Our most important findings

Für 2021 droht sogar ein Rückgang der installierten Leistung. Dies gefährdet die Wirtschaft, denn ohne deutlich mehr günstigen Windstrom steigt der Börsenstrompreis in den nächsten Jahren deutlich an. Dies gilt erst recht angesichts erwartbar steigender CO₂-Preise im Zuge der Umsetzung des höheren EU-2030-Klimaziels.

Das 2017 erreichte Zubauniveau ist dauerhaft nötig. Denn bis 2030 müssen die Erneuerbaren nicht nur die Kohle ersetzen, sondern auch den zusätzlichen Strombedarf im Zuge der Sektorenkopplung decken. Der im EEG-Entwurf vorgesehene Ausbau, der zudem erst 2028 wirklich steigen soll, geht an der Realität vorbei.

Es umfasst eine Erhöhung der Ausschreibungsmengen, Maßnahmen zur kurzfristigen Bereitstellung

zusätzlicher Flächen, Regelungen für Weiterbetrieb und Repowering von EE-Altanlagen, eine vereinfachte Planungsmethodik sowie erste Schritte hin zu einem modifizierten Artenschutzregime.

Klimaneutralität ist Deutschlands Beitrag zum Erhalt einer intakten Natur. Um sie zu erreichen, braucht es Windkraft an Land mit einer Leistung von etwa 130 Gigawatt bis spätestens 2050.

Hierbei wurde bereits unterstellt, dass die Solarenergie weiterhin mit vier Gigawatt pro Jahr und Offshore-Windenergie auf 20 Gigawatt bis 2030 zugebaut wird. Das 65-Prozent-Erneuerbaren-Ziel für 2030 rückt so in weite Ferne.

Bei nur 55 Prozent Erneuerbaren-Anteil steigen die Börsenstrompreise im Jahr 2030 um etwa 5 bis 10 Euro je Megawattstunde und die Emissionen um etwa 5 bis 20 Millionen Tonnen CO₂.

Bei gleichbleibendem Stromverbrauch sind für das 65-Prozent-Ziel zwei der drei genannten Zubaupfade für Offshore-Windkraft, Onshore-Windkraft und Solarenergie nötig. Geht man für 2030 von einem höheren Stromverbrauch aus – wegen zunehmender Elektromobilität, mehr Wärmepumpen, Wasserstoffgewinnung und zusätzlichem Ökostrombedarf in der energieintensiven Industrie –, müssen alle drei Maßnahmen umgesetzt werden.

Hierzu gehört ein Maßnahmenpaket, das durch geeignete und einheitliche Planungsverfahren für ausreichend Flächen zur Errichtung von Windenergie an Land sorgt und Genehmigungsverfahren beschleunigt. Auch bei Offshore-Windkraft müssen jetzt rasch die Weichen für höhere Zubaumengen bis 2030 gestellt werden.

By 2030, renewables will account for 55% of power generation in Europe, and 50% of power generation in SEE. Nearly 70% of renewable power in SEE will stem from wind and solar, given the excellent resource potential of these renewables in the region.

For example, wind generation can fluctuate from one hour to the next by up to 47% in Romania, whereas the comparable figure for Europe is just 6%. Moving from national to regional balancing substantially lowers national flexibility needs. Increased cross-border interconnections and regional cooperation are thus essential for integrating higher levels of wind and PV generation.

Accordingly, conventional power plants will need to flexibly mirror renewables generation: When renewables output is high, conventionals produce less, and when renewables output is low, fossil power plants increase production. Flexible operations will become an important aspect of power plant business models.

The available reserve capacity margin in SEE will remain above 35% in 2030. More interconnectors, market integration and regional cooperation will be key factors for maximising national security of supply and minimising power system costs. SEE can be an important player in European power markets by providing flexibility services to CEE in years of high hydro availability.

This would be roughly in line with the quickest deployment levels seen in previous years. With a rapid decline in technology costs, wind and solar can serve as a substitute for new nuclear and hydro, which current plans foresee growing at an unrealistically high rate.

Restructuring the power system will be essential in order to keep it reliable and cost-effective. Inflexible baseload technologies and non-merit-order-based, coarse-scale dispatch are incompatible with a system that is increasingly dominated by weather-dependent power generation technologies.

Recent policy reforms have moved in the right direction, as China has started pilot projects for emissions trading, has reviewed its renewables remuneration scheme, and has acknowledged the need to create a power spot market. However, fundamental challenges remain to be addressed. These include overcapacity in coal-fired assets, an inflexible dispatch system, and a lack of data transparency and accessibility for market participants.

China has the opportunity to leapfrog to a renewables-led power system design that ensures cost-effectiveness and reliability. The Five Golden Rules we develop in this paper will help policy makers view the various policy instruments and emerging sectoral markets both pragmatically and coherently while taking into account interdependencies and avoiding inconsistencies:

Golden Rule 1: Use existing generation capacity efficiently by implementing short-term markets

Golden Rule 2: Incentivise flexibility to ensure system reliability and adequacy

Golden Rule 3: Provide stable revenues for new investment in renewables

Golden Rule 4: Manage the decline of coal and its structural consequences

Golden Rule 5: Acknowledge the pivotal role of transparency and data accessibility

Cumulated cost effects from national regimes on planning, permitting, grid connection and usage, taxation and financing range from 12 EUR/MWh in Germany to 26 EUR/MWh in Belgium. A wind park in Belgium would thus need to have 20% more full load hours than a German wind park to equalise these effects of the national policy environment.

Cross-border cooperation on renewables is addressed i.a. in the EU Renewable Energy Directive, in the EU Regulation on the Governance of the Energy Union and in EU State Aid rules. A prerequisite for successful implementation is to better understand how national regulatory environments outside renewable energy support frameworks shape investor choices.

Governments and regulators involved may agree on the coordinated convergence of some regulatory conditions towards recognised best practice. Where convergence is not feasible or desirable, the focus will be on whether and how to account for existing differences in the design of competitive auctions.

These learnings will be relevant e.g. in the context of the EU 2030 renewables gap filler mechanism or the Renewable Energy Projects of European Interest.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.