Our most important findings

Electricity Production

  1. 1

    The EU will establish a Carbon Border Adjustment Mechanism (CBAM) that will apply to power imported from neighbouring countries, including the Western Balkan region.

    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.

  2. 2

    The Western Balkan countries have the EU as their main trading partner. They should prepare for its entry into force by either adopting internal carbon pricing or establishing clear pathways to enter the EU ETS.

    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.

  3. 3

    Plans for new lignite power plants in the Western Balkans should be halted.

    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.

  4. 4

    The EU should commit to use CBAM revenues for technical assistance and transfer of knowledge to countries developing carbon pricing.

    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.

  1. 1

    Die Treibhausgasemissionen sinken 2020 um gut 80 Mio. t CO2 und liegen damit etwa 42,3 Prozent unter dem Niveau von 1990. Etwa zwei Drittel des Rückgangs ist auf die Corona-Wirtschaftskrise zurückzuführen, Corona-bereinigt lägen die Emissionen bei -37,8 Prozent.

    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.

  2. 2

    Der Anteil Erneuerbarer Energien am Stromverbrauch erreicht 2020 mit 46,2 Prozent einen Höchstwert, zugleich hält die Zubaukrise bei der Windkraft weiter an.

    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.

  3. 3

    Die Kohle ist weiter im Sinkflug: Braun- und Steinkohle tragen zusammen nur noch 24 Prozent zur Stromerzeugung bei, weniger als die Windkraft (Offshore und Onshore). In den vergangenen fünf Jahren hat sich die Kohleverstromung halbiert.

    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.

  4. 4

    Der Europäische Rat hat im Dezember 2020 das EU-Klimaziel für 2030 auf mindestens -55 Prozent erhöht. Das bedeutet, dass auch Deutschland sein 2030-Ziel erhöhen muss: auf mindestens -65 Prozent.

    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.

  1. 1

    The EU’s 2030 climate target of –55 percent requires a complete coal phase-out in the power system by 2030.

    A 2030 coal phase-out provides a CO₂ emission reduction potential of 1 billion tons beyond the 40 percent emissions reduction scenario at little additional cost to consumers (wholesale prices rise by 0.5 cent/kWh).

  2. 2

    Coal should be replaced by renewables.

    The required emission reduction of the power sector can only be achieved if coal is overwhelmingly replaced by solar PV and wind energy. A phase-out of the remaining 38 GW coal capacities in the six countries that do not have a 2030 phase-out date yet (Bulgaria, the Czech Republic, Germany, Poland, Romania and Slovenia) must be met with 100 GW of PV and wind.

  3. 3

    Additional gas capacities will be needed, along with an overall decrease in the rate of utilization.

    The coal phase-out may require additional deployment of 15 GW of gas plant capacity to safeguard security of supply – while gas-fired power generation needs to fall 15 percent by 2030 in the EU. To avoid stranded assets, all new fossil gas investments should be hydrogen ready.

  4. 4

    To achieve the EU wide coal phase out at least cost, a policy mix is required.

    The EU ETS should be tightened as proposed by the European Commission. Several Member States should quickly develop or accelerate their plans for national coal phase-out, potentially complemented by a national carbon floor price. Member States should rapidly scale renewables.

  1. 1

    The strong outlook for carbon pricing in the Western Balkans means that new lignite plants will be loss making.

    2  GW of new lignite capacity is currently planned in the region. If built, these plants will generate a cumulative loss by 2040. This is because of low efficiency of lignite mining, costs to comply with air pollution regulation and limited export opportunities after establishment of the EU  Carbon Border Adjustment Mechanism (CBAM). A phase-in of carbon pricing in Energy Community countries would further increase losses.

  2. 2

    From an economic perspective, existing lignite units in the region should be closed by 2040.

    A 2040 lignite exit increases system costs by 3–4 €/MWh in an unlikely scenario without carbon pricing. With the EU CBAM regime or any other form of domestic carbon pricing, closing lignite plants by 2040 lowers system costs.

  3. 3

    The planned and gradual phase-out of lignite will ensure security of supply.

    Security of supply is not an issue if the gradual phase-out of lignite is accompanied by a rapid scaling of renewables, enhanced interconnections, regional power market integration, strengthening of existing hydro-storage and targeted investments in flexible gas plants. Expanding renewables also reduces import dependency of the power and energy sectors.

  4. 4

    A renewables-based power system is a ‘no regret’ strategy for the Western Balkans.

    Replacing lignite generation by renewables lowers wholesale prices, hedges against carbon prices and avoids that fossil gas infrastructure will become stranded. Renewables deployment can largely be financed from market revenues, especially in case of carbon pricing. Renewables also come with many co-benefits such as improved air quality and new job opportunities. ‘Just transition’ policies would ensure that no one is left behind.

  1. 1

    In 2019 greenhouse gas emissions in Germany fell by over 50 million tonnes of CO2 thanks to a sharp drop in lignite and hard coal generation which are now around 35% lower than in 1990.

    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.

  2. 2

    Renewable energy broke a new record, reaching almost 43 percent of electricity consumption. Unfortunately, the collapse in wind capacity expansions to just one gigawatt per year means the energy transition is entering the 2020s with a heavy burden.

    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.

  3. 3

    When it comes to the costs of renewable energy, the peak is in sight: the EEG levy will rise again in 2020 to 6.77 cents per kilowatt hour, but is expected to fall in 2022 at the latest, thanks to the lower costs of renewable energy.

    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.

  4. 4

    Surveys have shown that climate protection and the energy transition are the number one concern amongst German society in 2019, far ahead of immigration and pensions. This fact is not reflected in the country’s climate politics.

    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.

  1. 1

    Die Treibhausgasemissionen in Deutschland sinken 2019 aufgrund eines starken Rückgangs bei Braun- und Steinkohle um über 50 Millionen Tonnen CO2 und liegen damit etwa 35 Prozent unter dem Niveau von 1990.

    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.

  2. 2

    Die Erneuerbaren Energien liefern 2019 mit knapp 43 Prozent des Stromverbrauchs einen neuen Rekord - aber aufgrund des Zusammenbruchs beim Windausbau auf nur noch ein Gigawatt pro Jahr startet die Energiewende in die 2020er mit einer schweren Hypothek.

    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.

  3. 3

    Bei den Kosten der Erneuerbaren Energien ist der Scheitelpunkt in Sicht: Die EEG-Umlage steigt zwar 2020 nochmal auf 6,77 Cent je Kilowattstunde, aber spätestens ab 2022 zeigen sich die gesunkenen Kosten der Erneuerbaren Energien auch in einer sinkenden EEG-Umlage.

    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.

  4. 4

    Für die Bevölkerung war 2019 "Klimaschutz/Energiewende" das Top-Thema bei der Frage nach den wichtigsten Problemen - deutlich vor "Migration/Integration" (Platz 2) und "Renten" (Platz 3). Die Klima- und Energiepolitik hat dies jedoch nicht abgebildet.

    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.

  1. 1

    Coal generation collapsed by 24% in the EU in 2019.

    Hard coal generation dropped by 32%, while lignite decreased by 16%. This development is driven by CO₂ price increases and deployment of renewables. Gas replaced around half of the coal, solar and wind the other half. The decline of coal will continue: Greece and Hungary both made commitments in 2019 to phase out coal, bringing the total of member states phasing out coal to 15. Only Poland, Romania, Bulgaria and Slovenia are yet to start.

  2. 2

    The fall in coal means CO₂ emissions in Europe’s power sector fell by a record 120 Mt, or 12% in 2019.

    This is likely to be the largest ever fall. EU Emissions Trading Scheme (EU ETS) stationary emissions, including heavy industry, fell by 7.6% in 2019, implying that industrial emissions are likely to have decreased by only 1%. Nevertheless, overall emissions covered by the EU ETS are falling much faster than the cap; showing the central role of a further strengthening of the EU ETS to accelerate climate action in Europe.

  3. 3

    Renewables rose to a new record supplying 35% of EU electricity.

    For the first time, wind and solar combined provided more electricity than coal, contributing 18% of EU electricity in 2019. This is more than a doubling of market share since 2013. The increase in wind and solar generation was strongest in western Europe, while Poland and Greece have started to engage. The rest of eastern Europe is significantly lagging behind. The economic opportunities of low-cost renewables became increasingly visible. 2019 saw record low auction prices for offshore wind (UK) and solar (Portugal) - below wholesale prices – and the largest wholesale price decreases in countries where wind and solar expanded most.

  4. 4

    Europe’s energy transition is taking off.

    The European Green Deal has put the fight against the climate crisis at the very core of all EU policy work over the next five years: EU heads of state have endorsed Europe to become the first greenhouse gas neutral continent by 2050, and the EU commission is putting forward proposals to raise Europe’s 2030 greenhouse gas reduction target to -50% or -55% below 1990 levels. This implies power sector emissions will keep falling, even if electricity demand increases as transport, heating industry continue to electrify.

  1. 1

    Net zero emissions can be achieved in Japan at reasonable costs based on renewables deployment and electrification.

    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.

  2. 2

    A three-step roadmap is needed to achieve climate neutrality by 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.

  3. 3

    Hydrogen will be used sparingly, even if it is imported, as direct electrification is more efficient and less expensive.

    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.

  4. 4

    Nuclear power is not necessary to achieve the long-term decarbonization target at lower cost.

    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.

  5. 5

    Japan has to kick-start enhanced climate action as soon as possible and increase its interim sectoral targets to reach 45% lower GHG emissions and at least 40% renewables in power generation by 2030.

    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.

  1. 1

    Net zero emissions can be achieved in Japan at reasonable costs based on renewables deployment and electrification.

    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.

  2. 2

    A three-step roadmap is needed to achieve climate neutrality by 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.

  3. 3

    Hydrogen will be used sparingly, even if it is imported, as direct electrification is more efficient and less expensive.

    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.

  4. 4

    Nuclear power is not necessary to achieve the long-term decarbonization target at lower cost.

    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.

  5. 5

    Japan has to kick-start enhanced climate action as soon as possible and increase its interim sectoral targets to reach 45% lower GHG emissions and at least 40% renewables in power generation by 2030.

    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.

  1. 1

    CO₂ emissions in the power sector fell by 5% in 2018.

    Half of this was structural, from new wind, solar and biomass displacing hard coal. The other half was weather-related, as increased hydro generation reversed the temporary rise in gas in 2017. Overall EU ETS emissions, we estimate, fell by 3%, from 1754 Mt in 2017 to 1700 Mt in 2018.

  2. 2

    It’s a tale of two types of coal: Europe’s transition from hard coal to renewables is accelerating ...

    Hard coal generation fell by 9% in 2018, and is now 40% lower than in 2012. In 2018, Germany and Spain announced that coal phase-out plans were imminent. That would now put three quarters of Europe’s 2018 hard coal generation under national coal phase-outs. The remaining quarter is almost all in Poland.

  3. 3

    ... however, the transition from lignite – the dirtier, brown coal – to renewables proving much harder.

    Lignite generation fell by only 3% in 2018. Half of Europe’s lignite generation in 2018 was in Germany; the Coal Commission announcement for a 2038 phase-out includes lignite. The other half is in countries where this is not yet the case: Poland, Czech Republic, Bulgaria, Greece, Romania and Slovenia.

  4. 4

    Wind is strong, but get ready for solar!

    Renewables rose to 32.3% of EU electricity production in 2018. While this year’s rise was mainly due to wind growth picking up and hydro returning back to normal, solar will be the next big thing: solar additions increased by more than 60% to almost 10 GW in 2018 and could triple to 30 GW by 2022. Module prices fell by 29% in 2018. Solar outperformed during the 2018 summer heatwave, when coal, nuclear, wind and hydro all stumbled. Bold national plans for solar in 2030 were drafted in Italy, France and Spain in 2018. The EU’s 2030 RES target, agreed in 2018, will result in even more.

  5. 5

    For the first time, the fuel and carbon costs alone for coal and gas plants were on a par with the full cost of wind and solar.

    Coal and gas generation costs rose in 2018: coal price rose 15%, gas rose 30%, and the CO₂ price rose 170%. Consequently, electricity prices rose to 45–60 €/MWh in Europe. This is the level at which the latest wind and solar auctions cleared in Germany.

  1. 1

    Even when wind and solar conditions are better, investing into renewables in South East Europe is more expensive than in Western and Northern Europe.

    The reason: countries in South East Europe face higher financing costs due to perceived higher investor risks. More costly than necessary renewables investments seriously hamper power system modernisation in SEE.

  2. 2

    South East Europe could secure low cost renewables by introducing contractual, regulatory and market policies that greatly reduce investor risk and thereby lower financing costs.

    “De-risking measures” available to governments will reduce renewable energy project costs to levels comparable or lower than those of fossil fuel investments. Low cost renewable energy projects are thus a real alternative for replacing old and polluting lignite power plants.

  3. 3

    De-risking measures will lower the cost of renewable energy projects by 20 per cent. The cost for onshore wind would fall to 46 EUR/MWh in Greece and 54 EUR/MWh in Serbia.

    De-risking measures with the highest impact include: (1) the proposed EU budget guarantee mechanism; (2) reliable, long-term renewables remuneration regimes and long-term renewables targets; (3) well-functioning, regionally integrated balancing and intraday markets; and (4) corporate power purchase agreements.

  4. 4

    The proposed EU budget guarantee mechanism is a no-regret policy instrument and should be equipped with sufficient resources under the new EU budget 2021-2027.

    The budget guarantee alone accounts for 40 per cent of the decline in financing costs attributable to the de-risking measures analysed in this study. Overall, de-risking measures enable the expansion of renewables in South East Europe at lower costs than coal, natural gas or nuclear, with attendant benefits for the climate and for human health.

  1. 1

    Offshore wind energy, which has an installed capacity potential of up to 1,000 GW, is a key pillar of the European energy transition.

    The net-zero decarbonization scenarios contained in the European Commission’s Long-Term Strategy assume some 400 to 450 GW of offshore wind capacity by 2050. Additional demand of up to 500 GW may be created by dedicating offshore farms to electrolysis for renewable hydrogen production.

  2. 2

    Scenarios projecting near climate neutrality by 2050 assume an installed capacity of 50 to 70 GW of offshore wind in Germany, generating some 200 to 280 TWh of electricity per year.

    Given the 8 GW of installed capacity today and current plans for 20 GW by 2030, the pace of spatial planning for offshore wind deployment needs to pick up significantly. The slowing of onshore wind development could further enhance the importance of offshore wind in achieving net zero.

  3. 3

    Offshore wind power needs sufficient space, as the full load operating time may otherwise shrink from currently around 4,000 hours per year to between 3,000 and 3,300 hours.

    The more turbines are installed in a region, the less efficient offshore wind production becomes due to a lack of wind recovery. If Germany were to install 50 to 70 GW solely in the German Bight, the number of full-load hours achieved by offshore wind farms would decrease considerably.

  4. 4

    Countries on the North and Baltic Seas should cooperate with a view to maximizing the wind yield and full-load hours of their offshore wind farms.

    In order to maximize the efficiency and potential of offshore wind, the planning and development of wind farms – as well as broader maritime spatial planning – should be intelligently coordinated across national borders. This finding is relevant to both the North and Baltic Seas. In addition, floating offshore wind farms could enable the creative integration of deep waters into wind farm planning.

  1. 1

    Wind, Sonne und Co. erzeugen 2018 erstmals so viel Strom wie die Kohle: Die Erneuerbaren liefern 38,2 Prozent des Stromverbrauchs und damit gleich viel wie Stein- und Braunkohle zusammen.

    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.

  2. 2

    Die CO2-Emissionen Deutschlands sinken 2018 deutlich um über 50 Millionen Tonnen, könnten 2019 aber schnell wieder steigen.

    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.

  3. 3

    Die Steinkohle verabschiedet sich aus dem Energiemix Deutschlands: Sie fällt auf ihr niedrigstes Niveau seit 1949 und liefert nur noch zehn Prozent des Primärenergieverbrauchs.

    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.

  4. 4

    Der CO2-Preis hat 2018 mit knapp 15 Euro pro Tonne im Jahresmittel das höchste Niveau der letzten zehn Jahre erreicht, die 2018 beschlossene Reform des EU-Emissionshandels zeigt damit erste Wirkungen.

    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.

  1. 1

    The recommendations of the Coal Commission are an important milestone in the German energy policy debate: Germany has now resolved to phase out both nuclear energy and coal, and is fully committed to developing renewable energy.

    For decades, Germany's economy was reliant on energy from lignite and hard coal; in the future, renewables will serve as a basis for economic prosperity.

  2. 2

    The Commission's proposals, if fully implemented, will lead to CO₂ savings of some one billion tonnes by 2038.

    In the absence of implementation, CO₂ emissions from coal-fired power plants will only decline at a slow rate. However, the Coal Compromise is not sufficient for Germany to meet its 2030 carbon emissions target. Considerable additional measures are required, especially in the industrial, building, and transport sectors.

  3. 3

    The Coal Compromise will ensure a just transition for coal regions and employees.

    The compromise guarantees that no worker will be left high and dry and that coal mining regions will have sufficient time and resources to adapt economically. To this end, the compromise foresees 2 billion euros in federal spending per year - which in parts can also be understood as compensation for structural policy failures since German reunification especially in Eastern Germany.

  4. 4

    While the Coal Compromise envisions full phase-out occurring in 2038, earlier achievement of this goal is likely.

    Periodic reviews in 2023, 2026, 2029, and 2032 will offer policymakers an opportunity to react to a worsening climate crisis with additional measures. Furthermore, the Commission’s compromise creates a foundation for a socially equitable acceleration of the phase-out.

From study : The German Coal Commission
  1. 1

    New renewables generation sharply increased in 2017, with wind, solar and biomass overtaking coal for the first time.

    Since Europe‘s hydro potential is largely tapped, the increase in renewables comes from wind, solar and biomass generation. They rose by 12% in 2017 to 679 Terawatt hours, putting wind, solar and biomass above coal generation for the first time. This is incredible progress, considering just five years ago, coal generation was more than twice that of wind, solar and biomass.

  2. 2

    But renewables growth has become even more uneven.

    Germany and the UK alone contributed to 56% of the growth in renewables in the past three years. There is also a bias in favor of wind: a massive 19% increase in wind generation took place in 2017, due to good wind conditions and huge investment into wind plants. This is good news since the biomass boom is now over, but bad news in that solar was responsible for just 14% of the renewables growth in 2014 to 2017.

  3. 3

    Electricity consumption rose by 0.7% in 2017, marking a third consecutive year of increases.

    With Europe‘s economy being on a growth path again, power demand is rising as well. This suggests Europe‘s efficiency efforts are not sufficient and hence the EU‘s efficiency policy needs further strengthening.

  4. 4

    CO2 emissions in the power sector were unchanged in 2017, and rose economy-wide.

    Low hydro and nuclear generation coupled with increasing demand led to increasing fossil generation. So despite the large rise in wind generation, we estimate power sector CO2 emissions remained unchanged at 1019 million tonnes. However, overall stationary emissions in the EU emissions trading sectors rose slightly from 1750 to 1755 million tonnes because of stronger industrial production especially in rising steel production. Together with additional increases in non-ETS gas and oil demand, we estimate overall EU greenhouse gas emissions rose by around 1% in 2017.

  5. 5

    Western Europe is phasing out coal, but Eastern Europe is sticking to it.

    Three more Member States announced coal phase-outs in 2017 - Netherlands, Italy and Portugal. They join France and the UK in committing to phase-out coal, while Eastern European countries are sticking to coal. The debate in Germany, Europe’s largest coal and lignite consumer, is ongoing and will only be decided in 2019.

  1. 1

    Renewables will provide 50% of SEE power demand in 2030. The European energy transition is underway.

    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.

  2. 2

    Cross-border power system integration will minimise flexibility needs. Wind and solar pose challenges for power systems due to their variable generation. But weather patterns differ across countries.

    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.

  3. 3

    Conventional power plants will need to operate in a flexible manner. For economic reasons, hard coal and lignite will provide less than 25% of SEE power demand by 2030.

    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.

  4. 4

    Security of supply in SEE power systems with 50% RES is ensured by a mix of conventional power plants and cross-border cooperation.

    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.

  1. 1

    Existing thermal power plants can provide much more flexibility than often assumed, as experience in Germany and Denmark shows.

    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.

  2. 2

    Numerous technical possibilities exist to increase the flexibility of existing coal power plants. Improving the technical flexibility usually does not impair the efficiency of a plant, but it puts more strain on components, reducing their lifetime.

    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.

  3. 3

    Flexible coal is not clean, but making existing coal plants more flexible enables the integration of more wind and solar power in the system. However, when gas is competing with coal, carbon pricing remains necessary to achieve a net reduction in CO2.

    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.

  4. 4

    In order to fully tap the flexibility potential of coal and gas power plants, it is crucial to adapt power markets.

    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.

  1. 1

    Total electricity generation increased by five per cent in 2016, or by about 300 TWh.

    At 65 per cent, coal provides the largest share of total generated electricity. Renewables account for 25 per cent. Consumption increased by 283 TWh, comparable to the entire consumption of Spain.

  2. 2

    However, there is a clear trend towards renewable energy.

    Since 2010, the share of renewables in the power mix has increased by 8 percentage points, while coal has decreased by 11 percentage points.

  3. 3

    Curtailment of renewable energy is high, averaging 17 per cent.

    Some provinces, like Gansu and Xinjiang, plan to slow down wind capacity expansion in the coming years. Furthermore, the government is encouraging expansion of the transmission grid.

  4. 4

    Use of conventional power plants is decreasing.

    Full load hours for coal plants decreased from more than 5,000 hours in 2013 to 4,165 hours in 2016, and energy-related emissions have stagnated at 2013 levels. However, the government is reviewing its plans for new coal plants, and another 200 GW of coal-fired power plants are under construction and are expected to go online by 2020.

  1. 1

    Gas replaced coal, and hence European power sector emissions fell drastically by 4.5 %.

    European coal generation fell by 94 TWh and gas generation increased by 101 TWh, resulting in 48 Mt less CO2 emitted. Half of this happened in the UK, but also Italy, Netherlands, Germany and Greece saw switching from coal to gas. However, gas generation was far from reaching a record – it is still 168 TWh below the 2010 level, showing that more coal-gas switching is possible without new infrastructure.

  2. 2

    Renewables increased only slightly from 29.2 % to 29.6 % of the electricity mix, mainly due to bad solar and wind conditions. Radical price falls give hope for future growth.

    Solar and wind conditions were generally below average in 2016, compared to well above average in 2015. However, with new capacity installed, overall generation still saw small increases. As to prices, 2016 saw record low renewables auction results with only 49,9 Euros/MWh for wind offshore and 53,8 Euros/MWh for solar, both in Denmark.

  3. 3

    Electricity consumption rises slightly by 0.5 %, with European GDP rising by 1.7 %.

    Only two countries saw falls in electricity consumption in 2016, most had modest increases. Investment going into energy efficiency is apparently sufficient to prevent electricity consumption from rising but not enough for electricity consumption to begin structurally falling.

  4. 4

    The structural oversupply of the EU-ETS has passed the landmark of 3 billion tonnes of CO2, as 2016 added another 255 million tonnes CO2.

    The reason is that ETS emissions are structurally below the cap – mocking the concept of a “cap-and-trade” system. To play a meaningful role in EU climate policy, the EU ETS needs to be fundamentally repaired.

  5. 5

    The outlook for 2017 is for further big falls in fossil generation – but whether this is coal or gas is uncertain.

    2016 gave a glimpse of the rapid falls in emissions that are possible with decreased coal production. But a coherent European policy approach to continually increasing renewables and to a just transition in the context of a coal phase-out is needed to ensure that the CO2 reductions of 2016 are continued into the future.

  1. 1

    Wind power costs are coming down, as auction results around the world show:

     in Morocco, Peru and Mexico, average winning bids ranged between 2.7 and 3.4 EUR ct/kWh in 2015/2016. This fundamental cost reduction trend is projected to continue.

  2. 2

    The larger wind turbines are, the cheaper they produce electricity.

    The size of windmills is expected to be the major driver of future cost reductions, as costs for increasing turbine size grow at lower rates than the benefits. The limits to onshore turbine growth are most likely not of a technological nature but rather a question of local political consent.

  3. 3

    In Germany, projects at excellent wind sites can be built with only slightly higher generation costs than the most cost efficient auction-winning projects throughout the world.

    The levelized cost of electricity at those sites ranges between 3 and 4.5 ct/kWh for turbines of the latest generation. Major potentials to further improve cost efficiency are reducing land and maintenance costs, which are far higher than the international average.

From study : Future Cost of Onshore Wind
  1. 1

    Der Kohleausstieg wird sich erheblich beschleunigen.

    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.

  2. 2

    Der ökonomische Druck auf Braunkohlenkraftwerke wird spätestens ab 2024 wieder deutlich zunehmen.

    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.

  3. 3

    Die aktuelle Planung der Braunkohlentagebaue sollte zeitnah an den sich beschleunigenden Ausstieg aus der Braunkohle angepasst werden.

    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.

  1. 1

    As of 2015, renewable energies are Europe’s dominant power source, with a 29 percent share of the power mix.

    Nuclear power comes in second with 27 percent, coal (hard coal and lignite) amount to 26 percent. Among RES, wind power increased significantly by more than 50 terawatt hours to 307 terawatt hours in total. Hydropower produced much less due to less precipitation.

  2. 2

    Three key trends in European power production have emerged in 2010-2015: gas and nuclear power are losing ground, renewables are on the rise while coal is in 2015 back on 2010 levels.

    From 2010 to 2015, gas demand fell by more than a third, while renewables increased by 35.9 percent. Nuclear power production decreased slightly (-6.3 percent) and, following a slight decrease in 2014, coal (hard coal and lignite) returned to the 2010 level in 2015.

  3. 3

    CO2 emissions in the European power sector increased in 2015 by 2 percent. They could be lower by some 100 million tonnes if the decline in fossil power production since 2010 had been coal instead of gas.

    The average price of a tonne of CO2 in 2015 was 7.60 euros, which leads to coal-fired power plants having lower marginal costs than gas-fired power plants. Coal therefore outcompetes gas throughout Europe, which has resulted, for example, in the high coal power exports in 2015 from Germany to its neighbours.

  4. 4

    Outlook: Four major developments will probably characterise 2016: more RES, less coal, less consumption and lower CO2 prices.

    Additional capacity in mainly the onshore and offshore wind energy sector will increase RES production by another 50 terawatt hours. The carbon floor price in the UK, yielding a CO2 price signal of some 30 euros per tonne, will push out coal in the UK in favour of gas. Further efficiency developments and the relatively mild winter will lower power consumption. The demand for CO2 allowances will therefore decrease, leading to lower CO2 ETS prices in 2016 than in 2015.

  1. 1

    Solar photovoltaics is already today a low-cost renewable energy technology.

    Cost of power from large scale photovoltaic installations in Germany fell from over 40 ct/kWh in 2005 to 9ct/kWh in 2014. Even lower prices have been reported in sunnier regions of the world, since a major share of cost components is traded on global markets.

  2. 2

    Solar power will soon be the cheapest form of electricity in many regions of the world.

    Even in conservative scenarios and assuming no major technological breakthroughs, an end to cost reduction is not in sight. Depending on annual sunshine, power cost of 4-6 ct/kWh are expected by 2025, reaching 2-4 ct/kWh by 2050 (conservative estimate).

  3. 3

    Financial and regulatory environments will be key to reducing cost in the future.

    Cost of hardware sourced from global markets will decrease irrespective of local conditions. However, inadequate regulatory regimes may increase cost of power by up to 50 percent through higher cost of finance. This may even overcompensate the effect of better local solar resources.

  4. 4

    Most scenarios fundamentally underestimate the role of solar power in future energy systems.

    Based on outdated cost estimates, most scenarios modeling future domestic, regional or global power systems foresee only a small contribution of solar power. The results of our analysis indicate that a fundamental review of cost-optimal power system pathways is necessary.

  1. 1

    Three components are typically discussed under the term “integration costs” of wind and solar energy: grid costs, balancing costs and the cost effects on conventional power plants (so-called “utilization effect”).

    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.

  2. 2

    Integration costs for grids and balancing are well defined and rather low.

    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.

  3. 3

    Experts disagree on whether the “utilization effect” can (and should) be considered as integration costs, as it is difficult to quantify and new plants always modify the utilization rate of existing plants.

    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.

  4. 4

    Comparing the total system costs of different scenarios would be a more appropriate approach.

    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.

  1. 1

    Between 2025 and 2030, the cost of generating electricity (LCOE) from solar PV and wind power in Japan will be lower than from any other 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.

  2. 2

    Adding the “integration costs” (costs for grid, balancing, and variability) on top of the LCOEs does not fundamentally change the competitiveness of variable renewables in 2030.

    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.

  3. 3

    Integration costs for grids and balancing are well defined and rather low.

    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.

  4. 4

    Integration costs for compensating the variability of renewables are much more disputed.

    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.

  1. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 1

    Germany is currently facing an Energiewende paradox: Despite an increasing share of renewable energy sources, its greenhouse gas emissions are rising.

    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.

  2. 2

    Due to current market conditions, German coal-fired power plants are pushing gas plants out of the market – both within Germany and in neighbouring countries.

    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.

  3. 3

    If Germany is to reach its Energiewende targets, the share of coal in the German power sector has to decrease drastically – from 45 percent today to 19 percent in 2030.

    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.

  4. 4

    Germany needs a coherent strategy to transform its coal sector.

    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.

  1. 1

    New wind and solar can provide carbon-free power at up to 50 percent lower generation costs than new nuclear and Carbon Capture and Storage.

    This is the result of a conservative comparison of current feed-in tari­s in Germany with the agreed strike price for new nuclear in the UK (Hinkley Point C) and current cost estimates for CCS, neglecting future technology cost reductions in any of the four technologies.

  2. 2

    A reliable power system based on wind, solar and gas backup is 20 percent cheaper than a system of new nuclear power plants combined with gas.

    A meaningful comparison of the costs of di­erent energy technologies should take into account the need for backup capacities and peak load plants. Such a comparison shows that while additional costs arise for backup gas capacity in a system based on wind and solar PV, these costs are small compared to the higher power generation cost of nuclear.

  1. 1

    Policy makers have a large scope of action in designing policies for the regional distribution of onshore wind and photovoltaics.

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

  2. 2

    Finding the right balance is important in expanding offshore wind power.

    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.

  3. 3

    Grid expansion is an important prerequisite for the Energiewende.

    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.

  4. 4

    A strong focus on battery storage systems combined with photovoltaic is currently not desirable.

    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.

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