Our most important findings

By 2050, carbon-free hydrogen or hydrogen-based fuels will supply roughy one fifth of final energy worldwide, with much of the rest supplied by renewable electricity. Everyone agrees that the priority uses for hydrogen are to decarbonise industry, shipping and aviation, and firming a renewable-based power system. Therefore, we should anchor a hydrogen infrastructure around no-regret industrial, port and power system demand.

This is critical for incentivising hydrogen use where carbon pricing alone cannot do the job quickly enough. While policy options are available at a reasonable cost for industry, power and aviation, there is no credible financing strategy for hydrogen use by households. Blending is insufficient to meet EU climate targets and carbon prices high enough to deliver hydrogen heating would be unacceptable for customers.

To stay on track for 1.5C, Europe needs to reduce consumption of natural gas in buildings by 42 percent over the next decade, as per the EU Impact Assessment. Similarly, land-based hydrogen mobility will remain a niche application. Any low-pressure gas distribution grids that survive will be close to ports, where refuelling and storage infrastructure could provide an impetus for the decarbonisation of the maritime and aviation sectors.

To keep industry competitive, the EU should therefore access cheap hydrogen (green and near-zero carbon) from its neighbours via pipelines, reducing transport cost. Imports from a global market will focus on renewable hydrogen-based synthetic fuels.

Such a fully decarbonised system will be much more decentralised while relying on renewables, flexibility and an active ­demand-side. The EU Commission should initiate a well-prepared debate on necessary further adjustments to EU power market rules during the legislative period that starts in 2024.

Renewables investment should be ramped up to close the supply gap and reduce Europe’s dependence on fossil fuel imports. Annual onshore wind deployment needs to triple while annual offshore wind and solar PV deployment needs to quadruple by 2030. Marginal ­pricing on wholesale markets will ensure the efficient use of electricity, balance supply through cross-border trade and enable demand-side flexibility and storage.

CfDs can ensure predictable revenue streams from renewable energy projects, thus reducing risks for investors and lowering financing costs. CfDs can also facilitate the market integration of renewables and skimming-off of windfall profits, generating revenues that can be used for targeted support. To quickly scale up renewables deployment, investors should be able to decide whether to use government-backed CfDs or to develop merchant-based renewables projects, e.g. through PPAs.

A harmonised EU approach to reducing windfall profits during emergency situations should replace the current inframarginal revenue cap, as the uneven and unpredictable implementation of the revenue cap is scaring off renewables investors. In the medium term, with a growing volume of renewable electricity produced under CfDs and PPAs, windfall profit claw-backs will become less relevant.

Producing electricity from renewable energy sources and green hydrogen will cost 15 percent less up

to 2045 than relying on lignite or gas. A full decarbonisation of the region’s power system will require

a total investment of 43 billion euros over 30 years, 12 billion euros more than the fossil baseline. Even if investments are higher, renewables deployment can largely be financed from market revenues.

A reliable yet carbon-free power system can be achieved with a combination of renewables, storage (hydro, batteries, thermal storage) and 5 GW of green hydrogen fuelled power plants. Deeper regional integration can further reinforce security of supply.

The need for more ambitious climate action together with high and volatile fossil gas prices and ever cheaper renewables undermine the business case for new fossil gas infrastructure: any new fossil gas plant risks becoming a “stranded asset”. If the Western Balkan countries invest in hydrogen-ready infrastructure and storage technologies instead, they can reduce cumulative fossil gas demand by 50 percent up to 2045 while cutting overall costs by 12 percent compared to a strategy that bets on fossil gas to replace aging lignite.

Greater energy storage capacity enables rapid growth in PV, the most easily scalable renewables

technology. Storage also lowers the need for hydrogen power plants that will replace gas plants. It

is important not to overestimate hydrogen needs when planning for corresponding infrastructure. 5 GW of green hydrogen plants, covering 7 percent of demand in 2045, are needed for power system security of supply.

The CBAM is a necessary tool for the EU to prevent carbon leakage; it is not an instrument to force trading partners to adopt similar policies.

Export markets for goods with high carbon intensity will shrink, impacting the region far beyond the power sector. The CBAM will to some extent also reduce opportunities to export carbon free flexible power generation. There is a tight timeline concerning the numerous re-forms that must take place before 2030.

Such projects will be loss-making in context of the CBAM. Establishing domestic carbon pricing will assist countries in gathering revenues that should be used to fund the transition to clean power systems.

Specific support is needed for establishing the data and technical backbone of carbon pricing systems. In addition, the West-ern Balkan countries should use a larger share of available EU funds for supporting a just transition and socio-economic convergence with the EU.

Corona-bedingt sinken damit die Emissionen unter die 2020-Klimaziel-Marke von -40 Prozent. Hauptursachen für die geringeren Emissionen sind die Wirtschaftskrise (geringe Energienachfrage, gesunkene Industrieproduktion, Einbruch der Verkehrsnachfrage), höhere CO2-Preise im EU-Emissionshandel sowie ein milder Winter.

Im Vorjahr lag der Erneuerbaren-Anteil bei 42,4 Prozent, Corona-bereinigt läge er 2020 bei etwa 44,6 Prozent. Knapp die Hälfte des höheren Erneuerbare-Energien-Anteils 2020 geht damit auf die Corona-bedingt gesunkene Stromnachfrage zurück. Im Jahr 2021 könnte der Erneuerbare-Energien-Anteil aufgrund einer sich erholenden Stromnachfrage und des aktuell unzureichenden Erneuerbaren-Ausbaus erstmals seit etwa 20 Jahren sinken.

Selbst das moderne Kohlekraftwerk Moorburg beteiligte sich erfolgreich an der ersten Stilllegungs-Ausschreibung und geht 2021 nach nur gut fünf Jahren Betrieb vom Netz. Steigende CO2-Preise und niedrige Gaspreise verdrängen nicht nur Steinkohle-Kraftwerke, sondern zunehmend auch Braunkohle-Kraftwerke vom Markt.

Im Jahr 2021 steht daher eine erhebliche Beschleunigung der Klimapolitik an: Auf EU-Ebene wird die EU-Kommission im Juni 2021 ein Paket an Maßnahmen präsentieren. Auch in Deutschland ist in allen Bereichen – Kohleausstieg, Erneuerbare Energien, Gebäudesanierung, Verkehrswende, Industrie, Landwirtschaft – eine klimapolitische Beschleunigung erforderlich, um die 2030-Ziele zu erreichen.

These applications include steel, ammonia and basic chemicals production in the industrial sector, as well as long-haul aviation and maritime shipping. The power sector needs long-term storage to accommodate variable renewables, and existing district heating systems may require hydrogen to meet residual heat load. Accordingly, renewable hydrogen needs to be channelled into these no-regret applications.

While renewable electricity (the main cost component of renewable hydrogen) is already on track to become cheaper, electrolyser system costs also need to be reduced. Cheaper electrolysers will come through economies of scale and learning-by-doing effects; however, predictable and stable hydrogen demand is prerequisite for electrolyser manufacturers to expand production and improve the technology.

Even at CO₂ prices of €100 to 200/tonne, the EU ETS will not sufficiently incentivise renewable hydrogen production, making additional policy support necessary for a considerable period of time. Among potential policy options, a general usage quota for renewable hydrogen would not be sufficiently targeted to induce adoption in the most important applications.

Several policy instruments should be deployed in concert to achieve this aim – namely, carbon contracts for difference in industry; a quota for aviation; auctions to support combined heat and power plants; measures to encourage markets for decarbonised materials; and hydrogen supply contracts. These instruments will also need to be complemented by regulations that ensure sustainability, appropriate infrastructure investment, system integration, and rapid renewables growth.

Mit einem solchen Ziel würde Deutschland wieder zu einem internationalen Vorreiter beim Klimaschutz und zu einem Leitmarkt und Leitanbieter für Klimaschutztechnologien.

ist als Meilenstein auf dem Weg zur Klimaneutralität 2045 geeignet und schafft die Voraussetzungen für eine beschleunigte Transformation nach 2030.

Beim Ausbau der Erneuerbaren Energien (EE), bei der klimaneutralen Industrie und beim Umstieg auf Wärmepumpen und Elektromobilität wird nach 2030 die Transformation beschleunigt. Zudem werden die Agrarwende und der Einsatz von CO₂-Abscheidung und -Speicherung (CCS) vorgezogen.

This would re-establish Germany as an international leader in climate protection and make it a lead market and technology provider for climate-friendly technologies.

and would set the stage for an accelerated transformation after 2030.

After 2030, the transformation would have to accelerate with regard to renewable energy expansion, industrial decarbonisation, and the adoption of heat pumps and electric vehicles. The transformation of the agricultural sector and the use of carbon capture and storage (CCS) technologies will have to occur sooner.

Following a drastic slump of 6.8 per cent YOY in Q1, the Chinese economy rebounded with 3.2 per cent YOY growth in Q2. China is projected to be the only major economy to see positive growth in 2020.

Because of the coal-intensive economic recovery in Q2 2020, China’s carbon emissions and air pollution have already returned to pre-crisis levels. Structural changes and a green stimulus package are urgently needed to steer China’s economic recovery in a more environmentally sustainable direction.

Because of coal’s dominance in China’s primary energy mix and the uncertainty associated with the country’s statistical reporting on coal in recent years, it is important to focus attention on tracking the changes and trends in China’s economic activity and energy consumption instead of on the absolute numbers provided in our COVID-19 China Energy Impact Tracker reports.

As both current and future Chinese administrations will need to take President Xi’s climate pledge seriously, the announcement is expected to make a real difference in China’s energy transition, especially in the long run.

The Chinese energy policy community’s recent revisions to draft 14th FYPs for energy and climate indicate that the impacts are likely to be not only positive but also substantial.

China’s monthly carbon emissions have exceeded pre-crisis levels. Greener 14th FYPs for energy and climate are urgently needed to steer the Chinese energy economy in a more sustainable direction.

It remains to be seen how China will balance its short-term interest in economic stimulus through carbon-intensive investment with its medium-to-long-term interest in peaking national emissions as soon as possible.

While the rest of the world experienced economic contraction in 2020, China’s economy grew, increasing its share of global carbon emissions by two percentage points. China must urgently downsize its gigantic national coal consumption, which makes up more than half of the global total.

In the post-COVID-19 world, China is likely to face a much more contentious geopolitical environment. Beijing could stabilize its role in the world by becoming a leader in the global transition to clean energy.

Steel, ammonia, refineries and chemical plants are widely distributed across Europe. To reduce and eventually eliminate their process emissions, 300 TWh of low-carbon hydrogen are required. This number does not factor in the production of high-temperature heat, for which direct electri-fication should be considered first.

Given the current asset lifecycle and political commitments, fossil-based hydrogen with carbon capture will remain a viable investment until the 2030s, but strong policies for renewable hydro-gen will shorten the investment window for fossil hydrogen, likely closing it by the end of the 2020s.

Adding potential hydrogen demand from power, aviation and shipping sectors is likely to strengthen the case for an even more expansive network of hydrogen pipelines. However, even under the most optimistic scenarios, any future hydrogen network will be smaller than the cur-rent natural gas network. A no-regrets vision for hydrogen infrastructure needs to reduce the risk of oversizing by focusing on indispensable demand, robust green hydrogen corridors and storage.

Steel, ammonia, refineries and chemical plants are widely distributed across Europe. To reduce and eventually eliminate their process emissions, 300 TWh of low-carbon hydrogen are required. This number does not factor in the production of high-temperature heat, for which direct electrification should be considered first.

Given the current asset lifecycle and political commitments, fossil-based hydrogen with carbon capture will remain a viable investment until the 2030s, but strong policies for renewable hydrogen will shorten the investment window for fossil hydrogen, likely closing it by the end of the 2020s.

Adding potential hydrogen demand from power, aviation and shipping sectors is likely to strengthen the case for an even more expansive network of hydrogen pipelines. However, even under the most optimistic scenarios, any future hydrogen network will be smaller than the current natural gas network. A no-regret vision for hydrogen infrastructure needs to reduce the risk of oversizing by focusing on indispensable demand, robust green hydrogen corridors and storage.

It is uncertain whether the 750 billion NextGen EU recovery budget will be used for clean investment; and only a very limited part of the 1.1-trillion Multiannual Financial Framework is reserved to that end. The proposal fails to meet the stated commitment of the European Commission and Europe’s heads of state to an economic recovery in line with climate neu-trality by 2050.

Priorities are tripling the speed for creating new solar and wind energy, tripling the rate of energy efficiency retrofits of building, greening district heating networks, an EU-wide EV-charging infrastructure, a high-speed EU railway system, a clean hydrogen economy and a climate-neutral industry.

(1) Stipulating a climate share of 40% across all budget lines in both the NextGen EU budget and the multiannual financial framework; (2) establishing dedicated EU facilities to accelerate climate action in critical areas; (3) setting out a clear exclusion-list of climate-negative activi-ties that will not be eligible for EU funding.

We need (1) to ensure that spending activities are consistent with the National Energy and Climate Plans, the Territorial Just Transition Plans, the Recovery and Resilience Plans, and other planning processes; (2) to devise a role for the EU Green Taxonomy in determining na-tional spending priorities; and (3) to conduct a budget review in early 2024, when EU legisla-tors will have just finished updating the EU’s 2030 climate and energy framework.

In einem ersten Schritt sinken die Emissionen bis 2030 um 65 Prozent. Der zweite Schritt nach 2030 ist der vollständige Umstieg auf klimaneutrale Technologien, sodass die Emissionen um 95 Prozent sinken. In einem dritten Schritt werden nicht vermeidbare Restemissionen durch CO2-Abscheidung und -Ablagerung ausgeglichen.

Kernelemente sind eine Energiewirtschaft auf Basis Erneuerbarer Energien, die weitgehende Elektrifizierung, die smarte und effiziente Modernisierung des Gebäudebestands sowie der Aufbau einer Wasserstoffwirtschaft für die Industrie. Dies steigert zugleich die Lebensqualität durch weniger Lärm und Luftschadstoffe.

Dazu gehören bis 2030 der vollständige Kohleausstieg, ein Erneuerbaren-Anteil am Strom von etwa 70 Prozent, 14 Millionen Elektroautos, 6 Millionen Wärmepumpen, eine Erhöhung der Sanierungsrate um mindestens 50 Prozent sowie die Nutzung von gut 60 TWh sauberen Wasserstoffs.

Das Regierungsprogramm nach der Bundestagswahl 2021 ist von zentraler Bedeutung. Kluge Instrumente und Politiken modernisieren Wirtschaft und Gesellschaft Deutschlands in Richtung Resilienz und Zukunftsfähigkeit. Gleichzeitig gestaltet gute Politik den anstehenden Strukturwandel so, dass er inklusiv ist und alle mitnimmt.

The first step consists of a 65% reduction in emissions by 2030. The second step is the complete transition to climate-neutral technologies, for a total emissions reduction of 95%. The third step is the offsetting of residual emissions through carbon capture and storage.

The core elements of the programme are the creation of a renewable-based energy sector, mass electrification, a smart and efficient modernization of buildings and the development of a hydrogen economy for the industrial sector. Besides achieving climate neutrality, the programme will also improve people’s quality of life by reducing noise and air pollution.

This includes the complete phase-out of coal by 2030, a 70% share of renewables in electricity generation, 14 million electric cars on the road, 6 million heat pumps, an increase in the green retrofit rate of at least 50% and the use of some 60 TWh of clean hydrogen.

Government action after the 2021 federal election will be pivotal for future climate policy. Intelligent policy instruments will be needed to modernise Germany’s economy and make it sustainable and resilient. They will also be needed to ensure that the structural changes are as fair and inclusive as possible.

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.

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.

Meanwhile, CO2 emissions from the buildings and transport sectors have risen due to an increase in oil and gas consumption. The decline in CO2 emissions can be attributed to the higher CO2 prices in the EU ETS, a significant increase in renewable generation and lower electricity consumption. The rising share of SUVs in the transport sector is responsible for rising emissions.

Whilst annual growth in renewables has been consistently in the 15 terawatt hours in recent years, the lack of available space and permits for wind capacity puts its continuation in jeopardy. Decisive political action is now required if the 2030 renewable energy targets are to be achieved.

Older, more expensive power plants will then increasingly fall out of the support scheme. In addition, from 2021, part of the revenue from the Fuel Emission Trading Act (BEHG) will be used to reduce the EEG levy. As a result, the price of electricity is likely to fall slightly in the 2020s rather than rise.

Indeed, the climate package adopted by the German government in September is not sufficient to achieve the 2030 climate protection targets. There is a considerable need for improvement, particularly in the areas of transport, buildings and industry.

Demgegenüber sind die CO2-Emissionen bei Gebäuden und im Verkehr durch mehr Erdöl- und Erdgasverbrauch angestiegen. Hauptursache des CO2-Rückgangs sind höhere CO2-Preise im EU-Emissionshandel, ein deutlicher Zuwachs bei den Erneuerbaren und ein gesunkener Stromverbrauch. Im Verkehr sorgte der steigende Anteil an SUVs für einen Anstieg der Emissionen.

Während die Erneuerbaren in den letzten Jahren kontinuierlich um 15 Terawattstunden pro Jahr anwuchsen, wird der Mangel an Windflächen und -genehmigungen den weiteren Aufwuchs spürbar bremsen. Schnelles politisches Handeln ist jetzt gefragt, um die Erneuerbaren-Ziele für 2030 tatsächlich zu erreichen.

Ältere, teure Anlagen fallen dann zunehmend aus der Förderung. Zudem soll ab 2021 ein Teil der Einnahmen aus dem Brennstoffemissionshandelsgesetz zur Senkung der EEG-Umlage verwendet werden. Der Strompreis dürfte in der Folge in den 2020ern nicht mehr steigen, sondern leicht fallen.

So reicht das im September von der Bundesregierung beschlossene Klimapaket nicht aus, um die 2030er-Klimaschutzziele zu erreichen. Insbesondere bei Verkehr, Gebäude und Industrie besteht erheblicher Nachbesserungsbedarf.

Denn während im Trend der letzten Jahre die Treibhausgasemissionen nur um 10 Mio. t CO2e pro Jahr gesunken sind, ist von 2021 bis 2030 eine jährliche Minderung um 25 Mio. t CO2e gefordert. Verfehlt Deutschland seine jährlichen Klimaziele, kommen auf den Bundeshaushalt nach Europarecht Kosten von 30 bis 60 Milliarden Euro zu, um anderen EU-Staaten ihre CO2-Minderungen abzukaufen.

Dies führt zu einer Kombination aus CO2-Bepreisung, Markteinführungsprogrammen, Anreizsystemen, Ordnungsrecht und Initiativen zur Änderung europäischer Regelwerke. Die Bundesregierung muss daher 2019 ein umfangreiches Gesetzespaket auf den Weg bringen, soll das 2030-Klimaziel erreicht werden.

In Energiewirtschaft und Industrie geht es neben der rechtlichen Umsetzung des Kohleausstiegs darum, Investitionssicherheit für Klimatechnologien zu schaffen, u. a. durch eine Novelle des Erneuerbare-Energien-Gesetzes, die Förderung grüner Fernwärme, eine Quote für grünen Wasserstoff und Markteinführungsprogramme für klimaneutrale Technologien in der Industrie.

Hierzu gehören ein Bonus-Malus-System beim Autokauf, eine Reform der Lkw-Maut, die steuerliche Förderung der Gebäudesanierung und effektive Energiestandards für Neubauten und Sanierungen. Ergänzt wird dies durch einen CO2-Aufschlag auf die Energiesteuern mit kompletter Rückverteilung der Einnahmen, u. a. über eine 100-Euro-pro-Kopf-Klimaprämie und eine Senkung der Stromsteuer.

Möglich wurde dies durch ein starkes Solarjahr bei Zubau und Erzeugung. Auch der Windstrom legte zu, wenn auch deutlich weniger als in den Vorjahren, während die Wasserkraft aufgrund der Dürre zurückging. Für die kommenden Jahre ist ein deutlich höherer EE-Zubau notwendig, verbunden mit einer proaktiven Sektorkopplung, um die 2030-Energiewende-Ziele in allen Sektoren umzusetzen.

Denn die Ursache für den Rückgang war weniger Klimaschutz, als vielmehr ein stark gesunkener Energieverbrauch auf das Niveau von 1970. Die wesentlichen Faktoren hierfür waren die milde Witterung im Winter und der damit verbundene niedrigere Heizbedarf, ein leicht gesunkenes Produktionsniveau bei Teilen der energieintensiven Industrien sowie zeitweilig stark gestiegene Ölpreise.

Damit geht im Jahr 2018 nicht nur die Ära der Steinkohleförderung zu Ende, auch ihr Nutzungsende in der Stromversorgung ist absehbar. Anders bei der Braunkohle, die fast unverändert 22,5 Prozent der deutschen Stromerzeugung deckte. Die Kohlekommission, die im Februar 2019 ihre Empfehlungen abgeben soll, wird daher vor allem für die Braunkohle klare Regelungen vorschlagen müssen.

So ist der Rückgang der Steinkohle im Stromsektor vor allem auf die höheren CO2-Preise zurückzuführen. Auch haben die durch die gestiegenen CO2-Preise erhöhten Börsenstrompreise erste Kaufverträge für Strom aus Windanlagen außerhalb des EEG-Regimes möglich gemacht. Dies zeigt, dass eine stärkere Bepreisung von CO2 deutliche Klimaschutzeffekte am Markt auslösen kann.

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.

The aim of the fund would be to strengthen the region’s economic attractiveness and its desirability as a place to live. It should help to: preserve the region’s industrial character, strengthen innovation among its businesses, support its academic institutions, equip it with an up-to-date transport network and digital infrastructure, and foster a lively civil society that retains local residents while also attracting new ones.

In each of these areas, it should be possible to use the available funds in a flexible manner (i.e. to shift funding between areas), and funds that are not withdrawn should not expire (i.e. funding should be transferable to subsequent years).

The federal government should only play a monitoring and coordinating role, as part of a steering committee; decisions on funding priorities should be made by stakeholders from the region.

Raising the attractiveness of a region means more than just promoting its economy, academic institutions and infrastructure. Ultimately, the vibrancy of a place depends on art, culture, lived traditions and the quality of civil society. These factors require ongoing support, which can be guaranteed in the short term through the Structural Change Fund and in the long term through developing a foundation with a strong endowment.

Reducing emissions from the current level of 130 million tons of CO2 to between 70 and 72 million tons in the next 11 years will require ramping up all available technologies across the board. These include insulation, heat pumps, heat networks, decentralized renewable energy and power-to-gas. Cherry-picking the various building technologies is no longer an option because of past shortcomings.

Ensuring adequate competition between various energy supply options such as renewable energy, heat pumps, synthetic fuels and decarbonized heat networks requires reducing final energy consumption by at least a third before 2050. The more efficient a building is, the more realistic any necessary expansion on the generation side will be.

Synthetic fuels are a significant component of energy supply in all 2050 climate protection scenarios. But their contribution by 2030 is only limited, and even between 2030 and 2050 they are considerably more expensive than most energy efficiency measures in the buildings sector. In addition, the bulk of generation from power-to-gas may be allocated to other markets (industrial processes, shipping, air travel and transport by truck).

To this end, a package of policy measures is needed, including changes to relevant laws, regulations and energy tax laws, as well as an overhaul of funding programs. The heating sector goals for 2030 and 2050 can only be met if the installation rate of all building-related climate protection technologies is quadrupled.

Synthetic fuel production technologies can be used to manufacture chemical precursors, produce high-temperature process heat, as well as to power air, sea and possibly road transport. Because synthetic fuels are more expensive than the direct use of electricity, their eventual importance in other sectors is still uncertain.

Instead, renewable power plants must be built explicity for the purpose of producing synthetic fuels, either in Germany (i.e. as offshore wind) or in North Africa and the Middle East (i.e. as onshore wind and/or PV). The development of synthetic fuel plants in oil- and gas-exporting countries would provide those nations with a post-fossil business model.

The aimed-for cost reductions require considerable, early and continuous investments in electrolysers and CO2 absorbers. Without political intervention or high CO2 pricing, however, this is unlikely, because the cost of producing synthetic fuels will remain greater than the cost of extracting conventional fossil fuels.

Electricity-based fuels are not an alternative to fossil fuels but they can supplement technologies with lower conversion losses, such as electric vehicles and heat pumps. Application-specific adoption targets and binding sustainability regulations can help to ensure that PtG and PtL fuels benefit the climate while also providing a reliable foundation for long-term planning.

A coal-based system would only be significantly less expensive if extremely low CO₂ prices are expected in 2050 (20 euros/t). Similarly, a natural gas-based system would only be significantly less expensive if gas prices are low and CO₂ prices are not high (i.e. below 100 euros/t).

Variable costs (largely for fuel and CO₂) account for 30 to 67 percent of the total costs of the fossil-based systems. By contrast, variable costs represent just 5 percent of costs in the renewables-based systems.

A renewables based energy transition can thus be considered efficient climate policy, as CO₂ damage costs are estimated a lot higher (80 euros/t over the short-term, and at 145 to 260 euros/t over the long term).

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.

In this scenario, the importance of natural gas remains roughly the same as today, while oil heating is almost entirely replaced by heat pumps. District heating is another key factor. By 2030, district heating will primarily draw on heat from CHP plants, but it will increasingly rely on solar thermal energy, deep geothermal energy, industrial waste heat, and large-scale heat pumps as well.

Energy efficiency is a pillar of decarbonisation because it makes climate protection affordable. Improving energy use efficiency in buildings requires a green retrofit rate of 2 per cent and a high retrofit depth. But current trends in building modernisation fall far short of these targets.

To close this gap, heat pumps must be installed early on not only in new buildings but also in existing buildings, for example as bivalent systems with fossil fuel-fired boilers for peak demand. If heat pumps can be flexibly managed and existing storage heaters replaced with efficient heating units by 2030, the 5 to 6 million heat pumps will affect only a slight rise on peak demand that thermal power plants must cover.

To reach the 2030 climate protection target, additional electricity consumption in the heating and traffic sector must be covered by CO2-free energy sources. But the new renewable energy capacities stipulated in EEG 2017 will not suffice to do so.

It enjoys broad public support and is driven by four main political objectives: combatting climate change, avoiding nuclear risks, improving energy security, and guaranteeing competitiveness and growth.

Wind and solar energy are now cost-competitive with conventional energy sources for new investments. These technologies, however, impact power systems, making increased system flexibility crucial. Fossil power plants currently deliver the needed flexibility; increasingly other options (demand side management, storage,… ) will become more important.

Given the transformative nature of the Energiewende, investment, growth, and employment are shifting towards new low-carbon sectors. Renewable energy and energy efficiency are providing several hundred thousand jobs, while jobs in the nuclear and coal sectors are declining. A broad consensus on the phasing out of coal is needed to accompany this restructuring process.

In 2014, for the third year running, worldwide investment in new renewable capacity exceeded investment in fossil-fuel power. Many other countries in Europe and beyond have set ambitious renewable energy targets. The challenges faced by Germany are therefore a preview of what is likely to occur in several other countries in the medium to long-term.

The main reason is that starting in 2023, EEG funding for renewable plants from the early years with high feed-in tariffs starts to expire, and new renewable energy plants produce electricity at a considerably lower cost.

The sum of the EEG surcharge and wholesale electricity price, after being adjusted for inflation, will climb from around 10 cent per kWh today to 11 to 12 cents in 2023 and then sink to 8 to 10 cents by 2035.

According to the current law, the share of renewables in electricity use is to rise from today’s 28 per cent to 55-60 per cent in 2035. Yet, the electricity cost in 2035 will be on the same level as today.

Since renewable energy plants have now become affordable alternatives for energy production, these drivers – not the costs and volumes of renewables – are essential for the EEG surcharge level.

Principle 1: Convening a ‘Round Table for a National Consensus on Coal’

Principle 2: Incremental, legally binding phase-out of coal power by 2040

Principle 3: No new construction of coal-fired power plants

Principle 4: Determine a cost-efficient decommissioning plan for existing coal power plants based on remaining plant lifespans, including flexibility options in lignite mining regions

Principle 5: No additional national climate policy regulations for coal-fired power plants beyond the phase-out plan

Principle 6: No additional lignite mines and no further relocation processes of affected communities

Principle 7: The follow-up costs of lignite mining should be financed with a special levy on lignite

Principle 8: Creation of ‘Structural Change Fund’ to ensure a sound financial basis for structural change in affected regions

Principle 9: Ensuring security of supply over the entire transformation period

Principle 10: Strengthening EU Emissions Trading and the prompt retirement of CO? certificates set free by the coal phase-out

Principle 11: Ensuring the economic competitiveness of energy-intensive companies and the Germany economy as a whole during the transformation process

The calculation of these costs varies tremendously depending on the specific power system and methodologies applied. Moreover, opinions diverge concerning how to attribute certain costs and benefits, not only to wind and solar energy but to the system as a whole.

Certain costs for building electricity grids and balancing can be clearly classified without much discussion as costs that arise from the addition of new renewable energy. In the literature, these costs are often estimated at +5 to +13 EUR/MWh, even with high shares of renewables.

When new solar and wind plants are added to a power system, they reduce the utilization of the existing power plants, and thus their revenues. Thus, in most cases, the cost for “backup” power increases. Calculations of these effects range between -6 and +13 EUR/MWh in the case of Germany at a penetration of 50 percent wind and PV, depending especially on the CO? cost.

A total system cost approach can assess the cost of different wind and solar scenarios while avoiding the controversial attribution of system effects to specific technologies.

. In 2025, the LCOE of utility-scale PV should reach about 6.3 ¥/kWh (5.2 €cts/kWh). Onshore wind could reach those levels in 2030. Those costs will be significantly lower than those of new fossil-fuelled power plants, comparable to lifetime extensions of nuclear and far below new nuclear and CCS projects.

Japan can reach a share of at least 45% renewables in 2030 (corresponding to a share of 35% wind and solar power) with integration costs below 1.5 ¥/kWh. Integrating 66% renewables (corresponding to 50% wind and solar power) would come only at a slightly higher cost of 2 ¥/kWh.

These costs are estimated at below 1 ¥/kWh for Japan. Various measures exist to minimize those costs, in particular through optimal grid planning, optimised grid operation, and well-functioning and non-discriminatory intraday and balancing markets.

The calculation of those costs can vary tremendously depending on the assumptions. A total system cost approach would circumvent some of the uncertainties, in particular the controver-sial attribution of system effects to specific technologies. Rather than to speak about integra-tion costs, we should speak about interaction costs. If the system adapts to renewables (reduc-ing baseload power plants), the cost of variability for integrating 50% PV and wind energy in Japan is estimated at about 1.25 ¥/kWh. If not, the costs of variability could be much higher. This finding calls for a refinement of energy markets design, so as to incentivize rather than to hamper flexibility.

In particular, additional generation from renewables in the Nordics – reflected in the Nordic electricity balance - will increase the value of transmission capacity. There is a lot of potential for trade, due to hourly differences in wholesale electricity prices throughout the year.

This is caused by reduced curtailment of renewables, improved integration of additional renewable production sites and increased competitiveness of biomass-fuelled power plants.

In general, additional integration will lead to slightly higher wholesale electricity prices in the Nordics and to slightly lower prices in Germany. But this will be counteracted by the decreasing price effect that higher wind shares in the Nordics have on the wholesale power market.

This strongly impacts the incentives of market players such as electricity producers or consumers (e.g., energy-intensive industries) for or against increased integration. Distributiona leffects need to be taken into account for creating public acceptance for new lines and for the cross-border allocation of network investments.

In particular, additional generation from renewables in the Nordics – reflected in the Nordic electricity balance - will increase the value of transmission capacity. There is a lot of potential for trade, due to hourly differences in wholesale electricity prices throughout the year.

This is caused by reduced curtailment of renewables, improved integration of additional renewable production sites and increased competitiveness of biomass-fuelled power plants.22

In general, additional integration will lead to slightly higher wholesale electricity prices in the Nordics and to slightly lower prices in Germany. But this will be counteracted by the decreasing price effect that higher wind shares in the Nordics have on the wholesale power market.3

This strongly impacts the incentives of market players such as electricity producers or consumers (e.g., energy-intensive industries) for or against increased integration. Distributiona leffects need to be taken into account for creating public acceptance for new lines and for the cross-border allocation of network investments.

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 reason for this paradox is not to be found in thedecision to phase out nuclear power – the decrease of nuclear generation is fully offset by an increasedgeneration from renewables. Rather, the paradox is caused by a fuel switch from gas to coal.

Since 2010, coal and CO2 prices have decreased, whilegas prices have increased. Accordingly, Germany’s coal-fired power plants (both new and old) are able to produceat lower costs than gas-fired power plants in Germany and in the neighbouring electricity markets thatare coupled with the German market. This has yielded record export levels and rising emissions in Germany.

Sharp decreases in generation fromlignite and hard coal of 62 and 80 percent, respectively, are expected in the next 15 years while theshare of gas in electricity generation will have to increase from 11 to 22 percent. This goes in line with thegovernments’ renewables and climate targets for 2030.

Such a strategy – call it a coal consensus –would bring power producers, labour unions, the government and environmental groups together in findingways to manage the transformation.

In the next 10 to 20 years the flexibility required in the power system can be provided for by other, more cost-effective technologies such as flexible power plants, demand side management. New storage is required only at very high shares of renewable energies.

New markets for battery storage and power to gas technologies are expected to emerge, especially in the transport and chemical sector. Storage developed in these sectors can enable further flexibility for the electricity system as an additional service. Research and development as well as market incentive programs should maximize the system-supporting contribution of new storage technologies.

Storage can already today deliver several ancillary services at competitive costs. Flexibility markets – such as the ancillary services or future capacity markets – should therefore be designed such that they are technology-neutral.

In specific cases, storage that is used to support a grid can help to avoid grid expansion in the low-voltage distribution grid. The regulatory framework should enable such cost-efficient decisions.

Each saved kilowatt-hour of electricity reduces fuel and CO2 emissions, as well as investment costs forfossil and renewable power plants and power grid expansion. If electricity consumption can be lowered by10 to 35 percent by 2035 compared to the Reference scenario outlined in the study, the costs for electricitygeneration will reduced by 10 to 20 billion euros2012.

One saved kilowatt-hour of electricity would lead to reduced electrical system costs of between 11 to 15euro cents2012 by 2035, depending on the underlying assumptions. Many efficiency measures wouldgenerate lower costs than these savings, and would therefore be beneficial from an overall economicperspective.

A significant increase in energy efficiency can significantly reduce the long-term need to expand thetransmission grid: between 1,750 and 5,000 km in additional transmission lines will be needed by 2050,down from 8,500 km under the “business as usual” scenario.

Reducing power consumption by 15 percent compared to the Reference scenario would lower CO2 emissionsby 40 million tonnes and would reduce spending on coal and natural gas imports by 2 billion euros2012 in2020.

Regional distribution of this renewable energy has little impact on the total cost of power supply.

To promote technology development and reduce the cost of electricity for consumers, expansion should be continued, but on a lower level than current plans foresee.

Solely in terms of cost, a few years of delays for the additional transmission lines foreseen in the German Grid Development Planning act would not be critical. Further expansion of renewables does not have to wait for these new transmission lines.

Only if cost of such systems drop by 80 % in the next 20 years would a renewable expansion path focusing on photovoltaics + storage be an economically viable option.