt über die EEG-Umlage organisiert, das  Interesse an Strom konkreter regionaler und technischer Herkunft steigt jedoch. Die Regelung,  wonach jeder Umlagezahler eine rein rechnerische Menge EEG-Strom pauschal zugewiesen bekommt, sollte entsprechend weiterentwickelt werden.

  3. Investitionssicherheit für Anlagenbetreiber und Ökostromprodukte aus EEG-Strom müssen kein Widerspruch sein.

    Der Blick ins europäische Ausland zeigt, wie eine staatlich garantierte Erneuerbare-Energien-Finanzierung mit handelbaren Herkunftsnachweisen kombiniert werden kann. Dies ist im Rahmen des geltenden EEG 2014 nicht darstellbar.

  4. Bei der Weiterentwicklung des EEG sollte die Vermarktung von gefördertem EEG-Strom ermöglicht werden.

    Wichtigstes Ziel ist dabei eine verbesserte Akzeptanz der Energiewende. Ein denkbarer Ansatz ist das europäische System der Herkunftsnachweise, verbunden mit einer revidierten und besser kontrollierten Stromkennzeichnung.

  1. Already now, Germany and France are helping each other guarantee security of supply.

    Whenever there iscapacity shortage in one country, prices in that country rise, favoring power plants in the other country to export. This is done automatically via market coupling.

  2. A joint German-French shortage situation is currently very rare, but may occur more often.

    A cross-border challenge in security of supply arises only during days with very cold weather and very little wind in both countries at the same time. An analysis of historical weather data suggests that after 2023 this might occur about six days in ten years.

  3. The unilateral introduction of a capacity mechanism in France benefits French power generators and German consumers – but the redistributive effects are likely to be small.

    Different market designs between Germany and France will generate some redistributive effects, but they are limited by the level of interconnections between the two countries (currently 3 GW) and joint market coupling with other European countries.

  4. The French decentralized capacity mechanism and the proposal developed by the German energy associations BDEW/VKU, though globally based on the same principles, differ in important respects.

    The French proposal, while effectively decentralized by nature, relies significantly on regulated components, with a centra lrole going to the TSO. Similar design elements are currently missing in the BDEW/VKU model, leaving the question open as to who would actually supervise, control and sanction this scheme in Germany.

  5. Cross-border participation in capacity mechanisms raises fundamental technical and regulatory questions.

    These questions include monitoring and control issues as well as rules for delivering capacities in foreign markets without interfering with market coupling. Addressing these questions requires political and technical cooperation on both sides of the border, especially when it comes to situations of joint scarcity.

  1. Tendering procedures for renewable energy need to be carefully designed.

    The introduction of competitivebidding for a specific renewable-energy technology in a given country needs to be preceded by a thorough analysis of the conditions for successful tendering, including market structure and competition. Specific project characteristics of the various renewable-energy technologies must be considered appropriately in the auction design.

  2. Pilot tenders should be used to enable maximum learning.

    Prior to adoption of tendering schemes, multiple design options should be tested in which the prequalification criteria, auction methods, payment options, lotsizes, and locational aspects are varied. Learning and gaining experience is of utmost importance, as poor auction design can increase overall costs or endanger deployment targets.

  3. The most challenging technology for auctions is onshore wind.

    Experiences made with auctions for certain technologies (e.g. solar PV) cannot be readily applied to other types of renewable energy. Onshore wind is particularly difficult due to the complexity of project development, including extended project time frames (often over two years), the involvement of multiple permitting authorities and the need for local acceptance.

  4. Inclusion of a variety of actors is a precondition for competition and efficient auction outcomes.

    The auction should be designed to facilitate a sufficiently large number of participating actors, as this will minimise strategic behaviour and ensure a level playing field for all actors, thus enabling healthy competition. As renewable deployment often hinges critically on local acceptance, enabling the participation of smaller, decentralised actorsin auctions is important.

  1. Tendering procedures for renewable energy need to be carefully designed.

    The introduction of competitivebidding for a specific renewable-energy technology in a given country needs to be preceded by a thorough analysis of the conditions for successful tendering, including market structure and competition. Specific project characteristics of the various renewable-energy technologies must be considered appropriately in the auction design.

  2. Pilot tenders should be used to enable maximum learning.

    Prior to adoption of tendering schemes, multiple design options should be tested in which the prequalification criteria, auction methods, payment options, lotsizes, and locational aspects are varied. Learning and gaining experience is of utmost importance, as poor auction design can increase overall costs or endanger deployment targets.

  3. The most challenging technology for auctions is onshore wind.

    Experiences made with auctions for certain technologies (e.g. solar PV) cannot be readily applied to other types of renewable energy. Onshore wind is particularly difficult due to the complexity of project development, including extended project time frames (often over two years), the involvement of multiple permitting authorities and the need for local acceptance.

  4. Inclusion of a variety of actors is a precondition for competition and efficient auction outcomes.

    The auction should be designed to facilitate a sufficiently large number of participating actors, as this will minimise strategic behaviour and ensure a level playing field for all actors, thus enabling healthy competition. As renewable deployment often hinges critically on local acceptance, enabling the participation of smaller, decentralised actorsin auctions is important.

  1. Resource adequacy is not only about “how much?”, but also about “what kind?”.

    The power system of the future will require a mix of flexible resources in order to efficiently address resource adequacy. On the supply side, more peak and mid-merit plants and fewer inflexible baseload plants will be needed. In addition, the activation of flexibility potential on the demand side will be crucial.

  2. Resource adequacy should be assessed on a regional level.

    Regional resource adequacy assessments lower the costs of achieving a reliable power system and mitigate the need for flexibility. For a given resource adequacy standard, the quantity of required resources decreases and the options for balancing the system expand as the market size increases.

  3. A reformed energy-only market is a no-regret option.

    Making the energy-only market faster and larger is crucial to meeting the flexibility challenge. Further integrating short-term markets across borders as well as vertically linking the different segments (day-ahead, intraday and balancing markets) can help to reduce flexibility requirements. This will also allow markets to better reflect the real-time value of energy and balancing resources.

  4. If resource adequacy is addressed through a capacity mechanism, resource capability rather than capacity needs to be the primary focus.

    Security of supply will increasingly become a dynamic issue. Future capacity mechanisms will need to consider this by focussing not just on capacity in a quantitative sense but also on operational capabilities. This will minimise price spillover effects of capacity mechanisms to energy-only markets while also fostering greater reliability at lower costs.

  1. In welcher Form Ausschreibungen für die unterschiedlichen Technologien der Erneuerbaren Energien sinnvoll eingesetzt werden können, ist derzeit noch völlig offen.

    Die Zeit bis zur nächsten EEG-Novelle 2016 muss intensiv genutzt werden, um herauszu?nden, ob die Erfolgsvoraussetzungen für Ausschreibungen bei Photovoltaik, Onshore-Windkraft, Offshore-Windkraft sowie Biomasse jeweils erfüllt sind und wie die unterschiedlichen Marktstrukturen und Projektcharakteristika im Auktionsdesign zu berücksichtigen sind.
     

  2. Pilotausschreibungen sollten maximales Lernen ermöglichen.

    Dazu sollten mehrere Varianten erprobt werden, wie Präquali?kation, Auktionsverfahren, Vergütungsoptionen, Losgrößen und Standortaspekte. Denn ein falsches Auktionsdesign ab 2017 kann die Gesamtkosten erhöhen oder die Ausbauziele gefährden.

  3. Pilotausschreibungen sollten auch für Onshore-Windkraft durchgeführt werden.

    Die Erkenntnisse aus der derzeit für 2015 vorgesehenen Photovoltaik-Pilotausschreibung sind kaum übertragbar auf andere wichtige Erneuerbare Energien.

  4. Funktionierende Ausschreibungen setzen Anbietervielfalt voraus.

    Das Auktionsdesign muss die Teilnahme kleinerer, dezentraler Akteure ermöglichen, auch um strategisches Verhalten zu erschweren.

  1. Nur ein kleiner Teil des Strompreises von Endkunden ist vom Börsenpreis abhängig.

    Vor allem bei kleinerenKunden dominieren konstante Strompreisbestandteile. Dies ist ein Hemmnis bei der Mobilisierungvon Lastmanagementpotenzialen.

  2. Besserstellungen des Eigenverbrauchs dürfen nicht zu verminderter Effizienz und Flexibilität des Systems führen.

    Heutige Umlagebefreiungen isolieren die Eigenverbrauchsanlagen weitgehend von den Preissignalen der Strombörse und erschweren somit die Systemintegration von Erneuerbaren Energien.

  3. Eine Dynamisierung der EEG -Umlage kann Lastmanagementpotenziale mobilisieren und verbessert die Systemintegration der Eigenerzeugung.

    Sie gibt Anreize zur Steuerung der Erzeugung und Lastanpassungsowie zur Vermeidung negativer Preise. Dies führt zur Kostensenkung sowohl bei der Eigenerzeugungals auch im Gesamtsystem.

  1. Die gegenwärtigen Ausnahmeregelungen im EEG müssen grundlegend reformiert werden, da sonst eine sich selbst verstärkende EEG-Umlagen-Erhöhung droht.

    Das derzeitige Modell benachteiligt kleine und mittelständische Unternehmen, führt zum Outsourcing von Beschäftigung und reizt ineffiziente Eigenstromkraftwerke an. 

  2. Eine europarechtskonforme Reform begrenzt die Ausnahmen auf Industrien, die energie- und exportintensiv sind – und führt keine unternehmensbezogene Kriterien ein.

    Privilegiert wären dann die 15 Sektoren, die derzeit unter die EU-Emissionshandels-Strompreiskompensation fallen, u.a. Chemie, Eisen, Stahl, Aluminium, Kupfer, Papier.

  3. Auch privilegierte Industrien und Eigenstromerzeuger sollten sich mit reduzierten Sätzen an der EEG-Finanzierung beteiligen.

    Denn energieintensive Industrien profitieren von den durch die Erneuerbaren Energien gesenkten
    Strompreisen, Eigenstromerzeuger von der Existenz des Gesamtsystems.

  4. Eine solche Reform der EEG-Ausnahmeregelungen gleicht Energie-, Industrie- und Verbraucherinteressen aus und senkt die EEG-Umlage um 20% von 6,24 auf 5 ct/kWh.

    Privilegierte Industrien zahlen dann einen reduzierten Umlagesatz von 10% (ca. 0,5 Cent), Eigenstromerzeuger erhalten einen Freibetrag von 3,5Cent (EEG-Beitrag ca. 1,5 Cent).


  1. Beim Schritt von 25 % auf 50 % Erneuerbare Energien werden systemdienliche Auslegung und Betrieb der EE-Anlagen zentral, da sonst die Gesamtsystemkosten deutlich steigen.

    Systemdienliche Auslegung und systemdienlicher Betrieb von Wind- und Solaranlagen werden jedoch von der derzeitigen EEGFinanzierungsform, der gleitenden Marktprämie, kaum angereizt.
     

  2. Der Energy-only-Marktpreis wird EE-Anlagen nie ausreichend refinanzieren, muss jedoch als zentrale Steuerungsgröße des Gesamtsystems bei den EE-Anlagenbetreibern unverzerrt ankommen.

    Die gleitende Marktprämie des geltenden EEG verzerrt aber das Preissignal des Spotmarkts, mit der Folge vermehrt auftretender negativer Börsenpreise und entsprechend steigender EEG-Umlage.
       

  3. Im EEG 2016 sollte daher die Finanzierung von EE-Anlagen auf die Zahlung von Kapazitätsprämien für systemdienliche Kapazität umgestellt werden.

    Diese Umstellung bedeutet zwar, dass EE-Anlagenbetreiber das Strompreis-Risiko übernehmen müssen, gleichzeitig reduziert es jedoch ihr Wetterrisiko. Ein Risikobandbreitenmechanismus kann zudem das Strompreis-Risiko begrenzen.

  4. Der Übergang zu Ausschreibungen für systemdienliche Kapazitäten sollte schrittweise erfolgen und durch Sonderregeln für kleine Projekte aus dem Bereich der Bürgerenergie ergänzt werden.

    Die für das EEG 2016 vorgesehenen Ausschreibungen werden nicht für alle Technologien und Anlagenklassen in kurzer Frist möglich sein. In diesen Segmenten sollte mit festgesetzten Kapazitätsprämien begonnen werden.

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