Germany

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.