Our most important findings

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.

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

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

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

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

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

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

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

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

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

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

Ansonsten ist zu erwarten, dass Ladeinfrastruktur nur in Netzen mit günstigen Anschluss- und fixen Netzbetriebskosten entsteht und für bestimmte Gebiete möglicherweise gar keine Angebote eintreffen. Um das Problem zu lösen, sind zwei Ansätze denkbar: Der Bund sollte entweder verschiedene Netze mit unterschiedlichen Netzkosten in einem Los zusammenlegen oder befristet einen Teil der Netzkosten übernehmen.

Die momentanen Leistungspreise bemessen sich im Regelfall an der Spitzenleistung, unabhängig davon, ob ein Fahrzeug oder sehr viele Fahrzeuge geladen werden. Dies ist nicht sachgerecht, weswegen auch in anderen EU-Ländern die Leistungspreise für Ladeinfrastruktur angepasst werden.

Mittelfristig ist eine an den tatsächlichen Netzausbaukosten angenäherte Entgeltstruktur zu erarbeiten, die weniger auf Jahresleistungspreise abstellt. Die Netzentgelte, gerade auch für das Laden von Elektro-Autos, sollten stärker an den langfristigen Systemkosten und weniger an einer lokalen Situation oder suggerierten Verursachungsgerechtigkeit ausgerichtet werden.

Grid-friendly charging reduces the peak loads created when vehicles and electric heat pumps are charged simultaneously. It can also shift electricity consumption to times with abundant generation from solar photovoltaics and wind turbines.

Without the mobility transition, annual investments of 2.1 billion euros would be needed to accommodate 45 million, instead of 30 million, electric cars.

Electric mobility increases electricity sales, while the overall investment needed for power lines and transformers does not increase. However, it is important that the participants in the mobility transition pay their fair share of grid fees.

To achieve this, grid-friendly managed charging must become the standard. We need secure information and communications technologies, incentives and, if necessary, obligatory managed charging. Precautionary indirect control, in the form of incentives for grid-friendly charging, should take precedence over direct control by the distribution grid operator.

Netzdienliches Laden reduziert Lastspitzen durch gleichzeitig ladende Fahrzeuge und elektrische Wärmepumpen. Außerdem verlagert es Verbrauch in Zeiten mit hohen Einspeisespitzen durch Sonnen- und Windenergieanlagen.

Ohne Mobilitätswende, mit 45 statt 30 Mio. Elektro-Pkw, betragen die jährlichen Investitionen 2,1 Mrd. Euro.

Allerdings muss die Elektromobilität angemessen an der Zahlung der Netzentgelte beteiligt werden.

Hierfür muss netzdienliche Ladesteuerung zum Standard werden. Es braucht sichere Informations- und Kommunikationstechnologie, Anreize und gegebenenfalls Verpflichtungen zur Steuerbarkeit. Präventive, indirekte Steuerung über Anreize zum netzdienlichen Laden sollten Vorrang vor direkter Steuerung durch den Verteilnetzbetreiber haben.

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).

By 2030, renewables will account for 55% of power generation in Europe, and 50% of power generation in SEE. Nearly 70% of renewable power in SEE will stem from wind and solar, given the excellent resource potential of these renewables in the region.

For example, wind generation can fluctuate from one hour to the next by up to 47% in Romania, whereas the comparable figure for Europe is just 6%. Moving from national to regional balancing substantially lowers national flexibility needs. Increased cross-border interconnections and regional cooperation are thus essential for integrating higher levels of wind and PV generation.

Accordingly, conventional power plants will need to flexibly mirror renewables generation: When renewables output is high, conventionals produce less, and when renewables output is low, fossil power plants increase production. Flexible operations will become an important aspect of power plant business models.

The available reserve capacity margin in SEE will remain above 35% in 2030. More interconnectors, market integration and regional cooperation will be key factors for maximising national security of supply and minimising power system costs. SEE can be an important player in European power markets by providing flexibility services to CEE in years of high hydro availability.

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

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

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

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

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

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

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

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

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

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

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

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