CO2-neutral carbon-based gases, such as synthetic methane, offer high volumetric energy density and serve as viable greenhouse gas (GHG) mitigation measures for various end uses, including industrial processes and heating. Synthetic methane can utilize existing natural gas infrastructure, minimizing the need for demand-side transformation. Synthetic methane production requires sustainable carbon sources, such as direct air carbon capture (DACC) and electricity-based hydrogen from energy-intensive electrolysis (renewable hydrogen path). Alternatively, sustainable carbon can be used to compensate for CO2 emissions from fossil natural gas (natural gas path). In this study, we design a comparative framework to show that the economic competition between synthetic methane and CO2compensated fossil natural gas is independent of CO2 supply costs. We revise and consolidate literature supply costs of synthetic methane from potential exporting countries and compare them to costs of CO2-compensated fossil natural gas. In addition, we compare the supply chain emissions of both pathways. The results indicate that synthetic methane is only cost-competitive when fossil natural gas prices exceed 74 EUR/MWh in 2030 and 52 EUR/ MWh in 2050 in the Tech_progressive scenario with progressive technology cost assumptions. The study highlights that a cost-based regulatory approach may favor the natural gas path over the renewable hydrogen path due to the higher cost of synthetic methane. Applying a CO2 penalty for compensation for supply chain emissions can improve the competitiveness of synthetic methane only for high methane leakage rates and CO2 costs. This research contributes to the debate on cost-effective methane supply and the role of synthetic methane in promoting energy efficiency and sustainable energy supply. In addition, the developed comparative framework is generally transferable to other carbon-based energy carriers.

Hydrogen and its derivatives are important components to achieve climate policy goals, especially in terms of greenhouse gas neutrality. There is an ongoing controversial debate about the applications in which hydrogen and its derivatives should be used and to what extent. Typically, the estimation of hydrogen demand relies on scenario-based analyses with varying underlying assumptions and targets. This study establishes a new framework consisting of existing energy system simulation and optimisation models in order to assess the long-term price-elastic demand of hydrogen. The aim of this work is to shift towards an analysis of the hydrogen demand that is primarily driven by its price. This is done for the case of Germany because of the expected high hydrogen demand for the years 2025–2045. 15 wholesale price pathways were established, with final prices in 2045 between 56 €/MWh and 182 €/MWh. The results suggest that – if climate targets are to be achieved - even with high hydrogen prices (252 €/MWh in 2030 and 182 €/MWh in 2045) a significant hydrogen demand in the industry sector and the energy conversion sector is expected to emerge (318 TWh). Furthermore, the energy conversion sector has a large share of price sensitive hydrogen demand and therefore its demand strongly increases with lower prices. The road transportation sector will only play a small role in terms of hydrogen demand, if prices are low. In the decentralised heating for buildings no relevant demand will be seen over the considered price ranges, whereas the centralised supply of heat via heat grids increases as prices fall.

Today, most hydrogen production is based on natural gas and occurs locally at the demand sites. However, according to many studies, hydrogen generation will shift to greenhouse gas (GHG)-neutral sources and supply, substantially increasing demands to meet ambitious climate protection targets in the European Union. Therefore, the model-based analysis in this paper addresses where hydrogen will come from in a GHG-neutral target system. A scenario study examines different expansion paths of renewable energy generation technologies and variations in European cooperation regarding energy trading. The model results show that a domestic European hydrogen supply strategy is cost-efficient. This result is robust even with higher self-sufficiency shares of individual countries. However, delayed or restricted expansions of renewable electricity generation technologies lead to increased hydrogen demands for power generation and increased pipeline-bound hydrogen imports in winter from the Middle East and North Africa in the model results. Furthermore, scenarios with higher photovoltaic shares exhibit increased demand for hydrogen storage for seasonal energy supply and demand balancing and increased hydrogen demands for power generation. A cost-efficient hydrogen supply strategy should, therefore, particularly focus on the expansion of onshore wind energy and hydrogen supply technologies in Europe and strengthen European cooperation for energy supply infrastructures.

With its ability to store and transport energy without releasing greenhouse gases, hydrogen is considered an important driver for the decarbonisation of energy systems. As future hydrogen import prices from global markets are subject to large uncertainties, it is unclear what impact different hydrogen and derivative import prices will have on the future German energy system. To answer that research question, this paper explores the impact of three different import price scenarios for hydrogen and its derivatives on the German energy system in a climate-neutral setting for Europe in 2045 using three different energy system models. The analysis shows that the quantities of electricity generated as well as the installed capacities for electricity generation and electrolysis increase as the hydrogen import price rises. However, the resulting differences between the import price scenarios vary across the models. The results further indicate that domestic German (and European) hydrogen production is often cost-efficient.

The fast rollout of hydrogen generation, transport, and storage infrastructure has become a top priority of the European Union and its member states. Planning hydrogen infrastructure requires a thorough understanding of the future role of hydrogen in the energy system. At the same time, there is still huge uncertainty about the future demand for hydrogen and its overall role. An energy systems analysis is conducted with high temporal and spatial as well as technological resolution under alternative demand scenarios. An energy system model is used to optimize the entire European energy system with hourly time resolution and high spatial consideration of renewable energy potentials. The hydrogen demand in the five scenarios ranges from about 700 TWh for mainly industrial uses to 2800 TWh in all sectors in the EU27 + UK by 2050. The results show that an integrated European hydrogen system is a robust element of the cost-optimal system design in all scenarios. This encompasses flexible electrolyzers at the most favorable wind and solar locations, long-distance hydrogen transport network, large-scale seasonal underground storage, and electricity generation for peak demand periods. Conclusions about the individual components are provided and high-resolution data on hydrogen demand are available for future research.

Negative emission technologies will likely be needed to achieve the European Commission's goal of greenhouse gas neutrality by 2050. This article investigates the potential of reducing greenhouse gases in the atmosphere via the DACCS pathway, i.e., to capture CO2 from the ambient air and permanently store it in geological formations. Since the capture of CO2 from ambient air is energy-intensive, this study particularly models the integration of DACCS plants into a greenhouse gas-neutral European energy system. The model results show that DACCS in Europe 2050 could cost between 160 €/tCO2 and 270 €/tCO2 with very conservative techno-economic assumptions and between 60 €/tCO2 and 140 €/tCO2 using more progressive parameters. Annually capturing 5% of Europe's 1990 emissions with a fully electric DACCS system would increase the capacities of onshore wind by 80–119 GWel and PV by 85–126 GWel. In the model results, Sweden, the Iberian Peninsula, Norway, and Finland incorporate the essential characteristics for a successful deployment of capturing and storing CO2 from ambient air: Sufficiently large geological CO2 storage capacities and relatively low-cost, vacant renewable power generation potentials. The low DACCS costs could minimize the cost of combating climate change and prevent the implementation of more expensive mitigation strategies. On the other hand, a DACCS-based climate protection strategy is fraught with the risks of CO2 storage leaks, acceptance problems for the additional required expansion of renewable energies, and premature depletion of global CO2 storage potentials.

Hydrogen is widely considered to play a pivotal role in successfully transforming the German energy system, but the German government's current “National Hydrogen Strategy” does not specify how hydrogen utilization, production, storage or distribution will be implemented. Addressing key uncertainties for the German energy system's path to greenhouse gas-neutrality, this paper examines hydrogen in different scenarios. This analysis aims to support the concretization of the German hydrogen strategy. Applying a European energy supply model with strong interactions between the conversion sector and the hydrogen system, the analysis focuses on the requirements for geological hydrogen storages and their utilization over the course of a year, the positioning of electrolyzers within Germany, and the contributions of hydrogen transport networks to balancing supply and demand. Regarding seasonal hydrogen storages, the results show that hydrogen storage facilities in the range of 42 TWhH2 to 104 TWhH2 are beneficial to shift high electricity generation volumes from onshore wind in spring and fall to winter periods with lower renewable supply and increased electricity and heat demands. In 2050, the scenario results show electrolyzer capacities between 41 GWel and 75 GWel in Germany. Electrolyzer sites were found to follow the low-cost renewable energy potential and are concentrated on the North Sea and Baltic Sea coasts with their high wind yields. With respect to a hydrogen transport infrastructure, there were two robust findings: One, a domestic German hydrogen transport network connecting electrolytic hydrogen production sites in northern Germany with hydrogen demand hubs in western and southern Germany is economically efficient. Two, connecting Germany to a European hydrogen transport network with interconnection capacities between 18 GWH2 and 58 GWH2 is cost-efficient to meet Germany's substantial hydrogen demand.

Der Import von Wasserstoff in die EU aus Ländern mit günstigen Produktionsvoraussetzungen ist ein wesentlicher Faktor der heutigen Wasserstoffstrategien. Die Wirtschaftlichkeitsbewertung basiert jedoch oft auf Herstellkosten, in denen die Länderrisiken nicht adäquat abgebildet sind. Durch deren Einbeziehung über entsprechende Risikoaufschläge auf das Kapital lassen sich diese relativ einfach integrieren. Dies hat deutliche Auswirkungen auf die Wirtschaftlichkeit.

With the 2015 Paris Climate Agreement, the international community has reaffirmed its commitment to tackle anthropogenic climate change with the goal of limiting the global average temperature increase below 1.5 degrees C, but to a maximum of 2 degrees C above pre-industrial levels. Against this background, we examine scenarios for a complete decarbonisation of the European energy supply. Since such scenarios are based on a high expansion of weather-dependent renewable energy sources, the question arises, which flexible technologies are necessary to balance supply and demand in such energy systems. In this paper, a scenario analysis shows which capacity or volume of energy storage, power interconnectors and synthetic fuels are needed in decarbonization scenarios. To address this research question three different energy system models are applied. These models cover Europe and Germany, respectively, and are able to explain different results of the single models based of the corresponding model characteristics. The paper concludes that the power sector is able to cover a considerable share of the energy demand in the heat and transport sector with the help of flexible sector coupling technologies such as heat pumps and electric mobility. All considered models manage to find solutions for a deep decarbonization if flexibility and storage option are available.

The utilization of electricity-based fuels (e-fuels) is a potential strategy component for achieving greenhouse gas neutrality in the European Union (EU). As renewable electricity production sites in the EU itself might be scarce and relatively expensive, importing e-fuels from the Middle East and North Africa (MENA) could be a complementary and cost-efficient option. Using the energy system model Enertile, supply curves for hydrogen and synthetic methane in the MENA region are determined for the years 2030 and 2050 to evaluate this import option techno-economically. The model optimizes investments in renewable electricity production, e-fuel production chains, and local electricity transport infrastructures. Analyses of renewable electricity generation potentials show that the MENA region in particular has large low-cost solar power potentials. Optimization results in Enertile show for a weighted average cost of capital of 7% that substantial hydrogen production starts above 100 euro/MWhH2 in 2030 and above 70 euro/MWhH2 in 2050. Substantial synthetic methane production in the model results starts above 170 euro/MWhCH4 in 2030 and above 120 euro/MWhCH4 in 2050. The most important cost component in both fuel production routes is electricity. Taking into account transport cost surcharges, in Europe synthetic methane from MENA is available above 180 euro/MWhCH4 in 2030 and above 130 euro/MWhCH4 in 2050. Hydrogen exports from MENA to Europe cost above 120 euro/MWhH2 in 2030 and above 90 euro/MWhH2 in 2050. If exported to Europe, both e-fuels are more expensive to produce and transport in liquefied form than in gaseous form. A comparison of European hydrogen supply curves with hydrogen imports from MENA for 2050 reveals that imports can only be economically efficient if the two following conditions are met: Firstly, similar interest rates prevail in the EU and MENA; secondly, hydrogen transport costs converge at the cheap end of the range in the current literature. Apart from this, a shortage of land for renewable electricity generation in Europe may lead to hydrogen imports from MENA. This analysis is intended to assist in guiding European industrial and energy policy, planning import infrastructure needs, and providing an analytical framework for project developers in the MENA region.

China's energy system is based mainly on coal power plants, which held a share of 69% in 2017. Large numbers of coal power plants lead to air pollution and high CO2 emissions. China has high potentials for renewable energies, which could bring about the transformation of the energy system in the future. The transition of the energy system from coal-based to renewables-based is a huge challenge. A carbon-neutral energy system is based mainly on fluctuating renewable energies like wind and solar power. In order to meet the hourly demand, flexibility options are needed to balance volatile energy production. In this paper, we construct two scenarios to analyse a carbon-neutral Chinese energy system in 2060. The first scenario focusses on electricity in order to decarbonise the energy system. The second scenario uses hydrogen for the decarbonisation. We found that storage possibilities like batteries and hydrogen play a major role in both scenarios. However, the number of installed batteries was lower in the hydrogen scenario although the installed capacity of renewable energies is higher. This is due to the increased hydrogen production in this scenario, which flattens the high solar photovoltaic (PV) peak at noon. Our results highlight the importance of flexibility options in a decarbonised energy system with a high share of renewables.

Alongside substituting fossil fuels with renewable energies and increasing energy efficiency, the utilization of electricity-based hydrogen or its derived synthetic fuels is a potential strategy to meet ambitious European climate protection targets. As synthetic hydrocarbons have the same chemical properties as their fossil substitutes, existing infrastructures and well-established application technologies can be retained while CO2 emissions in energy conversion, transport, industry, and residential and services can be reduced. However, the conversion processes, especially the generation of hydrogen necessary for all e-fuels, are associated with energy losses and costs. To evaluate the techno-economic hydrogen production potential and the impact of its utilization on the rest of the energy system, a supply curve of electricity-based hydrogen in a greenhouse gas emission-free European energy system in 2050 was developed. It was found that hydrogen quantities of the order of magnitude envisaged in the 1.5 degrees C scenarios by the European Commission's long-term strategic vision (1536-1953 TWh(H2)) induce marginal hydrogen production costs of over 110 (sic)(2020)/MWh(H2) and electrolyzer capacities of more than 615 GW(el). Although the generation of these amounts of hydrogen using electrolysis provides some flexibility to the electricity system and can integrate small amounts of local surplus electricity, an additional 766 GWel of wind power and 865 GWel of solar power must be installed to cover the additional electricity demand for hydrogen production. It was furthermore found that the most important techno-economic properties of electrolyzers used in an energy system dominated by renewable energies are the ability to operate flexibly and the conversion efficiency of electricity into hydrogen. It is anticipated that the shown analysis is valuable for both policy-makers, who need to identify research, subsidy and infrastructure requirements for a future energy system, and corporate decision-makers, whose business models will be significantly affected by the future availability of electricity-based fuels.

To meet ambitious climate protection targets, European greenhouse gas emissions need to be reduced to net zero by 2050. Even under these circumstances, there remain processes in industry, transport, or power and heat supply that require CO2 as a feedstock or emit CO2 as flue gas. In this paper, we characterize the physical and economic interrelations of the emerging CO2 economy. We find that direct air capture processes for CO2 become essential. We furthermore show that the use of natural gas remains economically more feasible than the use of synthetic fuels if long-term carbon storages are available.