Much of the climate ambition of the EU hinges on the bloc’s emission trading system (EU ETS). During December 2022, the Council and the European Parliament reached important agreements on the “Fit for 55” proposals. With these revisions implemented the EU would edge closer to its 2030 climate targets, but question marks remain.

Much of the climate ambition of the EU hinges on the bloc’s emission trading system (EU ETS). During December 2022, the Council and the European Parliament reached important agreements on the “Fit for 55” proposals. Specifically, new rules for the existing EU ETS, the implementation of a carbon border adjustment mechanism (CBAM) and the introduction of a new EU ETS for emissions from buildings and road transport are in sight. With these revisions implemented the EU would edge closer to its 2030 climate targets, but question marks remain. In this article we unpack some of the most relevant points on changes and updates on the EU ETS I and CBAM.

EU ETS I: new inclusion, rebasing and strong annual cap reduction

Currently, the existing EU ETS covers roughly 40% of the EU’s emissions. They stem from the energy sector, industrial installations and aviation. Maritime transport will be the newcomer and large vessels of 5000 gross tonnage and above must gradually surrender emission allowances (EUA) for an increasing share of their emissions: 40% in 2024, 70% in 2025 and 100% in 2026. The inclusion of smaller vessels and non-CO2-emissions such as methane and N2O will likely start from 2026 onwards.

Next to this new inclusion, the overall ambition of emission reductions until 2030 compared to 2005 under the EU ETS increased to 62% (Figure 1). The agreement reached on 18th of December 2022 would thus lead to about 23 million tons less CO2-emissions compared to the EU Commission’s proposal from 2021 and is much more aggressive than the minus 43% that has been the previous reduction target. While the target is politically ambitious, it still falls short of the necessary reductions in the EU to limit global warming to 1.5°C even without taking into account fair share considerations.

To achieve this stronger reduction of 62%, the legislators agreed on a rebasing of emissions: 90 million EUA are taken out of the market in 2024 with another 27 million EUA following in 2026. In addition, the entire emission cap will be reduced by 4.3% annually from 2024 to 2027. From 2028 onwards this linear reduction factor (LRF) will even rise to 4.4%. As expected, the market stability reserve (MSR) will continue to take out 24 % of surplus EUAs.

All these reductions will lead to significantly tighter supply of EUAs, drive prices and incentivise more decarbonisation especially in industrial sectors. This brings us to the changes for the industrial sector.

Fundamental change for the industrial sector

Most of the industrial sectors under the EU ETS are currently still eligible for free allocation of EUAs. Based on benchmarks on efficient and thus less emission-intensive production, different industrial facilities will still receive free allowances. However, the benchmark system will be overhauled in 2026: the basis for the free allocations will not be a production process, but the product. This facilitates a better comparison between industries. In addition, industrial companies must have energy audits in place and implement related decarbonisation measures. Otherwise, the free allocation volumes of a facility will be reduced by 20%. Similarly, industrial facilities that are among the worst 20% in terms of carbon-intensity in one sector have to design and implement decarbonisation plans, otherwise their free allocations will be cut by 20%.

However, the biggest change will be the phase-out of free allocations for industrial players as such. From 2026 onwards, the number of free allowances handed over to industries will be reduced gradually until 2034 when industries have to procure all of their needed allowances through the auctioning mechanism or on the market. Free allocation will be part of the history books. As becomes clear from Figure 2 below, the phase-out of free allocation for industry starts relatively slowly compared to the phase-out for aviation and picks up speed from the end of the decade. This approach postpones that necessary price signals kick in for industrial polluters while allowing the EU industry to prepare and decarbonise in earnest during the next five years.

The EU Commission expects that about 75 million more EUAs will be auctioned due to the phase-out of free allocations to industry, increasing the auction income. Half of that income should go into the EU Innovation Fund that supports these very industries with the implementation of decarbonisation projects. The other half will be available for the EU member states to support their exporting industries. Which leads us to the next large update as phasing out free allocations is tightly coupled with the introduction of the carbon border adjustment mechanism (CBAM).

At the same time and rate as European industries will not receive free allocations of EUA anymore, importers of certain goods into the EU will have to pay for the emissions of their products. This carbon border adjustment mechanism (CBAM) should on the one hand create a level-playing field between EU and non-EU industries for products in the EU (both paying a similar carbon price) and increase climate ambition in non-EU states (climate instruments and carbon pricing abroad can reduce necessary payments for importers).

Initially, CBAM will cover the most emission-intensive sectors: iron and steel, cement, fertilisers, aluminium, electricity. The new agreements from 13th of December 2022, however, also feature hydrogen, certain precursors and other downstream products such as screws and bolts as imports under CBAM. In addition, the EU Commission will assess the inclusion of other products that might be at risk of carbon leakages such as organic chemicals and polymers into CBAM from 2030 onwards. Indirect emissions at the production facility also might have to be part of the emissions to be reported and consequently paid for by importing companies. From October 2023 importers in the covered sectors must be ready for their monitoring, reporting and verification (MRV) obligations, which start 3 years ahead of the pricing mechanism. Figure 3 depicts the timeline of the CBAM implementation.

Two main contentious issues remain for CBAM:

How will reporting and verification methods and schemes really look like and work for imported goods?

How to compensate or support companies that produce in the EU and must purchase EUAs but export to non-EU countries where no or less ambitious carbon pricing rules exist?

Next to those sectors that are already under the EU ETS, a lot of emissions from other activities in the EU are not part of an emission pricing scheme. After much uncertainty about its prospects, it is now clear: a new or second emission trading system (EU EHS II) will be implemented as well. This will be the topic of our second article.

. Illuminem Voices is a democratic space presenting the thoughts and opinions of leading Sustainability & Energy writers, their opinions do not necessarily represent those of illuminem.

Biggest update to EU emission trading rules in years, part I: EU ETS and CBAM

Reducing dependence on Russian gas is the order of the day. Thus, import LNG terminals will soon play an important role in Germany. The idea of building import terminals for liquefied natural gas (LNG) on the German coast is already several years old. However, political support for the construction of the planned facilities in Brunsbüttel, Wilhelmshaven and Stade was limited. Moreover, investment decisions by economic actors also dragged on for a long time, were put on hold or planning was very slow.

Now everything has to happen very quickly at once. For this reason, this article answers to the most important questions:

When can the terminals go into operation?

And what do they mean for climate protection?

The invasion of Ukraine by Russia made it clear to all actors in Germany: Diversification of gas imports is urgently needed. Moreover, the great dependence on Russian gas can severely impair Germany’s security of supply in the event of a supply stoppage.

Russia stopped gas supplies to Poland and Bulgaria at the end of April. Our 

 examines the German and EU-wide supply situation under different supply scenarios of gas from Russia. Thus, a supply gap can only be closed in the short term by reducing consumption. Mid term, new regasification capacities for liquid natural gas are needed in Europe, especially for Germany. Hence, Europe might become independent of Russian gas supplies.

Germany currently consumes about 90 billion cubic meters of natural gas per year. More than 50 per cent still came from Russia via pipelines in 2020. Moreover, the EU was still heavily dependent on Russian gas in 2021, which accounted for 45 per cent of imports. However, almost 15 per cent of EU imports last year were provided by LNG from the USA or Qatar, for example, as Figure 1 shows. A further 10 billion cubic metres came via the Mediterranean from Algeria (sources: 

Figure 1: Shares of natural gas import countries in Germany and the EU (source: Energy Brainpool, 2022)

To reduce German dependence, LNG is to come to Germany in the very short term via floating terminals, so-called FSRUs (Floating Storage and Regasification Units). These terminals receive the liquid natural gas cooled to about -163 degrees Celsius from an LNG tanker. Then, the still-liquid natural gas is regasified and brought ashore via a connecting pipeline. There it can be fed into the gas grid. Moreover, plans for the 

First of all, the onshore LNG import facilities have to be built before imports can start. Under normal conditions, a timeframe of five or more years is realistic for planning, permitting and construction. On the one hand, for the planned LNG import terminals in Brunsbüttel and Stade, commissioning is likely to take place earliest in 2024 or later, even with strong political support. The terminal in Wilhelmshaven, on the other hand, could regasify imported LNG from the US or Qatar and feed it into the German gas grid as early as winter 2023/2024.

Nevertheless, a number of FSRUs are to be at sea off the German coast sooner. So far, Germany has reserved four special ships on the world market. Moreover, the first liquefied natural gas is to be landed from a floating terminal off Wilhelmshaven as early as the turn of the year 2022/2023. In total, it can replace up to 20 percent of gas imports from Russia. Thus, the first pile driving – which is equivalent to a groundbreaking ceremony, only at sea – already took place on the fifth of May. On top of that, another ship is planned for stationing in Brunsbüttel in early 2023 (source: 

According to plans of the Federal Government, two more floating terminals are to be rented near Stade, Rostock, Hamburg-Moorburg or Eemshaven in the Netherlands and operated for ten years. Therefore, a total of EUR 2.94 billion is available from the federal government’s budget for the procurement of the four terminals (source: 

In addition, the Federal Government is currently working at full speed on an LNG Acceleration Act (

). It is intended to greatly accelerate the construction and operation of both floating and land-based terminals by shortening approval procedures and reducing environmental regulations. The LNG import terminals will only be allowed to be in operation until 2040. What is more, the plant operators can submit a permit application to convert the plants to the use of green hydrogen or other green derivatives by 2035. Then, the terminals can continue to operate after 2040 (source: 

Capacities of already existing terminals in Europe

LNG import terminals have existed in many European countries for a number of years, 37 in total, 26 of which are located in EU member states. Between 20 and 30 more import terminals are currently being planned. The capacity of the continent’s existing regasification terminals is just under 250 billion cubic meters per year (source: 

Capacities are particularly high in Spain, with 60 bcm, as the Iberian Peninsula is only very partially connected to the gas network of Central Europe. However, the UK, Turkey and France also have significant LNG import capacities as Figure 3 makes clear. Countries such as Lithuania and Poland each have terminals of only four and five billion cubic meters, respectively, but are able to source much of their gas requirements through them.

What capacities should the terminals in Germany have?

The planned terminals in Germany are expected to have considerable capacity. The four floating LNG terminals are to be gradually expanded to a capacity of 33 billion cubic meters per year by summer 2024. This is based on the BMWK in its second energy security progress report. By winter 2022/2023, it could already be possible to obtain 7.5 billion cubic meters of LNG for the German market.

With the completion of the terminals in Brunsbüttel and Wilhelmshaven, between 45 and 50 billion cubic meters of LNG could be supplied to Germany from 2026. Each has around 8 billion cubic meters of regasification capacity. This would catapult Germany into second or third place among Europe’s largest LNG importers. The potential imports would then also be roughly equivalent to the import of natural gas from Russia in recent years. Dependency on Russian natural gas could be reduced to just 10 percent from as early as 2024 through further energy efficiency and conservation measures (source: 

Diversification with a long-term perspective

However, the chartering of the FSRUs, as well as the construction of the new LNG terminals, also raises questions. New fossil fuel infrastructure is being developed and partly financed by the German government. This could create overcapacity and cement existing energy consumption patterns. Moreover, the triangle of objectives between sustainability, security of supply and economic efficiency is important. Especially, in an extreme situation of a war this has be taken into account .

Therefore, according to the Federal Ministry of Economic Affairs and Climate Protection, infrastructures and land-based terminals in Germany should be planned and built in a way that they are suitable for the import of green hydrogen or other derivatives such as green ammonia (source: 

). Uniper’s planned terminal in Wilhelmshaven is either to be built with a landing terminal for green ammonia or at least to allow conversion to green imported products (source: 

). Similarly, RWE and Gasunie plan to build the Brunsbüttel terminal a special way. Thus, the terminal can be easily converted to green ammonia imports afterwards. Simultaneously, a terminal for green ammonia is already to be built here next to the LNG import terminal. Green hydrogen can then be produced from the green ammonia in a further process step (source: 

What does this mean for climate protection?

Germany will continue to be dependent on energy imports from abroad in the future. For instance, green ammonia or hydrogen will have to be imported from other countries. Especially for the decarbonization of industrial processes and parts of the transport sector. The war in Ukraine has thrown old certainties overboard. The shift away from Russian gas can be reduced in the medium term through LNG import terminals. However, the expansion of these infrastructures must also be designed to achieve medium- and long-term climate targets.

. Illuminem Voices is a democratic space presenting the thoughts and opinions of leading Energy & Sustainability writers, their opinions do not necessarily represent those of illuminem.

Rocket program for German LNG terminals

The energy systems of the two largest EU countries differ. A comparison of the electricity sectors in particular shows the contrasts. Electricity generation in France is dominated by nuclear power, which accounts for almost 70 percent, while Germany’s electricity mix relies on coal and natural gas as fossil fuels for one-third of the total. Follow us in this article as we explore the differences between the two energy systems.

Just by looking at the primary energy consumption of the two countries, the differences between France and Germany become clear. France’s primary energy consumption of about 10000 PJ was for many years about one third lower than that of Germany. However, in addition to the higher economic output, the high shares of coal-fired power generation in Germany also played an important role.

Primary energy consumption declines in both countries

Primary energy consumption has been declining in both countries since 2010. Since that time, coal-fired power generation in Germany decreased (especially from 2017), while renewable energy shares grew. Renewable generation also increased in France during this period, but less so than in Germany. For example, primary energy consumption in France declined by 7.8 percent between 2010 and 2019, and by as much as 10 percent in Germany. The Corona pandemic led to an economic slump in both Germany and France, resulting in a drastic drop in energy consumption as shown in Figure 1 (source: 

While the share of oil in primary energy consumption is relatively similar in France and Germany, the shares for other energy sources lie far apart. In 2019, for example, nuclear energy accounted for 43 percent of French primary energy consumption. In contrast, with only 6 percent in Germany at that time. After 2023, the generation of electricity from nuclear power plants in Germany will decline to zero as the last reactors are shut down. There are also big differences in the share of coal. While hard coal and lignite still accounted for 17 percent of primary energy in Germany in 2019, the share of coal in France was only 3 percent in the same period (source: 

). Figure 2 illustrates the shares of different energy sources in primary energy supply in France (inner ring) and Germany (outer ring). 

The higher shares of fossil fuels in Germany are also reflected in the greenhouse gas emissions balance. While French greenhouse gas emissions were 443 million metric tons CO2– eq. in 2019 (source: 

), emissions in Germany stood at 800 million metric tons CO2-eq. according to the Federal Environment Agency (source: 

). This means that France’s production-related greenhouse gas emissions before the Corona pandemic were almost 45 percent lower than in Germany.

In particular, France’s relatively low-CO2 electricity generation contributes to low climate-damaging emissions. The CO2-intensity of electricity generation in France stood at around 57 CO2/kWh in 2020 (source: 

). In Germany, the electricity mix at the same time had a CO2-intensity of 366g CO2/kWh, which was more than six times higher (source: 

). The explanation for this high discrepancy lies in the technologies used to generate electricity in the two countries.

German power generation capacity is best described as a colorful mix. With over 120 GW of renewable capacity and more than 70 GW of fossil power plants, Germany had a total capacity of over 220 GW of power plant capacity on the grid in 2020 (source: 

). In France, total capacity was just over 130 GW, with just under 60 GW of renewable capacity installed. At the same time, nuclear power plants account for the majority of French capacity, with over 61 GW of installed capacity (source: 

). Figure 3 compares the generation capacities in the two countries.

France and Germany each produced about 525 TWh of electricity in 2020. To understand the low CO2-intensity of French power generation, it is necessary to look at actual power generation and not just installed capacity. Here, it becomes very clear how strongly nuclear power dominates the French electricity sector. Until before 2020, nuclear power usually accounted for over 70 percent of electricity generation in France. In 2020, however, nuclear generation declined to 67 percent, or just over 350 TWh, due to the closure of two plants. Hydropower generation was the second largest source, contributing just under 64 TWh of electricity (source: 

German electricity generation presents a more diverse picture, with generation from fossil sources declining in 2020 compared to previous years due to pandemic-related impacts. The share of renewables in gross electricity generation in Germany reached the 45 percent mark in 2020 (source: 

). Figure 4 shows electricity generation in France and Germany by technology in 2020.

With the new traffic light coalition, the signs in Germany point to a faster implementation of the energy transition (

see our report on the traffic light coalition

). Also, under the impact of the armed conflict in Ukraine, Europe’s energy supply will not remain unchanged. Until now, natural gas was still politically high on the agenda as a bridge to climate neutrality. This has changed significantly after the events at the end of February 2022.

According to a key issues paper dated February 28, 2022, Germany is to achieve its power supply entirely from renewable energies by 2035. To this end, the output of onshore wind energy should double to up to 110 GW by 2030 (source: 

With the inclusion of nuclear power plants in the EU taxonomy (

 you can finde our detailed article on this topic), CO2-free generation in French nuclear power plants could develop even further. However, the fleet of power plants is aging and the commissioning of new power plants (Flamanville) has been repeatedly postponed while costs have increased (source: 

The long-term outlook for nuclear power in France is uncertain. According to French President Macron, nuclear power is still entitled to a maximum of 40 percent of electricity generation in 2050 (source: 

Cooperation between the two countries regarding the transformation of their energy systems will certainly have to intensify in the coming years.

Energy Voices is a democratic space presenting the thoughts and opinions of leading Energy & Sustainability writers, their opinions do not necessarily represent those of illuminem.

Two different energy systems: France and Germany compared

The new government is not the only one with ambitious plans for 2030. In their scenario framework 2023–2037 for electricity, the German transmission system operators also presented the electricity sector up to 2045 for the first time. In that year, Germany aims to be climate neutral. What assumptions do the grid operators make and what does the scenario mean for the energy industry? We want to explore these questions in this article. 

Every two years, the German transmission system operators (TSOs) must submit an electricity network development plan (NDP) for the next ten to twenty years. The basis for the NDP and thus the necessary expansion and construction measures for the transmission grid of the future is the scenario framework that the TSOs published on 17 January 2022. Besides that the date also marked the start of the 

public consultation phase by the Federal Network Agency

New scenario framework provides outlook for climate neutrality

In the course of the stronger focus on climate neutrality in industry, politics and society, the TSOs have not only developed a forecast up to 2037 in their 

, but also scenarios for the power system in 2045. In that year, Germany is supposed to be climate neutral according to the current climate protection law. And thus, as a country, it has no longer any harmful influences on the climate system. In the further course of the NDP process, the corresponding measures for the grid expansion will be developed. However, here we will primarily focus on the statements of the scenario framework for electricity generation and consumption until 2045.

All in all, the TSOs have developed scenarios with different transformation speeds. Scenario A shows a higher use of (imported) hydrogen. In contrast, Scenarios B and C anticipate a pronounced and faster electrification of energy consumption. For the climate neutrality scenario in 2045, B/C coincide with stronger electrification. Figure 1 shows the classification of the different scenarios according to energy-related metrics.

As can be seen in Figure 1, the range between the scenarios with respect to certain metrics (such as hydrogen demand, hydrogen import/export saldo and the transmission capacity of cross-border interconnectors) is very wide. The following considerations compare Scenario A (conservative), Scenario C (progressive) for 2037 and Scenario B/C for 2045. Comparison with the current federal government’s goals and estimates for 2030 is also helpful in some cases.

The TSOs’ scenario framework makes it very clear that electricity consumption will increase strongly with ambitious climate targets and sector coupling. For example, consumption increases in all sectors due to direct electrification of processes in industry, but also the greater penetration of electric vehicles, heat pumps, and the use of electrolysers to produce hydrogen.

Figure 2 illustrates the increase in gross electricity consumption along with the differences between the scenarios.

Already by 2030, the demand for electricity increases strongly from below 600 TWh today. The German government assumes a corridor of 680 to 750 TWh of electricity demand in 2030, with 715 TWh representing the mean value. The increase weakens by 2037 in Scenario A, which relies more heavily on imported hydrogen. However, the increase is substantial by 2037 in Scenario B, with over 200 TWh in 7 years.

In 2045, the year of climate neutrality, electricity consumption in Germany will have more than doubled compared to 2020. That represents an increase of more than 23 TWh per year or about half of the electricity consumption of Portugal.

What will happen in the transport sector by 2045?

One driver of additional electricity consumption is electric mobility, which experiences strong growth in the scenarios. Figure 3 shows the scenario framework’s assumptions for the number of all-electric passenger vehicles by scenario.

The targeted increase to 15 million e-vehicles by 2030 is ambitious, but necessary to achieve the climate targets by then. Therefore, the German government also sees the need for a massive increase in the share of electric mileage in the transport sector.

The TSOs’ scenario framework provides further relevant information on the transformation of the transport sector. For example, private cars consume only half of the electricity required in transport from 2037 onwards.

In 2045, the electrification of freight transport even accounts for more than half, with just under 90 TWh of annual consumption. Overall, electricity consumption in this sector rises to over 160 TWh, as Figure 4 shows.

Heat pumps and electrolysis drive electricity demand

Electricity consumption is also rising sharply in other sectors because of electrification. In particular, the generation of heat in heat pumps at the household level, but also the use of electricity in district heating, will increase electricity demand. The use of electrolysers to generate hydrogen increases strongly in the TSOs’ scenarios. Figure 5 makes this clear.

With almost 85 TWh of electricity consumption in the heat sector and 120 TWh by electrolysis, an additional electricity demand of more than 200 TWh comes from those sectors in 2045. This corresponds to about 35 per cent of today’s electricity consumption in Germany.

In order for the increased electricity demand from sector coupling and electrification also leading to sharply declining CO2 emissions, the generation capacities of renewable energies must be greatly expanded (Figure 6). The German government and Economics Minister Habeck have already announced their targets for 2030 and are currently developing the appropriate measures to enable the necessary expansion. For more details, please read our 

article on the energy targets of the “traffic light” coalition

Solar energy makes the biggest leap in all scenarios. PV power plants have between 260 and 320 GW of installed capacity in 2037, and nearly 400 GW in 2045. This would require a net addition of 12 to 15 GW per year by 2037 and just under 10 GW from 2037 to 2045. Wind generation capacity would also need to increase sharply.

In Scenario B/C 2045 offshore wind generates 280 TWh while onshore wind and PV each contribute another 375 TWh. Renewables (including small amounts of hydropower, biomass, and biogenic waste) would then account for 91 per cent of electricity generation.

It will probably not be possible to achieve the annual climate targets until the year 2023, as the addition of renewables has fallen sharply in the past four years (source: 

). The new German government and companies must now set the course to ensure that the German energy system is largely based on renewable energies by 2045 and that Germany is climate neutral. This task can only be achieved by society as a whole.

The climate-neutral grid in 2045: What do the transmission system operators expect?

The economic slump caused by Corona seems to have had little impact on energy consumption in 2021, at least in China. Thus, electricity consumption increased to almost 8400 TWh. At the same time, the shares of renewable energies also increased even if the addition could not reach the peak values of 2020.

. Thus, electricity consumption increased to almost 8400 TWh. At the same time, the shares of renewable energies also increased even if the addition could not reach the peak values of 2020.

Electricity generation in the world's most populous country rose to a new record high of 8377 TWh in 2021. Compared to the previous year, generation increased by about 750 TWh. This is about 1.3 times of Germany's total electricity generation last year and once again highlights the sheer size and relevance of China to all global energy and climate objectives. The first preliminary energy figures from China for 2021 can be viewed at the 

Despite a sharp increase in electricity consumption, renewables in China managed to grow by one percentage point. As a result, renewables reached 28 per cent of China's electricity generation last year. Generation from thermal power plants (90 per cent coal) declined by one percentage point to 67 per cent. Figure 1 shows the breakdown between the main energy sources.

However, thermal power plants provided the bulk of the additional electricity generation of 750 TWh last year. Generation from coal and gas-fired power plants increased by 9 per cent year-on-year, or nearly 470 TWh. Renewables, on the other hand, contributed only about one-third of the total growth in electricity generation, 240 TWh. The growth in renewables was primarily enabled by wind power, while generation from hydropower decreased compared with the previous year due to climatic conditions.

Generation from nuclear power plants also made a jump, increasing by about 41 TWh compared to 2020 to a total of over 400 TWh. The year-to-year change in generation from different technologies between 2020 and 2021 is shown in Figure 2.

In percentage terms, year-on-year growth was highest for wind power, with a 40 per cent increase, followed by a 25 per cent increase in solar generation compared to 2020.

In total, the main renewable energy sources in China generated over 2300 TWh of electricity last year. Figure 3 illustrates the trend in renewable electricity generation from 2010 to 2021, with PV plants alone generating nearly 330 TWh of electricity in China, while wind energy came in at over 650 TWh. By comparison, total electricity generation in Germany was about 580 TWh in 2021.

Renewable expansion weaker than in previous year

The large increase in wind power generation in 2021 was made possible primarily because a record 72 GW of wind power was installed in 2020. 

 we go into detail about the changes in China's power system in 2020.

Such high capacity growth was not possible for wind energy in 2021, but PV capacity grew by 53 GW last year. This is a bit less than the total installed solar capacity in Germany which stands at about 60 GW. Hydropower was also expanded comparatively strongly in 2021, increasing by 21 GW. However, the capacity of thermal conventional power plants also increased by around 50 GW. The annual increases in renewable energy capacity can be seen in Figure 4.

The addition of offshore wind power stood out particularly in China in 2021. Last year the capacity grew from less than 10 GW to 26.4 GW, an increase of almost 17 GW. This required the installation of 30 large offshore turbines every week (source: 

). Half of all offshore wind turbines installed worldwide are now off the coast of China as of the end of 2021 (source: 

). The strong additions in 2021 were driven by the drop in the feed-in tariff for offshore wind turbines from 850 yuan/MWh ($134/MWh) as of January 1, 2022, to the low tariff also received by coal-fired power plants (source: 

China continued to account for a large share of the world's installed renewable energy in 2021. China's hydro, wind, and solar generation capacity exceeded the 1000 GW threshold last year. Thus, China should easily meet its target of 1200 GW of renewable capacity by 2030. It could also be exceeded by 300 GW with today's expansion figures. The development since 2010 is shown in Figure 5.

In 2021, as in 2020, the largest share of renewable capacity additions in China took place in the last quarter. With a total of 31 GW of newly installed capacity in wind and 28 GW in PV, China added 50 to 60 per cent of the total annual additions in the fourth quarter of 2021. In addition to the drop in offshore wind feed-in tariffs to the new year, the end of a feed-in tariff for residential PV on December 31, 2021 (source: 

) was also key to the installation run in the last three months of the year (see Figure 6).

The Chinese Emissions Trading System and "Dual Carbon“

After the emission trading system in China started in July 2021, more than 1 billion yuan or 165 mil USD of pollution rights have been turned over by the end of 2021. So far, there is still no cap on the allowances issued (source: 

Therefore, there were hardly any spectacular price movements in the course of the last year. The price ranged between 41 and 61 yuan/ton or 6 and 9 USD/ton and is thus about one tenth of the price in the European emissions trading system (source: 

). By 2025, in addition to the electricity sector affected so far, plants from other industries such as steel and cement production are also to be covered by the Chinese emissions trading system.

In 2021, the Chinese government has also increasingly communicated its "dual carbon" target internationally. Firstly, CO2 emissions are to peak in 2030, and secondly, the country is to achieve climate neutrality in 2060. Figure 7 shows the development of CO2 emissions from China's energy sector (data: 

Against this backdrop, however, the country's energy transformation needs to be significantly strengthened. The first target in 2030 is probably still the easier one.

However, China was not spared from the energy price crisis and scarcity of fossil raw materials in 2021, and some factories and areas of the country had to go without power for a time due to planned load shedding. Whether the situation last fall will also have an impact on China's short- and medium-term energy and climate policy beyond 2022 is yet to be seen. However, there is no doubt that the developments in the Asian country will have a major impact on global energy markets.

China’s electricity system in 2021: More new generation than all of Germany

The potential inclusion of nuclear power and natural gas in the EU taxonomy has again ripped open the rifts in European energy and climate policy. What exactly does the EU taxonomy regulate and what conditions are attached to classifying the two technologies as sustainable? 

The potential inclusion of nuclear power and natural gas in the EU taxonomy has again ripped open the rifts in the European energy and climate policy. 

What exactly does the EU taxonomy regulate and what conditions are attached to classifying the two technologies as sustainable?

 In this article, we put the discussions surrounding the EU taxonomy in context.

As the core of the EU sustainable finance action plan, the 

EU taxonomy aims to do one thing above all: channel financial flows into more sustainable activities

 and the specific needs of the European economy for the benefit of the planet and our society. As a uniform classification system, the EU taxonomy aims to define 

which conditions economic activities can be declared sustainable

Especially for large investors, banks and insurance companies, and increasingly for other companies as well, public reporting requirements apply to their activities regarding sustainability. The idea behind this: The 

EU taxonomy creates incentives for a sustainable transformation of the economy.

Six environmental objectives in the focus of EU taxonomy

For several years, stakeholders from various working groups and institutions at the EU level have been developing the EU taxonomy. These include, for example, the 

activities must be aligned with the EU’s six environmental goals to be included in the taxonomy

 in the EU taxonomy is a way for funders and companies to be able to 

declare financing or economic activity in the relevant area as sustainable

Firstly, however, the taxonomy has a signal and orientation effect. 

In no way does the taxonomy imply general governmental or EU-wide financing or subsidies of the technologies included.

What is the deal with the inclusion of nuclear power and natural gas?

 to the governments of the member states. In this draft, the Commission 

also included nuclear power and natural gas

, which have long been controversial technologies. A version of the proposals can be found 

, partly so that the French energy company EDF can invest in its power plants. Meanwhile, at the 

 inclusion of gas-fired power plants is preferred

However, the “Ampelkoalition” (coalition formed by the German parties SPD, FDP and Green Party) disagrees on this. Likewise, Federal Minister of Economy and Environment Habeck rejects the current proposal. Many see the

 inclusion of the two forms of energy as a compromise between France and Germany.

Taxonomy and the power generation structure at EU level

In order to understand the discussion around the taxonomy in terms of the energy industry, we will now have a look at the power generation structure at the EU level. 

 shows the European electricity mix for 2021.

 have been the two technologies with the 

highest electricity generation at EU level

 for the past five years. In 2021, for example, nearly 27 percent of the EU’s electricity came from nuclear power plants and 17 percent from natural gas.

Above all, these existing dependencies of electricity generation on nuclear power and natural gas in the EU countries lead to its classification as a sustainable technology. In addition, the political balance of power contributes to this.

It is therefore not surprising that at the EU level, the technologies currently still generating the most electricity are favored in the respective countries. The 

 of nuclear power and natural gas in the EU taxonomy 

many countries were already relying on nuclear power

 to mitigate greenhouse gases before the taxonomy. For example, expansion is planned or envisaged not only in France, but also in Romania, Bulgaria, the Netherlands, Poland and Estonia.

 shows the share of electricity generation from nuclear power in the 13 EU countries with nuclear power plants in 2020. Clearly visible is the high share of over 30 percent in many EU member states.

According to the EU Commission’s draft, 

nuclear power plants should only be sustainable

The funds must have sufficient financial resources. The above conditions for classification should 

also apply to nuclear power plants whose operating lives are extended

. Furthermore, the political level must approve continued operation until 2040.

Only nuclear power plants whose operating lives are extended after 2025 must also have a 

. Here, too, the differences between countries are large. Gas-fired power plants account for a particularly high share of electricity generation in Belgium, Greece, Ireland, Italy, Latvia, Lithuania, Portugal and the Netherlands – i. e. primarily in countries that do not have a high level of generation from nuclear power.

 makes this clear. It shows the share of electricity from gas-fired power plants in the 13 countries with the highest shares in 2020. 

 after the phase-out of nuclear power and with an accelerated coal phase-out.

In general, gas-fired power plants must have greenhouse gas emissions less 100 g CO2/kWh. This limit would probably only be achievable with CO2 capture and storage.

Exemptions for gas-fired power plants with planning permission until 2030

For gas-fired power plants that receive a building permit by December 31, 2030, less restrictive regulations apply in order to be classified as sustainable. 

Here, there are still two options for gas-fired power plants

direct greenhouse gas emissions must be below 270 g CO2/kWh

 for power generation. Highly efficient cogeneration plants can fulfill this condition. For normal gas and steam power plants, the value is generally between 300 and 350 g CO2/kWh.

not emit more than an average of 550 kg CO2/kW per year over 20 years

. This would mean that power plants would have to reduce the number of hours they operate per year. In addition, they would only be allowed to produce electricity during high-load phases or when generation from renewables is low. 

 that receive a permit by the end of December 2030 

cannot yet be efficiently produced by renewables

replaces an existing plant with higher emissions

plant is capable of co-firing low-CO2 and renewable fuels

 and the share of these fuels is at least 30 percent from 2026, at least 55 percent from 2030, and as much as 100 percent from 2036, and

 in the country concerned and laid down in an official plan.

Environmental associations and individual countries have already strongly criticized the new regulations.

 Austria even wants to file a lawsuit against the inclusion of the two energy sources in the EU taxonomy. Energy industry players 

 that enough low-CO2 or renewable fuels will be available for the gas-fired power plants. However, 

major investors and donors, through the IIGCC

 (Institutional Investors Group on Climate Change),

in the taxonomy in an open letter to the EU.

On a political level, the EU Commission wanted to consult the draft with the member states first by 12th of January 2022. MEPs have extended this deadline until 

Commission will present the final proposal

The Council of Member States or the EU Parliament can still veto the proposal

 within four months before it becomes binding for all EU countries.

20 EU states representing at least 65 percent

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Simon Göß

Simon Göß

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