Hydrogen is expected to play a key role in the energy transition. Analyses exploring the price of hydrogen usually calculate average or marginal production costs regardless of the time of delivery. A key factor that affects the price of hydrogen is the balancing costs, which we define as the expense of ensuring a steady schedule of hydrogen delivery. We explore the effect of delivering hydrogen to the export ports at different schedules, ranging from fully flexible to moderately stable with a daily and weekly buffer, to fully stable. We quantify the rise in hydrogen price with strict balancing constraint in three countries: Brazil, Morocco and Turkey, and three export volumes: 10, 50 and 200 TWh. The price difference between the flexible and stable schedules was found to reach a maximum of 36 % in Brazil, 47 % in Morocco and 18 % in Turkey across the different volumes.

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.

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.

Much research and policy advice for addressing climate change has focused on developing model-based scenarios to identify pathways towards achieving decarbonisation targets. The paper's first aim is to complement such model-based analysis with insights from socio-technical transition analysis to develop socio-technical storylines that show how low-carbon transitions can be implemented. Our second aim is to explore how policymakers could govern such transition processes through transformative policy mixes. We take the example of the transition of the German electricity system towards renewable energies, and elaborate two transition pathways which are assumed to achieve an 80% reduction in greenhouse gas emissions by 2050, but differ in terms of lead actors, depth and scope of change: the first pathway captures the substitution of technological components (pathway A), while the second aims at broader system transformation (pathway B). We find that multi-dimensional socio-technical change (pathway B) requires greater emphasis on societal experimentation and a more proactive role for anticipatory deliberation processes from the outset. In contrast, shifting gear from a new entrant friendly past trajectory to an incumbent dominated pathway (pathway A) requires agency from incumbents and is associated with regime stabilizing instruments defending the old regime while simultaneously fulfilling decarbonisation as additional success criteria.

[Summary and conclusions] A stronger integration across energy sectors can contribute to achieving climate targets, provided that fossil fuels are substituted by renewable energy sources. One analysis for the German energy market estimates the potential GHG-emission savings due to sector coupling to 50 Mio t of CO2 emissions by 2030 (see Wietschel et al. 2017). A high potential to reduce GHG-emissions in the short and medium term is provided by direct electrification options: e-mobility, heat pumps and electric blast furnace. In the longer term, trolley trucks may also contribute to GHG-emission reductions, but the technology is not yet mature and it will depend on the achievable technology and cost development. There are also options in the industry sector, including methanol, ammonium or refineries, but these options are still far from being economically efficient. Producing electricity mainly based on RES is crucial for exploiting the GHGemission reduction potential of sector coupling technologies. However, we believe that a timely market entry of sector coupling technologies is required in order to exploit potentials on a longer term. The current electricity mix still shows considerable shares of fossil fuels, but a further increase of the RES-E share is a precondition for exploiting the GHG-emission reduction potential of sector coupling technologies. Wietschel et al. (2017) suggest using options with high efficiencies and a high GHG-emission reduction potential in the early phase of the transformation mainly for reasons of public and social acceptance. Sector coupling technologies may also contribute to increasing energy efficiency (e.g. e-mobility, electric steel) and thus reduce GHG-emissions due to efficiency improvements. For example, heat pumps make use of the ambient heat and can therefore improve efficiencies. Wietschel et al. (2017) have estimated for Germany that final energy consumption can be reduced by 180 TWh due to the efficiency effect by 2030, whilst electricity demand of new applications would increase by 50 TWh. Finally, sector-coupling technologies can increase the flexibility of the power system, which can be particularly relevant for systems with high shares of variable RES-E. However, the flexibility potential of different options and technologies strongly differs. According to Wietschel et al. (2017) there are high potentials for e-mobility and electrode boilers in heating networks.

Increasing realism in quantitative system modelling with respect to the representation of actors, decision-making, and institutions is critical to better understand the transition towards a low-carbon sustainable society. Yet, studies using quantitative system models, which have become a key analytical tool to support sustainability and decarbonization policies, focus on outcomes, therefore overlooking the dynamics of the drivers of change. We explore opportunities that arise from a deeper engagement of quantitative systems modelling with social science. We argue that several opportunities for enriching the realism in model-based scenario analysis can arise through model refinements oriented towards a more detailed approach in terms of actor heterogeneity, as well as through integration across different analytical and disciplinary approaches. Several opportunities that do not require major changes in model structure are ready to be seized. Promising ones include combining different types of models and enriching model-based scenarios with evidence from applied economics and transition studies.

Social acceptance and political feasibility are important issues in low-carbon transitions. Since computer models struggle to address these issues, the paper advances socio-technical scenarios as a novel methodological tool. Contributing to recent dialogue approaches, we develop an eight-step methodological procedure that produces socio-technical scenarios through various interactions between the multi-level perspective and computer models. As a specific contribution, we propose 'transition bottlenecks' as a methodological aid to mediate dialogue between qualitative MLP-based analysis of contemporary dynamics and quantitative, model-generated future pathways. The transition bottlenecks also guide the articulation of socio-technical storylines that suggest how the social acceptance and political feasibility of particular low-carbon innovations can be improved through social interactions and endogenous changes in discourses, preferences, support coalitions and policies. Drawing on results from the 3-year PATHWAYS project, we demonstrate these contributions for the UK electricity system, developing two low-carbon transition pathways to 2050 commensurate with the 2 degrees C target, one based on technological substitution (enacted by incumbent actors), and one based on broader system transformation (enacted by new entrants).

In this paper, we apply two global Integrated Assessment Models (IAMs) and one detailed European electricity system model to explore the consequences of different narrative-based low-carbon scenarios on the electricity system from the global to national scale. The narratives are based on insights from socio-technical transition analysis on niche-innovations. The main aim of this exercise is to examine the solution space in low-carbon scenarios for electricity supply from the global to national scale, which is largely neglected when focusing on cost-optimal solutions only. We show that taking into account insights from socio-technical transition analysis can have large impacts on the projected transition strategy, especially regarding relatively costly technologies that currently have a high momentum. For instance, we fad that the share of offshore wind in electricity generation in Europe is less than 3% or up to 27% by 2050, depending on the underlying narrative. These ranges are useful input for policy-makers, as they show the degree of flexibility in mitigation options. Furthermore, our analysis shows that combining IAMs with more detailed sectoral models illuminates the challenges on a more detailed geographical scale, for instance regarding storage requirements and the need for interconnectivity across European borders.

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.

This paper proposes an approach to comparing and assessing the policy settings in the European low-carbon energy scenarios. First, it presents the methodology including ten characteristics for scenario assessment: modelling framework (diversity), ambitiousness of the targets 2050, relations with other (European) countries, stakeholder involvement, technology options, non-technological aspects, economic component, usage of scenarios in policy design, intermediate indicators of targets' achievement and revision of scenarios. Further, it uses qualitative and quantitative methods to evaluate energy scenarios developed in six north-west European countries (the Netherlands, Germany, France, Denmark, the UK, Belgium). Finally, conclusions are made concerning the possible ways of scenario design improvement. The analysis has shown that all selected countries have potential for modifying their energy scenarios, which being implemented may help to achieve the joint European targets 2050. Since these countries are socially and economically interrelated, a more harmonised approach to scenario development is needed to be designed and introduced on the EU level. Ten characteristics proposed in this study may serve as an initial input for such harmonisation. The results can be of interest to economists, business and academic representatives, and especially policy makers involved in the long-term energy scenario development on the international, regional and national level.

China has set a goal of 20% non-fossil energy in total primary energy consumption by 2030. The decision of where to invest in renewable energy, and to what extent, needs to be considered from a forward-looking perspective. This article presents a power sector optimization model that integrates unit commitment with long-term generation expansion planning framework. Power dispatches at an hourly level are combined with yearly investment decisions. Based on the model, this article analyzes the optimal spatial deployment of renewable energy. The results show that regional differences in non-hydro renewable energy are significant. Approximately 75% should be deployed in the north of China. With the increase of combined heat and power, more renewable energy facilities, especially solar photovoltaic, should be located in the south of China. Inter-regional power transmission is beneficial to onshore wind in resource-rich areas, and could mitigate the conflict between coal-heavy generation mix and renewable energy.