Our most important findings

The key strategies to achieve such an accelerated steel transformation are material efficiency, an increase of scrap- and hydrogen-based steelmaking plus bioenergy and carbon capture and storage (BECCS).

Transporting embodied hydrogen (H₂) as green iron will be significantly cheaper than transporting H₂ and its derivatives by ship. For countries with high renewable H₂ costs, green iron imports can increase the competitiveness of low-carbon steelmaking, thereby helping to safeguard local jobs in the steel industry. For green iron exporters, this can create new jobs and value added.

CCS on the BF-BOF route is unlikely to reduce direct CO₂ emissions beyond 73% and cannot address upstream emissions (coal mine methane leakage). Compared to other key technologies, steelmakers’ efforts to commercialise this technology are currently very low. If BF-BOF CCS does not materialise, new coal-based steel plants face a high carbon lock-in and stranded asset risk.

International cooperation will be needed to address key bottlenecks (i.e. DRI plant engineering, suitable iron ore qualities, low-carbon H₂), minimise stranded assets and help to unlock green iron trade.

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.

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.

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.

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.

Heavy reliance on fossil gas in fertiliser production makes the industry carbon-intensive and vulnerable to price shocks as seen currently.

Producing fertilisers with renewable energy instead of fossil fuels would help reduce greenhouse gas emissions and increase the sector’s resilience. However, the price gap between fossil and renewable hydrogen is a key challenge for Argentina to scale up green ammonia production.

Argentina could build up its ammonia production capacity using the existing natural gas reserves, while developing its vast renewable hydrogen potential in order to switch to green ammonia as fast as possible. This could create jobs, reinforce food security, and help to the decarbonise industry.

International support and investment can help to overcome economic challenges in the production of green ammonia, guaranteeing a sustainable development of Argentina’s industrial sector. Countries worldwide could benefit from a more diversified fertiliser supply chain.

Argentina’s national hydrogen strategy, currently being drafted, should prioritise the use of hydrogen in key sectors such as industry, ship­ping, and aviation, and in providing flexibility to a renewable-based power system. For other use cases, direct electrification is usually more economic and efficient.

Argentina’s renewable energy resources can produce cheap electricity that can be con­verted into renewable hydrogen. Natural gas with carbon capture and storage could be used as a bridge technology but should be switched to renewable hydrogen as soon as possible.

Hydrogen can enable the production of green products with a high export demand potential, such as ammonia, fertilisers, and synthetic fuels. Scaling up the production of these products would stimulate sustainable industrial growth and contribute to economic diversification and job creation.

Renewable hydrogen production in Argentina can greatly benefit global decarbonisation and it would therefore be in the interest of the international community to support the expansion of the country’s infrastructure and industrial development. Regional cooperation would also strengthen Latin America's position as hydrogen producer in international fora on standards and trade.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Klimaschutzverträge nach dem Vorbild der Carbon Contracts for Difference (CCfD) erlauben einen raschen Einstieg in die notwendigen Investitionen und sichern die Mehrkosten einer klimafreundlichen Produktion ab.

Klimaschutzverträge dienen somit auch als Absicherungsinstrument für die anfängliche Auslastung von strategisch wichtigen Infrastrukturen, ohne die Klimaneutralität nicht erreicht werden kann.

Zur Finanzierung kommen eine Kombination aus existierenden Förderinstrumenten mit Garantien durch den Bundeshaushalt oder den Energie- und Klimafonds in Frage.

Über die Reform des EU-Emissionshandels, der Instrumente zum Carbon-Leakage-Schutz sowie den Aufbau von grünen Leitmärkten können Klimaschutzverträge abgelöst und klimafreundliche Produkte als Standard am Markt etabliert werden.

Zudem muss der Einsatz von Zement über Materialeffizienz und Substitution gemindert werden. So wird die Zementproduktion in Deutschland zukunftsfähig.

In enger Zusammenarbeit mit europäischen Partnern müssen dafür der nationale und europäische Rechtsrahmen für die CO2-Speicherung aufgebaut werden.

Durch den Einsatz von nachhaltiger Biomasse und biogenen Reststoffen in der CCS-basierten Zementproduktion (BECCS) können darüber hinaus kostengünstige CO2-Senkeneffekte erzielt werden.

Klimaschutzverträge sind kurzfristig zentral, um Investitionen abzusichern, höhere Kosten können jedoch mithilfe einer EU-EHS-Reform, eines Grenzausgleichsmechanismus (CBAM) und dem Aufbau von grünen Leitmärkten für CO2-armen Zement kompensiert werden.

By compensating for the initially higher costs of climate-friendly production, carbon contracts anticipate the effects of evolving carbon pricing and enable the industry to implement its green investment plans.

Carbon contracts support this transformation. If appropriately coordinated with other policy measures, the need for financial support is limited to less than 9 billion euros, and green steel can be cost-competitive by 2035.

Running them initially on natural gas will enable a rapid reduction in CO2 emissions and provides a back-up for the use of increasing volumes of renewable hydrogen.

Alongside the rapid implementation of carbon contracts, the EU ETS must be reformed and green lead markets developed so that climate-friendly steel can establish itself as the industry standard.

In Kombination mit dem Ausbau der Sekundärstahlroute eröffnet sich ein Pfad zum Aufbau einer ressourceneffizienten, klimaneutralen und unabhängigen Stahlproduktion in Deutschland.

Parallel müssen das EU-Emissionshandelssystem reformiert und grüne Leitmärkte aufgebaut werden, damit klimafreundlicher Stahl am Markt honoriert wird und sich als Standard durchsetzen kann.

Durch eine intelligente Kombination von Politikinstrumenten auf nationaler und europäischer Ebene kann grüner Stahl bereits 2035 wettbewerbsfähig sein.

Der anfängliche Betrieb der Anlagen mit Erdgas bleibt trotz hoher Preise sinnvoll, um einen raschen Ausbau der Wasserstoffwirtschaft abzusichern.

Dazu kommt der Ausbau der Stahl-Sekundärroute als wesentlicher Baustein für eine klimaneutrale Stahlproduktion. So wird die Stahlbranche in Deutschland zukunftsfähig.

Über den Betrieb mit Erdgas wird ein Großteil der CO₂-Emissionen schnell zu moderaten Kosten reduziert, bis Erdgas durch ein steigendes Angebot an erneuerbarem Wasserstoff ersetzt wird.

Ziel ist es auch, parallel grüne Leitmärkte aufzubauen, die den Mehrwert von klimaneutralem Stahl honorieren und ihn als Standard am Markt etablieren.

Dafür benötigen sie einen eigenen dauerhaften Refinanzierungsmechanismus, damit die Branche Investitionssicherheit erhält.

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

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

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

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

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

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

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

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

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

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.

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.

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.

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).

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.

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.

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.

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).

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.

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.

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.

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).

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.

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

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.

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.

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

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

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

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

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

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

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

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

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.

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).

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.

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.

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.

(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.

...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.

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.

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.