Data and Tools

EEG-calculator and the “Agorameter” are our flagships, along with many smaller applications and data sets.

To make well-founded decisions on the future development of the power system, Agora Energiewende has sought to create the most reliable data and energy economy models possible and, as far as legally possible, to make these public.  These include our own products such as the Agorameter and the EEG-calculator, as well as Excel tools and data sets developed in the course of our studies. Our sources, data and calculation methods are presented as transparently as possible.

For example, more than 1.5 million large and small plants produce and supply power to the network. At the same time, millions of consumers draw power from the network. This complex system can only be thoroughly understood when data is available in a highly aggregated form.

The goals of the Energiewende are measured by how much electricity usage is covered by renewable energies. The progress and success of the Energiewende therefore depends on the extent to which the power system reaches these goals – a question that also is closely related to accessible data.

The same goes for the costs of the Energiewende. This depends, among other things, on which production technologies are used and on a variety of scenarios. The EEG-calculator is a tool anyone can use to calculate these costs and easily develop their own scenarios.

In addition, for many of our studies, we make the models and data they are based on available to the public – for example, costs related to production technologies.

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Core results

  1. 1

    Climate-neutrality in the building sector requires not only one transition, but four:

    1) a building envelope transition, 2) a heating and cooling transition, 3) a building materials transition and 4) a smart electrification transition.

  2. 2

    Investments in the transition to a climate-neutral building sector at the scale needed will not happen on their own.

    Strong regulatory standards must drive investment in line with the EU’s 2030 and 2050 climate targets, in particular ambitious standards for new construction and for renovating existing buildings. Neither carbon pricing or public finance measures alone will suffice. The July Fit for 55 Package put in place some policies to drive investment in public buildings; the December Package must add ambitious requirements for privately owned buildings and for heating appliances, including ambitious minimum energy performance standards.

  3. 3

    Muddling through is not an option.

    A transition at this scale and speed means governments and building owners must plan for success and develop action plans aligned with the longterm goal of a zero-emissions building stock. The July Fit for 55 Package introduced important requirements for comprehensive heating and cooling assessments at national and local level; the December package should add requirements for Member States to develop National Building Renovation Action Plans and for households to use Building Renovation Passports to guide their way to a zero-emissions building stock by 2050.

  4. 4

    Don’t forget the enabling framework!

    Some basic elements of the policy framework needed to make regulatory standards work effectively are not yet in place, including robust energy performance certificates (EPC), environmental product declarations for building materials (EPD) or ambitious Green Public Procurement guidelines. Governments must not lose sight of these often complex and "technical", but essential complementary files.

  1. 1

    The global steel sector is at a crossroads. Before 2030, 71% of existing coal-based blast furnaces (1090 Mt) will reach the end of their lifetimes and require major reinvestments.

    Meanwhile, emerging economies with rising steel demand will require at least 170 Mt of new capacity. Meeting these needs with coal-based capacity will create long-term carbon lock-in and lead to stranded assets, endangering jobs and putting any pathway compatible with 1.5°C out of reach.

  2. 2

    The global steel transformation needs to start in the 2020s. Key low-carbon technologies are ready and can be deployed now.

    The project pipeline of green steelmaking capacity that will come online before 2030 is growing rapidly. 40 Mt of direct reduced iron (DRI) capacity is already planned and many operators have announced that they will switch to secondary steel production. Retroactive post-combustion CCS for coal-fired blast furnaces may be a dead-end road.

  3. 3

    Aligning the steel sector with a 1.5°C compatible scenario needs to put the asset transition from coal to clean at its core.

    The best strategy from now on is to avoid reinvestments into blast furnaces by prolonging life-times of old assets by 2-5 years and after 2025, invest into DRI directly. By 2030, the global steel sector would require 390 Mt of DRI capacity and 278 Mt of additional secondary steel capacity. This is feasible – and would save the atmosphere 1.3 GtCO2 per year.

  4. 4

    A single-speed global steel transformation can bring enhanced international cooperation and a level playing field.

    Steel is a globally traded commodity. The sector’s transformation will require international coop-eration. Meeting the asset transition targets would transition some 1.3 million existing jobs in the steel industry from coal-based to future-proof green jobs while creating 240,000 new green jobs in emerging economies.

From study : Global Steel at a Crossroads
  1. 1

    The July "Fit for 55" package must be guided by three basic considerations: 1) the need for environmental integrity; 2) the need for social and distributional justice; and 3) the need for strong regulatory standards in support of expanded emission trading.

    The EU’s new climate architecture must have ambitious national targets and strengthen the use of emissions trading. But it must also be accompanied by additional financial support and policy measures to address the distributional impact on lower-income Member States, poorer households and industry, and deliver strong regulatory policies in all sectors to keep carbon prices in check.

  2. 2

    The July "Fit for 55" package must ensure enhanced carbon pricing with fairness and environmental integrity.

    The EU should: (1) strengthen the ETS to accelerate the EU coal phase out and clean industry transformation; (2) tighten the Effort Sharing in the Climate Action Regulation and introduce a new separate ETS Directive for transport and buildings; (3) introduce an effective and cooperative approach to carbon leakage protection; and (4) strengthen rules for energy taxes.

  3. 3

    The July "Fit for 55" package must include sectoral policies that deliver.

    EU sectoral policies should: (5) drive the upscaling of renewable energy; (6) drive a just transition in buildings; (7) create an enabling framework for efficiency, electrification, renewables and hydrogen in industry; (8) prepare a phase-out of combustion engines before 2035; (9) roll out the necessary infrastructure for zero emission vehicles; and 10) establish ambitious goals for Agriculture, Forestry and Land-use.

  4. 4

    Important elements are still missing in the second part of the "Fit for 55" package (Q4/2021).

    Initiatives are planned on energy efficiency in buildings, on gas and on methane emissions. To be truly "Fit for 55", the package must also establish a robust framework enabling European industry to invest into climate neutral technologies (e.g., Carbon Contracts for Difference, create new markets for low-CO2 materials, circular economy targets, infrastructure planning). And the Energy Union Governance Regulation must be adjusted to reflect the higher 2030 targets, the new intermediate climate target for 2040, and ensure that the required updates of national energy and climate plans in 2023/2024 are fully consistent with the "Fit for 55" package.

  1. 1

    China’s carbon neutrality pledge sent positive shock waves through the international climate community and has boosted its clean-energy transition efforts.

    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.

  2. 2

    All forms of energy demand, including coal, grew last year, which does not bode well for China’s ambitious international climate commitment.

    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.

  3. 3

    While the COVID-19 economic contraction in China is likely to be short-lived, the pandemic’s profound impact on China’s energy sector and global geopolitics is expected to be felt for many years to come.

    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.

  1. 1

    The EU’s “Fit for 55” climate policy architecture must guarantee environmental integrity and address solidarity.

    To guarantee both, the architecture must have a robust compliance mechanism. Whatever EU climate policy architecture is chosen, each ton of CO2 must be governed by the ETS or the Effort Sharing mechanism. At the same time, the target achievement must be a collective endeavor that supports lower-income Member States and poorer households.

  2. 2

    There are different options for strengthening the ETS and/or effort sharing while ensuring the environmental integrity of the 55% target.

    A standalone ETS for transport and/or buildings, an enlarged EU ETS, or tightened effort sharing are all options that could work, and each has their pros and cons. The important thing is to define who is accountable for reducing emissions, and who will be responsible if targets are not met. When emissions trading serves as the central compliance mechanism, prices must be allowed to rise as high as necessary to reach the emission reduction target – which means not introducing a price cap.

  3. 3

    A carbon price works better if it is supported by companion policies.

    This holds especially true for households and transport. Companion policies in these sectors guide investment decisions and drive innovation, while the carbon price ad-dresses the use of existing cars and heating systems. Strengthening EU-policies such as CO2 standards for vehicles, building codes, or support programs for low-carbon heat grids gives consumers the low-carbon options they need to respond to rising carbon prices and to reduce emissions in line with the 55% target.

  4. 4

    Distributional effects are a challenge but there are solutions for resolving them.

    100% of revenues from carbon pricing must flow back to consumers in one way or another – as targeted support for vulnerable households, as a fund for climate policy measures, or as lump-sum payments. Using carbon pricing revenues for other purposes such as repaying EU debt threaten to undermine support for higher CO2 prices. It is better to use tools that enable consumers to reduce their CO2 footprint, and thus their exposure to higher prices, rather than simply trying to exempt consumer

    groups generally.

  1. 1

    Chinese President Xi Jinping’s pledge on September 22 that the country would reach peak national carbon emissions before 2030 and achieve carbon neutrality before 2060 sent positive shock waves through the climate policy world.

    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.

  2. 2

    Clean energy and climate targets set for the 14th Five Year Plan (FYP) period between 2021 and 2025 are expected to be more ambitious than would otherwise be the case in the absence of a carbon neutrality pledge.

    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.

  3. 3

    The short-lived COVID-induced climate benefits call for greener 14th FYPs for energy and climate.

    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.

  1. 1

    The pandemic triggered an unprecedented economic contraction in the first quarter of 2020, the first time China has experienced a decline in national output in over four decades.

    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.

  2. 2

    COVID-19-induced climate and environmental benefits will be short-lived.

    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.

  3. 3

    The National Bureau of Statistics should consider readjusting China’s energy statistical reporting in the near future, especially with regard to coal-related data.

    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.

  1. 1

    The Japanese power system can accommodate a larger proportion of renewables (RES) than is currently provided for in the government’s 2030 targets, while still maintaining grid stability.

    An annual share of at least 33% RES (22% variable renewables – VRES) can easily be integrated, while still maintaining grid stability within a tolerable range. A higher renewable share of 40% (30% VRES) could also be achieved with very low curtailment level.

  2. 2

    There already exist a number of technical measures to improve grid stability in situations where a high proportion of variable renewables could place a strain on grid operations.

    Indeed, VRES can contribute to maintaining grid stability by providing fast frequency response (FFR). On conservative assumptions, this study shows that such FFR services would enable the existing Japanese transmission grid to incorporate instantaneous VRES penetration levels of up to 60% in eastern Japan and around 70% in western Japan, while still maintaining frequency stability. These assessments confirm the trends observed in 2018 in regions such as Kyushu or Shikoku, where hourly VRES penetration satisfied more than 80% of demand (corresponding to more than 55% of all power generation). By 2030, these high regional infeed levels could become the norm for the Japanese system as a whole. Furthermore, implementing additional technical measures would allow even higher penetration levels to be reached.

  3. 3

    Integrated grid and resource planning can help mitigate the impact of wind and solar PV deployment on intraregional and interregional load flows.

    Increasing the proportion of VRES in the mix is expected to reduce power line loading in some regions and increase it in other parts of the system. The impact of VRES distribution on the grid must therefore be systematically taken into account in future grid development plans, in order to avoid creating line-loading hotspots.

  4. 4

    Non-discriminatory market regulations, enhanced transparency, and state-of-the-art operational and planning practices facilitate the integration of a higher proportion of variable renewables.

    In particular, renewables should be incorporated into ancillary service provision, since they can contribute to frequency stability, balancing, and voltage control in tandem with other technologies (such as demand side response, conventional generation, and storage).

  1. 1

    The Japanese power system can accommodate a larger proportion of renewables (RES) than is currently provided for in the government’s 2030 targets, while still maintaining grid stability.

    An annual share of at least 33% RES (22% variable renewables – VRES) can easily be integrated, while still maintaining grid stability within a tolerable range. A higher renewable share of 40% (30% VRES) could also be achieved with very low curtailment level.

  2. 2

    There already exist a number of technical measures to improve grid stability in situations where a high proportion of variable renewables could place a strain on grid operations.

    Indeed, VRES can contribute to maintaining grid stability by providing fast frequency response (FFR). On conservative assumptions, this study shows that such FFR services would enable the existing Japanese transmission grid to incorporate instantaneous VRES penetration levels of up to 60% in eastern Japan and around 70% in western Japan, while still maintaining frequency stability. These assessments confirm the trends observed in 2018 in regions such as Kyushu or Shikoku, where hourly VRES penetration satisfied more than 80% of demand (corresponding to more than 55% of all power generation). By 2030, these high regional infeed levels could become the norm for the Japanese system as a whole. Furthermore, implementing additional technical measures would allow even higher penetration levels to be reached.

  3. 3

    Integrated grid and resource planning can help mitigate the impact of wind and solar PV deployment on intraregional and interregional load flows.

    Increasing the proportion of VRES in the mix is expected to reduce power line loading in some regions and increase it in other parts of the system. The impact of VRES distribution on the grid must therefore be systematically taken into account in future grid development plans, in order to avoid creating line-loading hotspots.

  4. 4

    Non-discriminatory market regulations, enhanced transparency, and state-of-the-art operational and planning practices facilitate the integration of a higher proportion of variable renewables.

    In particular, renewables should be incorporated into ancillary service provision, since they can contribute to frequency stability, balancing, and voltage control in tandem with other technologies (such as demand side response, conventional generation, and storage).

  1. 1

    The Japanese power system can accommodate a larger proportion of renewables (RES) than is currently provided for in the government’s 2030 targets, while still maintaining grid stability.

    An annual share of at least 33% RES (22% variable renewables – VRES) can easily be integrated, while still maintaining grid stability within a tolerable range. A higher renewable share of 40% (30% VRES) could also be achieved with very low curtailment level.

  2. 2

    There already exist a number of technical measures to improve grid stability in situations where a high proportion of variable renewables could place a strain on grid operations.

    Indeed, VRES can contribute to maintaining grid stability by providing fast frequency response (FFR). On conservative assumptions, this study shows that such FFR services would enable the existing Japanese transmission grid to incorporate instantaneous VRES penetration levels of up to 60% in eastern Japan and around 70% in western Japan, while still maintaining frequency stability. These assessments confirm the trends observed in 2018 in regions such as Kyushu or Shikoku, where hourly VRES penetration satisfied more than 80% of demand (corresponding to more than 55% of all power generation). By 2030, these high regional infeed levels could become the norm for the Japanese system as a whole. Furthermore, implementing additional technical measures would allow even higher penetration levels to be reached.

  3. 3

    Integrated grid and resource planning can help mitigate the impact of wind and solar PV deployment on intraregional and interregional load flows.

    Increasing the proportion of VRES in the mix is expected to reduce power line loading in some regions and increase it in other parts of the system. The impact of VRES distribution on the grid must therefore be systematically taken into account in future grid development plans, in order to avoid creating line-loading hotspots.

  4. 4

    Non-discriminatory market regulations, enhanced transparency, and state-of-the-art operational and planning practices facilitate the integration of a higher proportion of variable renewables.

    In particular, renewables should be incorporated into ancillary service provision, since they can contribute to frequency stability, balancing, and voltage control in tandem with other technologies (such as demand side response, conventional generation, and storage).

  1. 1

    Synthetic fuels will play an important role in decarbonising the chemicals sector, the industrial sector, and parts of the transport sector.

    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.

  2. 2

    To be economically efficient, power-to-gas and power-to-liquid facilities require inexpensive renewable electricity and high full load hours. Excess renewable power will not be enough to cover the power demands of synthetic fuel production.

    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.

  3. 3

    In the beginning, synthetic methane and oil will cost between 20 and 30 cents per kilowatt hour in Europe. Costs can fall to 10 cents per kilowatt hour by 2050 if global Power-to-Gas (PtG) and Power-­to-Liquid (PtL) capacity reaches around 100 gigawatts.

    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.

  4. 4

    We need a political consensus on the future of oil and gas that commits to the phase-out of fossil fuels, prioritises efficient replacement technologies, introduces sustainability regulations, and creates incentives for synthetic fuel production.

    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.

  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

    Initial EEG investments will begin to pay out in 2023: From then on, the EEG surcharge will fall despite increasing shares of renewable energy.

    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.

  2. 2

    If the expansion of renewables continues at its ambitious pace, electricity costs will rice by 1-2 ct/kWh until 2023, but then fall by 2-4 ct/kWh by 2035.

    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.

  3. 3

    In 2035, electricity will cost the same as today, but 60 per cent will stem from renewable sources.

    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.

  4. 4

    Main factors driving the EEG surcharge in the future will be the wholesale power price, the level of power demand, exemptions for industry and the amount of self-consumption.

    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.

From study : Projected EEG Costs up to 2035
  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

    Wholesale spot power prices are on the decline in many parts of Europe, and are lowest in Germany and Central Eastern Europe (especially in Poland and the Czech Republic). Meanwhile, prices have been rising in the US.

    Since 2011, spot prices have been decreasing in Europe, except for in the UK, Belgium and the Netherlands. While spot prices in Germany were higher than in the US during 2010-2012, in 2013 they fell below the New York ISO prices, and converged with those of other US regions. In many other European markets, the gap with US prices remains significant.

  2. 2

    Wholesale market prices can serve as a starting point for comparing the energy costs of European industries, especially energy-intensive industries. Nevertheless, this approach has inherent limitations:

    (1) Wholesale prices don’t necessarilyaccurately reflect the “energy component” of prices paid by end users, due to differences in purchasing strategies, longtermcontracts and potential price regulation; (2) Several additional components must be taken into account as well (gridtariffs, renewable levies and other taxes), from which industrial actors may receive partial or full exemptions.

  3. 3

    While numerous European companies have complained of market distortion due to regulatory favouritism for Germany’s energy-intensive industries,...

    ...caution must be exercised when attempting to directly compare industrial end-use pricesbetween countries and sectors. Against the backdrop of decreasing wholesale prices and increasing exemptionsfor energy-intensive consumers in Germany, several EU member states have argued that domestic regulations inGermany create market distortions that unduly favour German firms. Because firms in different regions and sectorsvary considerably in the extent to which they pay wholesale market prices and/or receive tax exemptions and levyreductions, comparing prices between sectors and countries is a difficult task. The heterogeneity of the situation is notfully and transparently captured by European statistics.

  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.

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