Policy & Socio-Economics

The EU and a number of its member states have now published hydrogen strategies and Europe continues to lead the way in the decarbonisation of its gas sector. In this latest OIES Energy Podcast James Henderson talks with Martin Lambert and Simon Schulte about their latest paper entitled “Contrasting European Hydrogen Pathways” which examines the plans in six major EU countries. They discuss the outlook for various forms of hydrogen supply contrasting the potential for green hydrogen from renewable energy with the outlook for blue hydrogen using steam-reforming of methane as well as hydrogen generated from surplus nuclear energy. They also examine the potential sources of demand considering existing use of hydrogen in industrial processes as well as the potential for hydrogen to displace hydrocarbons in the steel and cement industries. Finally the podcast also looks at the potential for imports of hydrogen and its distribution within Europe while also considering some key milestones that can provide indicators of how the region’s hydrogen plans are playing out.

The podcast can be found on their website

The building sector is one of the key energy consumers worldwide. Fuel cell micro-Cogeneration Heat and Power systems for residential and small commercial applications are proposed as one of the most promising innovations contributing to the transition towards a sustainable energy infrastructure. For the application and the diffusion of these systems in addition to their environmental performance it is necessary however to evaluate their economic feasibility. In this paper a life cycle assessment of a fuel cell/photovoltaic hybrid micro-cogeneration heat and power system for a residential building is integrated with a detailed economic analysis. Financial indicators (net present cost and payback time are used for studying two different investments: reversible-Solid Oxide Fuel Cell and natural gas SOFC in comparison to a base scenario using a homeowner perspective approach. Moreover two alternative incentives scenarios are analysed and applied: net metering and self-consumers’ groups (or energy communities). Results show that both systems obtain annual savings but their high capital costs still would make the investments not profitable. However the natural gas Solide Oxide Fuel Cell with the net metering incentive is the best scenario among all. On the contrary the reversible-Solid Oxide Fuel Cell maximizes its economic performance only when the self-consumers’ groups incentive is applied. For a complete life cycle cost analysis environmental impacts are monetized using three different monetization methods with the aim to internalize (considering them into direct cost) the externalities (environmental costs). If externalities are considered as an effective cost the natural gas Solide Oxide Fuel Cell system increases its saving because its environmental impact is lower than in the base case one while the reversible-Solid Oxide Fuel Cell system reduces it.

Power-to-Methane (PtM) can provide flexibility to the electricity grid while aiding decarbonization of other sectors. This study focuses specifically on the methanation component of PtM in 2050. Scenarios with 80–95% CO₂ reduction by 2050 (vs. 1990) are analyzed and barriers and drivers for methanation are identified. PtM arises for scenarios with 95% CO₂ reduction no CO₂ underground storage and low CAPEX (75 €/kW only for methanation). Capacity deployed across EU is 40 GW (8% of gas demand) for these conditions which increases to 122 GW when liquefied methane gas (LMG) is used for marine transport. The simultaneous occurrence of all positive drivers for PtM which include limited biomass potential low Power-to-Liquid performance use of PtM waste heat among others can increase this capacity to 546 GW (75% of gas demand). Gas demand is reduced to between 3.8 and 14 EJ (compared to ∼20 EJ for 2015) with lower values corresponding to scenarios that are more restricted. Annual costs for PtM are between 2.5 and 10 bln€/year with EU28’s GDP being 15.3 trillion €/year (2017). Results indicate that direct subsidy of the technology is more effective and specific than taxing the fossil alternative (natural gas) if the objective is to promote the technology. Studies with higher spatial resolution should be done to identify specific local conditions that could make PtM more attractive compared to an EU scale.

Green hydrogen (H2) is emerging as a future clean energy carrier. While there exists significant analysis on global renewable (and non-renewable) hydrogen generation costs analysis of its transportation costs irrespective of production method is still limited. Complexities include the different forms in which hydrogen can be transported the limited experience to date in shipping some of these carrier forms the trade routes potentially involved and the possible use of different shipping fuels. Herein we present an open-source model developed to assist stakeholders in assessing the costs of shipping various forms of hydrogen over different routes. It includes hydrogen transport in the forms of liquid hydrogen (LH2) ammonia liquified natural gas (LNG) methanol and liquid organic hydrogen carriers (LOHCs). It considers both fixed and variable costs including port fees possible canal usage charges fuel costs ship capital and operating costs boil-off losses and possible environmental taxes among many others. The model is applied to the Rotterdam-Australia route as a case study revealing ammonia ($0.56/kgH2) and methanol ($0.68/kgH2) as the least expensive hydrogen derivatives to transport followed by liquified natural gas ($1.07/kgH2) liquid organic hydrogen carriers ($1.37/kgH2) and liquid hydrogen ($2.09/kgH2). While reducing the transportation distance led to lower shipping costs we note that the merit order of assumed underlying shipping costs remain unchanged. We also explore the impact of using hydrogen (or the hydrogen carrier) as a low/zero carbon emission fuel for the ships which led to lowering of costs for liquified natural gas ($0.88/kgH2) a similar cost for liquid hydrogen ($2.19/kgH2) and significant increases for the remainder. Given our model is open-sourced it can be adapted globally and updated to match the changing cost dynamics of the emerging green hydrogen market.

The Hydrogen Strategy Group chaired by Australia’s Chief Scientist Dr Alan Finkel has today released a briefing paper on the potential domestic and export opportunities of a hydrogen industry in Australia.

Like natural gas hydrogen can be used to heat buildings and power vehicles. Unlike natural gas or petrol when hydrogen is burned there are no CO₂ emissions. The only by-products are water vapour and heat.

Hydrogen is the most abundant element in the universe not freely available as a gas on Earth but bound into many common substances including water and fossil fuels.

Hydrogen was first formally presented as a credible alternative energy source in the early 1970s but never proved competitive at scale as an energy source – until now. We find that the worldwide demand for hydrogen is set to increase substantially over coming decades driven by Japan’s decision to put imported hydrogen at the heart of its economy. Production costs are falling technologies are progressing and the push for non-nuclear low-emissions fuels is building momentum. We conclude that Australia is remarkably well-positioned to benefit from the growth of hydrogen industries and markets.

Pathways leading to a carbon neutral future for the German energy system have to deal with the expected phase-out of coal-fired power generation in addition to the shutdown of nuclear power plants and the rapid ramp-up of photovoltaics and wind power generation. An analysis of the expected impact on electricity market security of supply and system stability must consider the European context because of the strong coupling—both from an economic and a system operation point of view—through the cross-border power exchange of Germany with its neighbors. This analysis complemented by options to improve the existing development plans is the purpose of this paper. We propose a multilevel energy system modeling including electricity market network congestion management and system stability to identify challenges for the years 2023 and 2035. Out of the results we would like to highlight the positive role of innovative combined heat and power (CHP) solutions securing power and heat supply the importance of a network congestion management utilizing flexibility from sector coupling and the essential network extension plans. Network congestion and reduced security margins will become the new normal. We conclude that future energy systems require expanded flexibilities in combination with forward planning of operation.

As a signatory to the Paris Agreement Singapore is committed to achieving net-zero carbon emissions in the second half of the century. In this paper we propose a decarbonization roadmap for Singapore based on an analysis of Singapore’s energy landscape and a technology mapping exercise. This roadmap consists of four major components. The first component which also underpins the other three components is using centralized post-combustion carbon capture technology to capture and compress CO2 emitted from multiple industrial sources in Jurong Island. The captured CO2 is then transported by ship or an existing natural gas pipeline to a neighboring country where it will be stored permanently in a subsurface reservoir. Important to the success of this first-of-a-kind cross-border carbon capture and storage (CCS) project is the establishment of a regional CCS corridor which makes use of economies of scale to reduce the cost of CO2 capture transport and injection. The second component of the roadmap is the production of hydrogen in a methane steam reforming plant which is integrated with the carbon capture plant. The third component is the modernizing of the refining sector by introducing biorefineries increasing output to petrochemical plants and employing post-combustion carbon capture. The fourth component is refueling the transport sector by introducing electric and hydrogen fuel cell vehicles using biofuels for aviation and hydrogen for marine vessels. The implications of this roadmap on Singapore’s energy policies are also discussed.

The EU aims for complete decarbonisation. Therefore renewable generation must be massively expanded and the energy and exergy efficiency of the entire system must be significantly increased. To increase exergy efficiency a holistic consideration of the energy system is necessary. This work analyses the optimal technology mix to maximise exergy efficiency in a fully decarbonised energy system. An exergy-based optimisation model is presented and analysed. It considers both the energy supply system and the final energy application. The optimisation is using Austria as a case study with targeted renewable generation capacities of 2030. The results show that despite this massive expansion and the maximum exergy efficiency about half of the primary energy still be imported. Overall exergy efficiency can be raised from today's 34% (Sejkora et al. 2020) to 56%. The major increase in exergy efficiency is achieved in the areas of heat supply (via complete excess heat utilisation and heat pumps) and transport (via electric and fuel cell drives). The investigated exergy optimisation results in an increase of the final electrical energy demand by 44% compared to the current situation. This increase leads to mainly positive residual loads despite a significant expansion of renewable generation. Negative residual loads are used to provide heat and hydrogen.

To address the climate emergency France is committed to achieving carbon neutrality by 2050. It plans to significantly increase the contribution of renewable energy in its energy mix. The share of renewable energy in its electricity production which amounts to 25.5% in 2020 should reach at least 40% in 2030. This growth poses several new challenges that require policy makers and regulators to act on the technological changes and expanding need for flexibility in power systems. This document presents the main strategies and projects developed in France as well as various recommendations to accompany and support its energy transition policy.

Gaseous fuels with low life-cycle emissions of greenhouse gases (GHG) play a prominent role in the European Union’s (EU) decarbonization plans. Renewable and low-GHG hydrogen are highlighted in the ambitious goals for a cross-sector hydrogen economy laid out in the European Commission’s Hydrogen Strategy. Renewable hydrogen and biomethane are given strong production incentives in the Commission’s proposed revision to the Renewable Energy Directive (REDII). The EU uses life-cycle analysis (LCA) to determine whether renewable gas pathways meet the GHG reduction thresholds for eligibility in the REDII. This study aims to support European policymakers with a better understanding of the uncertainties regarding gaseous fuels’ roles in meeting climate goals. Life-cycle GHG analysis is complex and differences in methodology as well as data inputs and assumptions can spell the difference between a renewable gas pathway qualifying or not for REDII eligibility at the 50% to 80% GHG reduction level. It is thus important for European policymakers to use robust LCA to ensure that policy only supports gas pathways consistent with a vision of deep decarbonization. For this purpose we conduct sensitivity analysis of the life-cycle GHG emissions of a number of low-GHG gas pathways including biomethane produced from four feedstocks: wastewater sludge manure landfill gas (LFG) and silage maize; and hydrogen produced from eight sources: natural gas combined with carbon capture and storage (CCS) coal with CCS biomass gasification renewable electricity 2030 EU grid electricity wastewater sludge biomethane manure biomethane and LFG biomethane. For each pathway we estimate the life-cycle GHG intensity using a default central case identify key parameters that strongly affect the fuel’s GHG intensity and conduct a sensitivity analysis by changing these key parameters according to the range of possible values collected from the literature. Figure ES1 summarizes the full range of possible GHG intensities for each gaseous pathway we analyzed in this study—biomethane is depicted in the top figure and hydrogen is shown in the bottom. The bars represent the GHG intensity of the central case and vertical error bars indicate the maximum and minimum GHG intensity of each pathway according to our sensitivity analysis. The dotted orange horizontal line illustrates the fossil comparator which is 94 grams of carbon dioxide equivalent per megajoule (gCO2e/MJ) for transport fuels in the REDII. The dotted yellow line represents the GHG intensity of a 65% GHG reduction goal for biomethane used in the transportation sector or 70% GHG reduction for hydrogen. Pathways are situated from left to right in increasing order of GHG intensity of the central case. Comparing the central cases of the four biomethane pathways the waste-based biomethane pathways generally have negative GHG intensity. However considering the uncertainty in these GHG intensities manure biomethane might have more limited carbon reduction potential in the 100-year timeframe if methane leakage from its production process is high. In contrast wastewater sludge biomethane and LFG biomethane even after accounting for uncertainties retain relatively low GHG emissions. On the other hand biomethane produced from silage maize can have much higher emissions; in the central case we find that silage maize biogas only reduces GHG emissions by 30% relative to the fossil comparator—the low carbon reduction potential is due to the significant emissions emerging from direct and indirect land use change involved in growing maize. Taking into account the variation in assumptions silage maize biomethane can be worse for the climate than fossil fuels.