Germany

Alkaline water electrolysis is a key technology for large-scale hydrogen production. In this process safety and efficiency are among the most essential requirements. Hence optimization strategies must consider both aspects. While experimental optimization studies are the most accurate solution model-based approaches are more cost and time-efficient. However validated process models are needed which consider all important influences and effects of complete alkaline water electrolysis systems. This study presents a dynamic process model for a pressurized alkaline water electrolyzer consisting of four submodels to describe the system behavior regarding gas contamination electrolyte concentration cell potential and temperature. Experimental data from a lab-scale alkaline water electrolysis system was used to validate the model which could then be used to analyze and optimize pressurized alkaline water electrolysis. While steady-state and dynamic solutions were analyzed for typical operating conditions to determine the influence of the process variables a dynamic optimization study was carried out to optimize an electrolyte flow mode switching pattern. Moreover the simulation results could help to understand the impact of each process variable and to develop intelligent concepts for process optimization

A key building block of the European Green Deal is the development of a hydrogen commodity market which requires a suitable hydrogen market design and the timely introduction of related policy measures. Using exploratory interviews with five expert groups we contribute to this novel research field by outlining the core market design criteria and proposing suitable regulations for the future European hydrogen market. We identify detailed recommendations along three core market design focus areas: Market development policy measures infrastructure regulations as well as hydrogen and certificate trading. Our findings provide an across-industry view of current policy-related key challenges in the hydrogen commodity market development and mitigation approaches. We therefore support policymakers within the EU in the ongoing detailing of their regulatory hydrogen and green energy packages. Further we promote hydrogen market development by assisting current and future industry players in finding a common understanding of the future hydrogen market design.

In a future energy generation market the storage of energy is going to become increasingly important. Besides classic ways of storage like pumped storage hydro power stations etc the production of hydrogen will play an important role as an energy storage system. Hydrogen may be stored as a liquefied gas (LH2) on a long term base as well as for short term supply of fuel stations to ensure a so called “green” mobility. The handling with LH2 has been subject to several recent safety studies. In this context reliable simulation tools are necessary to predict the spill and spreading of LH2 during an accidental release. This paper deals with the different boiling regimes: film boiling transition boiling and nucleation boiling after a release and their modeling by means of an inhouse-code for wall evaporation which is implemented in the commercial CFD code ANSYS CFX. The paper will describe the model its implementation and validation against experimental data such as the HSL LH2 spill experiments.

This paper aims to provide a holistic analysis of the role of hydrogen for achieving greenhouse gas neutrality in Germany. For that purpose we apply an integrated energy system model which includes all demand sectors of the German energy system and optimizes the transformation pathway from today's energy system to a future cost-optimal energy system. We show that 412 TWh of hydrogen are needed in the year 2045 mostly in the industry and transport sector. Particularly the use of about 267 TWh of hydrogen in industry is essential as there are no cost-effective alternatives for the required emission reduction in the chemical industry or in steel production. Furthermore we illustrate that the German hydrogen supply in the year 2045 requires both an expansion of domestic electrolyzer capacity to 71 GWH2 and hydrogen imports from other European countries and Northern Africa of about 196 TWh. Moreover flexible operation of electrolyzers is cost-optimal and crucial for balancing the intermittent nature of volatile renewable energy sources. Additionally a conducted sensitivity analysis shows that full domestic hydrogen supply in Germany is possible but requires an electrolyzer capacity of 111 GWH2.

There are a large number of applications in which hydrogen internal combustion engines represent a sensible alternative to battery electric propulsion systems and to fuel cell electric propulsion systems. The main advantages of combustion engines are their high degree of robustness and low manufacturing costs. No critical raw materials are required for production and there are highly developed production plants worldwide. A CO2-free operation is possible when using hydrogen as a fuel. The formation of nitrogen oxides during hydrogen combustion in the engine can be effectively mitigated by a lean-burn combustion process. However achieving low NOx raw emissions conflicts with achieving high power yields. In this work a series industrial diesel engine was converted for hydrogen operation and comprehensive engine tests were carried out. Various measures to improve the trade-off between NOx emissions and performance were investigated and evaluated. The rated power output and the maximum torque of the series diesel engine could be exceeded while maintaining an indicated specific NOx emission of 1 g/kWh along the entire full load curve. In the low-end-torque range however the gap to the full load curve of the series diesel engine could not be fully closed with the hardware used.

The intermittent production of the renewable energy imposes the necessity to temporarily store it. Large amounts of exceeding electricity can be stored in geological strata in the form of hydrogen. The conversion of hydrogen to electricity and vice versa can be performed in electrolyzers and fuel elements by chemical methods. The nowadays technical solution accepted by the European industry consists of injecting small concentrations of hydrogen in the existing storages of natural gas. The progressive development of this technology will finally lead to the creation of underground storages of pure hydrogen. Due to the low viscosity and low density of hydrogen it is expected that the problem of an unstable displacement including viscous fingering and gravity overriding will be more pronounced. Additionally the injection of hydrogen in geological strata could encounter chemical reactivity induced by various species of microorganisms that consume hydrogen for their metabolism. One of the products of such reactions is methane produced from Sabatier reaction between H2 and CO2. Other hydrogenotrophic reactions could be caused by acetogenic archaea sulfate-reducing bacteria and iron-reducing bacteria. In the present paper a mathematical model is presented which is capable to reflect the coupled hydrodynamic and bio-chemical processes in UHS. The model has been numerically implemented by using the open source code DuMuX developed by the University of Stuttgart. The obtained bio-chemical version of DuMuX was used to model the evolution of a hypothetical underground storage of hydrogen. We have revealed that the behavior of an underground hydrogen storage is different than that of a natural gas storage. Both the hydrodynamic and the bio-chemical effects contribute to the different characteristics.

Subsurface porous media hydrogen storage could be a viable option to mitigate shortages in energy supply from renewable sources. In this work a scenario for such a storage is developed and the operation is simulated using a numerical model. A hypothetical storage site is developed based on an actual geological structure. The results of the simulations show that the storage can supply about 20 % of the average demand in electrical energy of the state of Schleswig-Holstein Germany for a week-long period.

Germany the European Union member state with the largest fiscal space and its leading manufacturer of industrial goods is pursuing an ambitious hydrogen strategy aiming at establishing itself as a major technology provider and importer of green hydrogen. The success of its hydrogen strategy represents not only a key element in realizing the European vision of climate neutrality but also a central driver of an emerging global hydrogen economy. This article provides a detailed review of German policy highlighting its prominent international dimension and its implications for the development of a global renewable hydrogen economy. It provides an overview of the strategy’s central goals and how these have evolved since the launch of the strategy in 2020. Next it moves on to provide an overview of the strategy’s main areas of intervention and highlights corresponding policy instruments. For this we draw on a comprehensive assessment of hydrogen policy instruments which have been systematically analyzed and coded. This was complemented by a detailed analysis of policy documents and information gathered in six interviews with government officials and staff of key implementing agencies. The article places particular emphasis on the strategy’s international dimension. While less significant in financial terms than domestic hydrogen-related spending it represents a defining feature of the German hydrogen strategy setting it apart from strategies in other major economies. The article closes with a reflection on the key features of the strategy compared to other important countries identifies gaps of the strategy and discusses important avenues for future research.

Green hydrogen promises to be critical in achieving a sustainable and renewable energy transition. As green hydrogen is produced with renewables green hydrogen could become an energy storage medium of the future and even substitute the current unsustainable grey or blue hydrogen used in the industry. Bringing this transition into reality for instance in Germany there are visions to rapidly build hydrogen facilities in Africa and export the produced green hydrogen to Europe. One problem however is that these visions presumably conflict with the visions of actors within Africa. Therefore this study aims to provide an initial assessment of African stakeholders’ visions for future energy exports and renewable energy expectations. By comparing visions from Germany and Africa this assessment was conducted to identify differences in green energy and hydrogen visions that could lead to conflict and similarities that could be the basis for cooperation. The National Hydrogen Strategy outlines the German visions which clarifies that Germany will have to import green hydrogen to meet its green transition target. In this context of future energy export demand a partnership between German and African researchers on assessing green hydrogen potentials in Africa started. The African visions were explored by surveying the partners from different African countries working on the project. The results revealed that while both sides see the need for an immediate transition to renewable energy the African side is not envisioning the immediate export of green hydrogen. Based on the responses the partners are primarily concerned with improving the continent’s still deficient energy access for both the population and industry. Nevertheless this African perspective greatly emphasises cross-border cooperation where both sides can realise their visions. In the case of Germany that German investment could build infrastructure which would benefit the receiving African country or countries and open up the possibility for the envisioned green hydrogen export to Europe.

Aviation contributes to anthropogenic climate change by emitting both carbon dioxide (CO2) and non-CO2 emissions through the combustion of fossil fuels. One approach to reduce the climate impact of aviation is the use of hydrogen as an alternative fuel. Two distinct technological options are presently under consideration for the implementation of hydrogen in aviation: hydrogen fuel cell architectures and the direct combustion of hydrogen. In this study a hydrogen demand model is developed that considers anticipated advancements in liquid hydrogen aircraft technologies forecasted aviation demand and aircraft startup and retirement cycles. The analysis indicates that global demand for liquid hydrogen in aviation could potentially reach 17 million tons by 2050 leading to a 9% reduction in CO2 emissions from global aviation. Thus the total potential of hydrogen in aviation extends beyond this considering that the total market share of hydrogen aircraft on suitable routes in the model is projected to be only 27% in 2050 due to aircraft retirement cycles. Additionally it is shown that achieving the potential demand for hydrogen in aviation depends on specific market prices. With anticipated declines in current production costs hydrogen fuel costs would need to reach about 70 EUR/MWh by 2050 to fulfill full demand in aviation assuming biofuels provide the cheapest option for decarbonization alongside hydrogen. If e-fuels are the sole option for decarbonization alongside hydrogen which is the more probable scenario the entire hydrogen demand potential in aviation would be satisfied according to this study’s estimates at significantly higher hydrogen prices approximately 180 EUR/MWh.

Hydrogen is a promising energy carrier for decarbonizing maritime and stationary applications. However using 100% hydrogen in large-bore engines introduces combustion challenges such as pre-ignition and backfire. These statistically occurring combustion anomalies particularly their spatial and temporal behavior cannot be fully understood through thermodynamic data alone. This study applies optical diagnostics to a medium-speed single-cylinder research engine (bore: 350 mm stroke: 440 mm displacement: 42.3 dm3 ) operated with 100% hydrogen exceeding 20 bar IMEP. By varying the air–fuel equivalence ratio between 2.3 and 4.0 and comparing active pre-chamber and open combustion chamber ignition systems backfire-induced operating limits are identified. High-speed flame imaging through two endoscopic accesses and up to three cameras captures both visible and UV (308 nm) flame chemiluminescence. An implemented visual vibration compensation method using fiber optics enables tracking of flame origins and propagation. The recordings show that 65% of ignition events initiate near one intake valve suggesting local hydrogen enrichment confirmed via 3D-CFD simulations. This is linked to intake manifold geometry which leads to mixture inhomogeneity up to −260◦ CA BTDC. At loads above 15 bar IMEP the localized enrichment reduces or shifts attributed to increased turbulence and intake mass flow. CFD simulations also reveal that gas temperatures under the intake valves exceeding the ignition temperature of hydrogen as early as 300◦ CA BTDC create the risk of backfire in the early gas phase. Additionally glowing oil droplets and ignition zones near the piston were observed indicating that lube oil ignition may be a cause of later (after −290◦ CA BTDC) backfire events. These findings contribute to the understanding of hydrogen combustion anomalies and support future experimental and modeling-based optimization of large-bore hydrogen engines.

Green hydrogen is gaining global attention as a zero-carbon energy carrier with the potential to drive sustainable energy transitions particularly in regions facing rising fossil fuel costs and resource depletion. In sub-Saharan Africa financing mechanisms and structured off-take agreements are critical to attracting investment across the green hydrogen value chain from advisory and pilot stages to full-scale deployment. While substantial funding is required to support a green economic transition success will depend on the effective mobilization of capital through smart public policies and innovative financial instruments. This review evaluates financing mechanisms relevant to sub-Saharan Africa including green bonds public–private partnerships foreign direct investment venture capital grants and loans multilateral and bilateral funding and government subsidies. Despite their potential current capital flows remain insufficient and must be significantly scaled up to meet green energy transition targets. This study employs a mixed-methods approach drawing on primary data from utility firms under the H2Atlas-Africa project and secondary data from international organizations and the peer-reviewed literature. The analysis identifies that transitioning toward Net-Zero emissions economies through hydrogen development in sub-Saharan Africa presents both significant opportunities and measurable risks. Specifically the results indicate an estimated investment risk factor of 35% reflecting potential challenges such as financing infrastructure and policy readiness. Nevertheless the findings underscore that green hydrogen is a viable alternative to fossil fuels in subSaharan Africa particularly if supported by targeted financing strategies and robust policy frameworks. This study offers practical insights for policymakers financial institutions and development partners seeking to structure bankable projects and accelerate green hydrogen adoption across the region.

This study examines the economic and regulatory implications of the development of Germany’s hydrogen core network. Using a mathematical-economic model of the amortization account and a reproduction of the network topology based on the German transmission system operators’ draft proposals the analysis evaluates the impact of delaying the network expansion with completion postponed from 2032 to 2037. The proposed phased approach prioritizes geographically clustered regions and ensures sufficient demand alignment during each expansion stage. The results demonstrate that strategic adjustments to the network size and timing significantly enhance cost-efficiency. In the initially reduced and delayed scenario uncapped network tariffs remain below €15/ kWh/h/a suggesting that under specific conditions the amortization account may become redundant while maintaining supply security and supporting the market ramp-up of hydrogen. These findings highlight the potential for demand-driven phased hydrogen infrastructure development to reduce financial burdens and foster a sustainable transition to a hydrogen-based energy system.

Liquid hydrogen (LH2) is a promising energy carrier to decrease the climate impact of aviation. However the inevitable formation of hydrogen boil-off gas (BOG) is a main drawback of LH2. As the venting of BOG reduces the overall efficiency and implies a safety risk at the airport means for capturing and re-using should be implemented. Metal hydrides (MHs) offer promising approaches for BOG recovery as they can directly absorb the BOG at ambient pressures and temperatures. Hence this study elaborates a design concept for such an MH-based BOG recovery system at hydrogen-ready airports. The conceptual design involves the following process steps: identify the requirements establish a functional structure determine working principles and combine the working principles to generate a promising solution.

The Middle East and North Africa region has not played a major role in climate action so far and several countries depend economically on fossil fuel exports. However this is a region with vast solar energy resources which can be exploited affordably for power generation and hydrogen production at scale to eventually reach carbon neutrality. In this paper we elaborate on the case of the United Arab Emirates and explore the aspirations and feasibility of its net-zero by 2050 target. While we affirm the concept per se we also highlight the technological complexity and economic dimensions that accompany such transformation. We expect the UAE’s electricity demand to triple between today and 2050 and the annual green hydrogen production is expected to reach 3.5 Mt accounting for over 40% of the electricity consumption. Green hydrogen will provide power-to-fuel solutions for aviation maritime transport and hard-to-abate industries. At the same time electrification will intensify—most importantly in road transport and low-temperature heat demands. The UAE can meet its future electricity demands primarily with solar power followed by natural gas power plants with carbon capture utilization and storage while the role of nuclear power in the long term is unclear at this stage.

Green hydrogen is a promising solution within carbon free energy systems with Sub-Saharan Africa being a possibly well-suited candidate for its production. However green hydrogen production in Sub-Saharan Africa is not yet investigated in detail. This work determines the cost-potential for green hydrogen production within this region. Therefore a potential analysis for PV wind and hydropower groundwater analysis and energy systems optimization are conducted. The results are evaluated under local socio-economic factors. Results show that hydrogen costs start at 1.6 EUR/kg in Mauritania with a total potential of ~259 TWh/a under 2 EUR/kg in 2050. Two third of the region experience groundwater limitations and need desalination at an added costs of ~1% of hydrogen costs. Socio-economic analysis show that green hydrogen deployment can be hindered along the Upper Guinea Coast and the African Great Lakes driven by limited energy access low labor costs in West Africa and high labor potential in other regions.

With green hydrogen gaining traction as a viable sustainable energyoption the present study explores the potential of producing greenhydrogen from wind and solar energy in Ghana. The study combinedthe use of geospatial multi-criteria approach and PEM electrolysisprocess to estimate the geographical and technical potential of theselected two renewable resources. The study also included anassessment of potential areas for grid integration. Technologyspecifications of a monocrystalline solar PV module and 1 MW windturbine module were applied. Results of the assessment show thatabout 85% of the total land area in the country is available for greenhydrogen projects. Technically capacities of ∼14196.21 Mt of greenhydrogen using solar and ∼10123.36 Mt/year from wind energy can beproduced annually in the country. It was also observed that someregions especially regions in the northern part of the country eventhough showed the most favourable locations for solar-based greenhydrogen projects with technical potential of over 1500 Mt/year theseregions may not qualify for a grid connected system based on thecurrent electrification policy of the country due to the regions’ lowpopulation density and distance from the power grid network threshold.

Conventional hydrogen production processes which often involve fossil raw materials emit significant amounts of carbon dioxide into the atmosphere. This study critically evaluates the feasibility of using sugarcane biomass as an energy source to produce green hydrogen. In the 2023/2024 harvest Brazil the world’s largest sugarcane producer processed approximately 713.2 million metric tons of sugarcane. This yielded 45.68 million metric tons of sugar and 29.69 billion liters of first-generation ethanol equivalent to approximately 0.0416 liters of ethanol per kilogram of sugarcane. A systematic literature review was conducted using Scopus and Clarivate Analytics Web of Science resulting in the assessment of 335 articles. The study has identified seven potential biohydrogen production methods including two direct approaches from second-generation ethanol and five from integrated bioenergy systems. Experimental data indicate that second-generation ethanol can yield 594 MJ per metric ton of biomass with additional energy recovery from lignin combustion (1705 MJ per metric ton). Moreover advances in electrocatalytic reforming and plasma-driven hydrogen production have demonstrated high conversion efficiencies addressing key technical barriers. The results highlight Brazil’s strategic potential to integrate biohydrogen production within its existing bioenergy infrastructure. By leveraging sugarcane biomass for green hydrogen the country can contribute significantly to the global transition to sustainable energy while enhancing its energy security.

As global demand for green hydrogen rises potential hydrogen exporters move into the spotlight. While exports can bring countries revenue large-scale on-grid hydrogen electrolysis for export can profoundly impact domestic energy prices and energy-related emissions. Our investigation explores the interplay of hydrogen exports domestic energy transition and temporal hydrogen regulation employing a sector-coupled energy model in Morocco. We find substantial co-benefits of domestic carbon dioxide mitigation and hydrogen exports whereby exports can reduce market-based costs for domestic electricity consumers while mitigation reduces costs for hydrogen exporters. However increasing hydrogen exports in a fossil-dominated system can substantially raise market-based costs for domestic electricity consumers but surprisingly temporal matching of hydrogen production can lower these costs by up to 31% with minimal impact on exporters. Here we show that this policy instrument can steer the welfare (re-)distribution between hydrogen exporting firms hydrogen importers and domestic electricity consumers and hereby increases acceptance among actors.

The ongoing global energy transition spurred by ecological concerns and by evolving political dynamics is necessitating a significant expansion of renewable energy sources. This shift towards renewables is introducing the challenge of heightened energy supply volatility and it underscores the imperative for large-scale storage solutions in order to mitigate fluctuations in demand and supply. This study investigates the potential of Power-to-X (P2X) technologies to address this challenge and it evaluates their technical and socioeconomic implications. Using scenario simulations that leverage the maximum estimated potentials of renewable energy sources relative to demand profiles across different countries we explore the role of P2X integration in the enhancement of energy production. Our analysis highlights the pivotal role of hydrogen in the decarbonization of key industrial sectors such as steel production and heavyduty transportation in the near term. For Germany we observe a reduction in CO2 emissions from 306.26 Mt to 232.28 Mt (-24.15%) and an increase in energy independence as measured by the reduction in primary energy imports from 1150.37 TWh to 887.86 TWh (-22.82%) when comparing the baseline scenario to the most socio-economically favorable scenario. France demonstrates even greater reductions with CO2 emissions decreasing by 37.69% and primary energy imports by 40.46%. Portugal achieves similar reductions with CO2 emissions falling by 38.71% and primary energy imports by 41.81%. However none of the three countries investigated in this study (Germany France and Portugal) achieve full decarbonization and energy independence simultaneously since their respective potential for renewable energy is not sufficiently large. Drawing from these insights and accounting for the unique contexts of each of the three countries we offer tailored policy recommendations for optimizing P2X utilization and enhancing energy production efficiency.

Transitioning from fossil fuels to renewable energies is imperative for Germany to reduce CO2 emissions and achieve greenhouse gas neutrality by 2045. Green hydrogen holds great potential to contribute to this energy transition by enabling the storage of surplus renewable energy. However Germany's green hydrogen production industry is still in its infancy with only a few green hydrogen plants existing. Studies examining the public's acceptance of green hydrogen production are scarce in this context. Still high societal acceptance can contribute to the future expansion of green hydrogen production in Germany in terms of speed and volume. Therefore our study aims to identify significant factors influencing the German population's acceptance of green hydrogen production within various acceptance groups with differing preferences for future green hydrogen production systems. We conducted an online survey (n=1203) in Germany in 2022/2023 incorporating a choice experiment. Through subsequent latent class analysis four acceptance groups with distinct preferences regarding local green hydrogen production were identified: Unconvinced citizens Security-conscious citizens Regional electricity consumers and Financial beneficiaries. A discriminant analysis identified 9 out of 11 factors as significant for distinguishing between these acceptance groups regarding their preferences for local green hydrogen production: trust in plant safety trust in project managers risk/benefit perception environmental self-identity negative attitude towards renewable energies positive attitude towards renewable energies emotions age and gender. However no significant effects were observed for experience with green hydrogen and distance to the place of residence. Based on our results it is recommended that required renewable energy for green hydrogen production should be produced as close to the green hydrogen plants as possible. It must be ensured and communicated to the public that the (planned) green hydrogen plants meet high safety standards and pose a very low risk of fire or explosion. The neighbouring population should also benefit through annual heating cost savings and financial participation. Implementing these measures can increase acceptance of local green hydrogen production facilitating the transition towards a more sustainable energy future in Germany and beyond.

The share of renewable electricity generation has been growing steadily over the past few years. However not all sectors can be fully electrified to reach decarbonization goals. The maritime industry which plays a critical role in international trade is such a sector. Therefore there is a need for a global strategic approach towards the production transportation and use of synfuels enabling the maritime energy transition to benefit from economies of scale. There are potential locations around the world for renewable generation such as hydropower in Norway wind turbines in the North Sea and photovoltaics in the Sahara where synfuels can be produced and utilized within the country as well as exported to demand hubs. Given that a country's domestic production may not fully meet its demand a scenario-based analysis is essential to determine the feasibility of supply chains pillaring on the demand and supply for the respective sector of utilization. Our work demonstrates this methodology for the import of hydrogen and derived ammonia and methanol to Germany from Norway Namibia and Algeria in 2030 and 2050 utilizing the pipeline- and ship-based transport scenarios. Thereby the overall supply chain efficiency for maritime applications is analyzed based on the individual supply chain energy consumption from production to bunkering of the fuel to a vessel. The analysis showed that the efficiency of import varies from 44.6% to 53.9% between the analyzed countries. Furthermore a sensitivity analysis for green and blue hydrogen production pathways is presented along with the influence of qualitative factors like port infrastructure geopolitics etc. As an example through these analyses recommendations for supply from Norway Algeria and Namibia at the Port of Wilhelmshaven within a supply chain are examined.

This study evaluates the techno-economic feasibility of solar-based green hydrogen potential for off-grid and utility-scale systems in Niger. The geospatial approach is first employed to identify the area available for green hydrogen production based on environmental and socio-technical constraints. Second we evaluate the potential of green hydrogen production using a geographic information system (GIS) tool followed by an economic analysis of the levelized cost of hydrogen (LCOH) for alkaline and proton exchange membrane (PEM) water electrolyzers using fresh and desalinated water. The results show that the electricity generation potential is 311617 TWh/year and 353166 TWh/year for off-grid and utility-scale systems. The hydrogen potential using PEM (alkaline) water electrolyzers is calculated to be 5932 Mt/year and 6723 Mt/year (5694 Mt/year and 6454 Mt/year) for off-grid and utility-scale systems respectively. The LCOH production potential decreases for PEM and alkaline water electrolyzers by 2030 ranging between 4.72–5.99 EUR/kgH2 and 5.05–6.37 EUR/kgH2 for off-grid and 4.09–5.21 EUR/kgH2 and 4.22–5.4 EUR/kgH2 for utility-scale systems.

The transition to a renewable energy system based mainly on an electricity and hydrogen infrastructure places new requirements and constraints on the infrastructure systems involved. This study investigates the impact of future hydrogen storage demands on a representative salt cavern considering two cases: a regional focus on Lower Saxony with high wind energy penetration and a national perspective on Germany with a PV-dominated mix of installed capacities. A numerical model is developed for in-depth assessment of the thermodynamics inside the cavern. Hydrogen storage profiles generated from 2045 renewable electricity projections for Germany reveal substantial storage demands. Key parameters such as hydrogen production and storage share turnover rate and storage interval length vary significantly between the two cases. In the Lower Saxony case high wind shares lead to increased turnover rates and reduced required working gas volumes but also result in steeper pressure and temperature gradients inside the cavern and necessitate larger compressor systems. In contrast the PV-dominated Germany case experiences lower internal cavern stresses but requires more flexible surface components to manage frequent fluctuations in hydrogen flow. These findings underscore the complex interplay between regional power mixes storage facility design and operational requirements.

Green hydrogen is critical for decarbonizing hard-to-electrify sectors but it faces high costs and investment risks. Here we defne and quantify the green hydrogen ambition and implementation gap showing that meeting hydrogen expectations will remain challenging despite surging announcements of projects and subsidies. Tracking 190 projects over 3 years we identify a wide 2023 implementation gap with only 7% of global capacity announcements fnished on schedule. In contrast the 2030 ambition gap towards 1.5 °C scenarios has been gradually closing as the announced project pipeline has nearly tripled to 422 GW within 3 years. However we estimate that without carbon pricing realizing all these projects would require global subsidies of US$1.3 trillion (US$0.8–2.6 trillion range) far exceeding announced subsidies. Given past and future implementation gaps policymakers must prepare for prolonged green hydrogen scarcity. Policy support needs to secure hydrogen investments but should focus on applications where hydrogen is indispensable.