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.

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.

Laut Nationaler Wasserstoffstrategie werden ab 2030 Einfuhren von mindestens 45 TWh Wasserstoff pro Jahr benötigt. Zusätzlich zu Pipeline-Importen können andere Wasserstoffträger auch per Schiff importiert werden.

Beim Import von Wasserstoffträgern per Schiff erhöhen sich die Transportkosten nach Rückumwandlung auf etwa 2 bis 5 €/kg H₂. Wasserstoffderivate wie Ammoniak oder brikettierter Eisenschwamm (HBI), die direkt weiterverarbeitet werden können, stellen vielfach eine kosteneffektive Alternative dar (< 1,5 €/kg H₂). Technologische Innovationen sind eine entscheidende Voraussetzung für alle Importoptionen, mit Ausnahme von Wasserstoff-Pipelines und Ammoniak zur direkten Nutzung.

(1) einem komplexen Wechsel­spiel mehrerer Komponenten mit vergleichsweise niedrigem Technologie-Reifegrad und einer Umsetzungszeit von zehn Jahren; (2) dem Wettbewerb mit anderen Import-Optionen, die SNG mittelfristig preislich unterbieten können; (3) regulatorischer Unsicherheit hinsichtlich der Messung, Berichterstattung und Überprüfung internationaler Kohlenstoffströme.

Angesichts ihrer kritischen Bedeutung sollte der Fokus in Deutschland auf der Umrüstung zu und dem Bau von Wasserstoffpipelines liegen. Die Schaffung neuer CO₂-Infrastruktur sollte sich auf No-regret-CCS-Anwendungen konzentrieren.

As long as green hydrogen requires public support to be economically competitive, policymakers need transparent estimates of the levelised cost of hydrogen to guide them in designing support schemes. Key drivers are the assumed electricity costs, the number of full-load hours, the cost of capital and the investment costs for electrolysers.

For example, most widely-cited German energy scenarios expect electrolysers to run ~3 000 full-load hours in 2030, corresponding to a ~34 percent utilisation rate, which is expected to gradually increase up to 2045. The lower the number of full-load hours, the greater the proportional significance of electrolysis investment costs becomes.

The price for electrolyser systems in the EU today is still generally high (significantly above 1 000 Euro/kW), although it is projected to fall considerably in the future.

Other potentially important but non-fundamental cost drivers, such as project financing or tax credits, should generally not be factored in unless explicitly included. While simplified cost estimates are appropriate for high-level studies, their practicality depends on a sufficient degree of consistency and transparency regarding system boundaries and cost drivers.

These applications include steel, ammonia and basic chemicals production in the industrial sector, as well as long-haul aviation and maritime shipping. The power sector needs long-term storage to accommodate variable renewables, and existing district heating systems may require hydrogen to meet residual heat load. Accordingly, renewable hydrogen needs to be channelled into these no-regret applications.

While renewable electricity (the main cost component of renewable hydrogen) is already on track to become cheaper, electrolyser system costs also need to be reduced. Cheaper electrolysers will come through economies of scale and learning-by-doing effects; however, predictable and stable hydrogen demand is prerequisite for electrolyser manufacturers to expand production and improve the technology.

Even at CO₂ prices of €100 to 200/tonne, the EU ETS will not sufficiently incentivise renewable hydrogen production, making additional policy support necessary for a considerable period of time. Among potential policy options, a general usage quota for renewable hydrogen would not be sufficiently targeted to induce adoption in the most important applications.

Several policy instruments should be deployed in concert to achieve this aim – namely, carbon contracts for difference in industry; a quota for aviation; auctions to support combined heat and power plants; measures to encourage markets for decarbonised materials; and hydrogen supply contracts. These instruments will also need to be complemented by regulations that ensure sustainability, appropriate infrastructure investment, system integration, and rapid renewables growth.

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.

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

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

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

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

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.