Our most important findings

An interim target of at least 40% renewables in power generation is required in 2030 to transition towards a 100% objective in 2050. Electrification of heat, transport and industry, as well as various flexibility options (such as grid reinforcement, storage and demand-side flexibility) will facilitate the integration of renewables, while bringing down emissions to net zero in 2050.

The first step consists of a 45% reduction in greenhouse gas emissions by 2030 (relative to 2010). Second, emissions must decline by at least 90% by 2045 (relative to 2010). Finally, green synthetic fuels eliminate residual emissions, mostly from high-temperature heat generation in industry.

Direct electrification should therefore be prioritized wherever possible in transportation, space heating and low and mid-temperature heat in industry. Domestic production of green hydrogen will also put considerable pressure on the power system.

Renewables will outcompete nuclear new build and lifetime extension projects already by 2025, leading to a gradual phase-out of nuclear power plants at the end of their technical lifetime if not stopped earlier.

The upcoming discussions on the 6th Strategic Energy Plan and concrete regulatory measures, such as an effective carbon pricing mechanism, will be crucial to determine how Japan goes about achieving those interim 2030 targets and climate neutrality by 2050.

An interim target of at least 40% renewables in power generation is required in 2030 to transition towards a 100% objective in 2050. Electrification of heat, transport and industry, as well as various flexibility options (such as grid reinforcement, storage and demand-side flexibility) will facilitate the integration of renewables, while bringing down emissions to net zero in 2050.

The first step consists of a 45% reduction in greenhouse gas emissions by 2030 (relative to 2010). Second, emissions must decline by at least 90% by 2045 (relative to 2010). Finally, green synthetic fuels eliminate residual emissions, mostly from high-temperature heat generation in industry.

Direct electrification should therefore be prioritized wherever possible in transportation, space heating and low and mid-temperature heat in industry. Domestic production of green hydrogen will also put considerable pressure on the power system.

Renewables will outcompete nuclear new build and lifetime extension projects already by 2025, leading to a gradual phase-out of nuclear power plants at the end of their technical lifetime if not stopped earlier.

The upcoming discussions on the 6th Strategic Energy Plan and concrete regulatory measures, such as an effective carbon pricing mechanism, will be crucial to determine how Japan goes about achieving those interim 2030 targets and climate neutrality by 2050.

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.

Coal-fired power plants are in most cases less flexible compared to gas-fired generation units. But as Germany and Denmark demonstrate, aging hard coal fired power plants (and even some lignite-fired power plants) are already today providing large operational flexibility. They are adjusting their output on a 15-minute basis (intraday market) and even on a 5-minute basis (balancing market) to variation in renewable generation and demand.

Targeted retrofit measures have been implemented in practice on existing power plants, leading to higher ramp rates, lower minimum loads and shorter start-up times. Operating a plant flexibly increases operation and maintenance costs — however, these increases are small compared to the fuel savings associated with higher shares of renewable generation in the system.

In some power systems, especially when gas is competing against coal, the flexible operation of coal power plants can lead to increased CO2 emissions. In those systems, an effective climate policy (e.g. carbon pricing) remains a key precondition for achieving a net reduction in CO2 emissions.

Proper price signals give incentives for the flexible operation of thermal power plants. Thus, the introduction of short-term electricity markets and the adjustment of balancing power arrangements are important measures for remunerating flexibility.

With a renewable electricity target of 40% in France and 65% in Germany by 2030, the two countries will significantly increase their production of wind and solar energy. Their conventional power plant fleet will have to be resized accordingly to avoid stranded costs.

A nuclear fleet exceeding 40 GW in 2030 would increase the national electricity export surplus and additionally postpone the achievement of the objective of reducing the share of nuclear power to 50% beyond 2030. The profitability of a nuclear fleet greater than 50 GW would not be assured in 2030, even when assuming a 60% increase in French export capacity, a doubling of interconnectors capacity in Europe and a CO2 price of 30 euros per ton of CO2.

In this case, Germany’s electricity trade balance with its neighbours is balanced. The new planned target of 65% renewable energy in electricity consumption by 2030 will ensure that Germany will not depend on undesired electricity imports while phasing-out coal.

These joint actions could take the form of initiatives led by the two countries on the development of renewable energy, interconnectors or CO₂ pricing.

Beide Länder werden die Erzeugung von Wind- und Solarstrom bis 2030 deutlich erhöhen müssen, um ihre Ausbauziele für Erneuerbare Energien zu erreichen. Zur Vermeidung von Stranded Assets ist eine damit einhergehende schrittweise Reduktion konventioneller Kapazitäten unerlässlich.

Zu wachsenden Stromexporten Frankreichs würde es bereits kommen, wenn das Land mehr als 40 Gigawatt Kernkraftwerke im Jahr 2030 in Betrieb hielte. Zudem würde Frankreich sein Ziel, den Kernenergieanteil im Strommix auf 50 Prozent zu reduzieren, erst nach 2030 erreichen können. Selbst wenn eine Steigerung der französischen Stromexportkapazitäten um 60 Prozent, eine Verdopplung der Interkonnektoren innerhalb der Europäischen Union und eine CO2-Bepreisung von 30 Euro pro Tonne CO2 angenommen werden, wäre die Wirtschaftlichkeit eines Kernkraftwerksparks mit einer Kapazität von über 50 Gigawatt bis 2030 gefährdet.

In diesem Fall wäre die Bilanz für den grenzüberschreitenden Stromhandel zwischen Deutschland und seinen Nachbarländern ausgeglichen. Die geplante Erhöhung des Anteils der Erneuerbaren Energien auf 65 Prozent des Bruttostromverbrauchs im Jahr 2030 wird dazu beitragen, eine unerwünschte Importabhängigkeit Deutschlands trotz des Kohleausstiegs zu vermeiden.

Initiativen für den Ausbau der Erneuerbaren Energien und der Interkonnektoren sowie zur CO₂-Bepreisung sollten koordiniert werden.

Das Kohleausstiegsgesetz sieht bisher die Stilllegung aller Braunkohlenkraftwerke bis spätestens 2038 vor. Um das Sektorziel der Energiewirtschaft für das Jahr 2030 des Klimaschutzgesetzes einzuhalten, ist jedoch eine weitgehende Reduzierung der Emissionen aus der Braunkohlenverstromung schon bis zum Jahr 2030 notwendig. Die neue Bundesregierung hat sich deshalb das Ziel gesetzt, den Kohleausstieg idealerweise bis 2030 abzuschließen.

Der Anstieg der CO₂-Preise auf über 60 Euro pro Tonne CO₂ hat bewirkt, dass viele Braunkohlenkraftwerke ihre Betriebskosten perspektivisch nicht mehr decken können. Aufgrund des Anstiegs der Erdgaspreise hat sich der ökonomische Druck auf die Braunkohlenkraftwerke im Laufe des Jahres 2021 und auch für 2022 etwas entspannt. Ab spätestens 2024 ist jedoch zu erwarten, dass sich der Kohleausstieg marktgetrieben deutlich beschleunigen wird. Die im Koalitionsvertrag für 2021–2025 niedergelegten Regelungen, über die der CO₂-Preis bei mindestens 60 Euro liegen soll, wird diesen Prozess flankieren.

Die Planungen für die Braunkohlentagebaue orientieren sich bisher überwiegend an einem Kohleausstieg bis 2038. Um Risiken zu vermeiden, sollte die Tagebauplanung auf einen sich beschleunigenden Kohleausstieg bis 2030 angepasst und das bestehende System der Rückstellungen zur Wiedernutzbarmachung der Tagebaue umfassend überprüft werden. Auch hier entstehen mit dem Koalitionsvertrag 2021–2025 neue Prüfungs- und Handlungsbedarfe.

The Yellow Vests protests are primarily directed at upward social redistribution and not climate protection.

Over the last 18 months, the French government has abolished the wealth tax, increased flat-rate social security contributions, reduced housing subsidies and increased the tobacco tax. Taken together with the energy tax increase and a lack of compensation, these measures have contributed to the widening of economic inequalities in French society.

Like any consumption tax, the CO2 surcharge on energy consumption has a greater effect on low-income households than high-income households in percentage terms. This was also the case in France. A per capita redistri-bution of revenue or other redistribution mechanisms are necessary to balance this.

In France, most of the revenue from the CO2 surcharge on energy taxes was used for consolidating the budget. The contribution climat énergie was therefore not recognised by large parts of the population as a climate protection measure. In addition to so-cial compensation, it is therefore necessary to use the revenues for climate protection measures which are transparent and easily accessible.

Die Hauptursache für den Anstieg bei der EEG-Umlage ist ein gesunkener Börsenstrompreise infolge des Preisverfalls bei Erdgas (+1,1 Cent) sowie des Einbruchs der Stromnachfrage durch die Corona-Krise (+0,7 Cent).

Das Bundeskabinett hat jüngst vorgeschlagen, den von 2021 an geltenden CO2-Preis auf Benzin, Diesel, Heizöl und Erdgas von 10 auf 25 Euro je Tonne zu erhöhen. Werden die Mehreinnahmen entsprechend der Bund-Länder-Einigung im Vermittlungsausschuss vom Dezember 2019 komplett zur Senkung der EEG-Umlage eingesetzt, wird dadurch der Anstieg der Umlage um etwa 1,5 Cent pro Kilowattstunde gedämpft. Die eigentlich beabsichtigte Senkung der EEG-Umlage kann aber aufgrund der Corona-Effekte nicht erreicht werden.

Diese Finanzspritze von rund 12 Milliarden Euro zuzüglich 1 Milliarde Mehrwertsteuer im Zuge eines Corona-Wachstumspakets würde kurzfristig die Stromrechnung entlasten und Kaufkraft in gleicher Größenordnung stärken. Sie könnte ab 2022 sukzessive durch die steigenden Einnahmen aus der CO2-Bepreisung abgelöst werden. Bei einer nochmaligen Erhöhung des CO2-Preises wäre sogar die komplette Abschaffung der EEG-Umlage denkbar – angesichts aktuell sehr niedriger Öl- und Gaspreise eine historische Chance.

­Klimaverträgliche Alternativen werden durch einen CO2-Preis attraktiver und klima­schädigender Energieverbrauch teurer. Bisher existiert ein Preis für den Ausstoß klimaschädigender Gase nur für die vom Europäischen Emissionshandelssystem erfassten Treibhausgas-Quellen aus der Energiewirtschaft und der energieintensiven Industrie, nicht jedoch für die erheblichen CO2-Mengen aus dem Verkehrs- und Wärmesektor. Ein CO2-Preis auch in diesen Sektoren schafft wirtschaftliche Anreize zur Emissionsminderung durch Investitionen in klimaschonende Technologien und Verhaltensanpassungen.

Ein CO2-Preis führt bei den privaten Haushalten zunächst zu Mehrausgaben für Mobilität und Wärme. Bei einem Preis von 50 Euro je Tonne CO2 wird beispielsweise Benzin um circa 14 Cent je Liter teurer, Heizöl um knapp 16 Cent je Liter und Erdgas um etwa 1,2 Cent je Kilowattstunde. Die Rückverteilung erfolgt mittels einer „Klimaprämie“ von 100 Euro pro Kopf und Jahr sowie einer Stromsteuersenkung von rund 2 Cent je Kilowattstunde. Haushalte mit niedrigem Energieverbrauch werden durch eine solche Reform unter dem Strich entlastet, während Haushalte mit hohem Energieverbrauch und Treibhausgasausstoß höhere Kosten zu tragen haben. Untere und mittlere Einkommensgruppen erhalten im Durchschnitt mehr Geld zurück als sie für ihren – vergleichsweise geringen – CO2-Ausstoß zahlen.

Für Haushalte im ländlichen Raum treten keine nennenswerten systematischen Zusatzbelastungen durch die CO2-Bepreisung auf. Durch die an jeden ausgezahlte Klimaprämie profitieren insbesondere größere Haushalte und damit Familien. Auch die meisten Mieterhaushalte zählen zu den Gewinnern.

Trotz Rückverteilung der Einnahmen verbleiben auch in den unteren und mittleren Einkommensgruppen noch Haushalte, denen signifikante Zusatzkosten entstehen. Hierfür wird ein aus den CO2-Einnahmen gespeister Ausgleichsfonds in Höhe von etwa 300 Millionen Euro aufgesetzt, durch den diese Belastungen effektiv begrenzt werden können.

Dazu zählen beispielsweise Anreizprogramme für klimaeffizientes Heizen und Bauen, Informations- und Beratungsprogramme oder Investitionen in den öffentlichen Verkehr. Hierdurch werden Treibhausgas-Ausstoß und finanzielle Belastung der privaten Haushalte gleichermaßen reduziert. Ein CO2-Preis ist somit nur ein – unverzichtbarer – Baustein einer effektiven und sozial ausgewogenen Klimaschutzstrategie.

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.

The challenge of integrating a high share of wind power led Danish institutions and market participants to develop several flexibility options early on, including use of interconnectors to other countries, increasing the flexibility of thermal power plants, making district heating more flexible, encouraging system friendly wind power, implementing demand side flexibility as well as introducing alternative options for procuring ancillary services.

With 6.4 GW of net transfer capacity to Norway, Sweden and Germany (Danish peak demand: 6 GW), Denmark is able to sell electricity during times of high wind production, and to import electricity in times of low wind production. The use of the 2.4 GW net transfer capacity to Germany is sometimes limited for export depending on the wind conditions in Northern Germany.

Danish coal power plants have been optimised to allow very steep ramp-up gradients, shorter
start-up times and low but stable minimum generation levels. Flexibility in providing ancillary services has further reduced must-run capacity

Regulation has been reshaped to reduce heat bound electricity generation in situations with high wind energy feed-in. In the future district heating systems are envisioned to become electricity consumers rather than producers in times of high wind power production. In spite of changes already adopted to the energy tax system, further regulatory measures are still needed to tap the full potential of using power for heat.

The Danish power system has been undergoing a transformation, moving from a highly centralised to a more decentralised structure in electricity generation. There has been a significant increase not only in wind power but also in distributed generation from combined heat and power plants since the 1980s. Broad-based political agreements on energy policy have provided security for investors while enabling a smooth and continuous transition to a sustainable power sector.

The interdependencies among these different sectors are reflected in Danish energy policy goals, in scenario analyses as well as in concrete initiatives for implementing the transition to a renewables based energy system.

The Danish tendering scheme is characterised by Contracts for Difference with guaranteed support payments, a guaranteed grid connection and a one-stop-shop authority for  preliminary site assessments when new offshore wind energy projects are developed.

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.