Energy Transition Commentary 14
For those following the projected role of hydrogen in a future net-zero world, recent decades have been a roller-coaster ride. From the highs of the full-scale hydrogen economy to the lows of economic reality, hydrogen has attracted both enthusiasm and derision. ‘Low-carbon’ hydrogen has been mooted as a mass-market transport fuel, a means of home heating, a long-distance energy vector and as both fuel and feedstock for industry. None of these areas has yet advanced much and, looking at it today, the sceptics often seem closer to the money. Nevertheless, taking a holistic view, there is a case to be made that hydrogen can address some key issues in the energy transition better than the alternatives. In this commentary, we focus on just one area: seasonal energy storage.
Unlike natural gas, hydrogen has to be synthesised from something, practically either water or a fossil fuel (even though in the very long term natural ‘white’ hydrogen may become available). Obviously, this only helps us towards net zero if accomplished with minimal carbon emissions, in which case the term ‘low carbon’ hydrogen applies. ‘Green’ hydrogen, synthesised by electrolysis of water using renewable electricity, comes close. If used to displace fossil fuels or fossil-derived ‘grey’ hydrogen, carbon emissions would certainly fall. Furthermore, with a high-capacity, low-loss electricity grid, hydrogen can be produced at multiple demand locations, reducing the need for pipelines. Cost is another matter, more of which later.
Why do we need to use hydrogen? Isn’t electrification of everything the true path to decarbonisation? Well, the answer to the second question is ‘not entirely’ (there are no silver bullets) and the reason why provides one of the answers to the first question. The central issue is obvious: the majority of renewable electricity supply is highly intermittent with daily and seasonal variations dependent on geography and the particular mix of renewable generation technologies. Batteries have made huge strides and are able to balance supply and demand on an hourly basis, likely extending in time to span the diurnal cycle. However, balancing supply variation on a seasonal basis is an entirely different matter. For a country like the UK, without significant pumped hydro storage capacity, international power connections can help in the balancing act but these run counter to the need for energy security, independent of the policies and actions of other nations, friendly or otherwise. As highlighted in a Royal Society report [1], this is one area in which hydrogen presents advantages. Combining green hydrogen production with underground hydrogen storage (UHS) and either combustion or electrochemical power generation, one can have the backup generating capacity currently provided by unabated natural-gas-fired thermal power plants. This might be implemented on a scale sufficient to span an extended dunkelflaute: a period without wind and without sunshine. The UK has vast potential in the North Sea to store hydrogen in depleted gas fields or other reservoir formations [2], with significant additional capacity in on-shore solution-mined salt caverns. In brief, hydrogen would be produced when renewable power is abundant and electricity prices are low or even negative, then compressed and sent to underground storage. Then, during periods of undersupply by renewables, the stored hydrogen would be recovered from the reservoir and used to generate electricity. Generation can be accomplished with gas turbines, combustion engines or, more efficiently, in hydrogen fuel cells.
What about the energy efficiency and cost of using hydrogen for seasonal energy storage? Well, the round trip efficiency of electricity to hydrogen and back to electricity (power-to-power, P2P) is probably not better than about 40% [1] and might be as poor as 25% [3]. Storage efficiency in salt caverns is excellent (> 98%) and experience with natural-gas storage suggests that reservoir storage of hydrogen is viable on a large scale, although this has yet to be fully demonstrated - currently there are test projects underway in the Netherlands (HyStock) and in Utah (ACES). The major losses are divided between the electrolysers and generating plant. On the other hand, excess renewable electricity on sunny and windy days might otherwise be entirely wasted (curtailed) and so we should not dismiss hydrogen as an energy storage vector on the basis of energy efficiency alone. The largest factors controlling the cost of producing hydrogen are the price of electricity and the capital cost of the electrolysers and associated system components [4]. While much development effort has been directed to maximising efficiency, there may be benefit in focusing instead on minimising capital cost. This factor is especially important in energy storage because the main assets will only be used intermittently. However, some studies suggest that a cheaper low-carbon backup option is provided by conventional natural-gas-fired thermal generation fitted with carbon capture and storage (CCS) [5]. Unfortunately, for a country with insufficient natural-gas resources, this again creates a problem with security of supply. The wars in Ukraine and the Middle East have reminded us of the volatility and insecurity of international fossil fuel markets. Therefore, while building a hydrogen storage system at scale would be a massive undertaking, this could be the key to building a fully-renewable low-carbon energy system with guaranteed security of supply.
Hydrogen features strongly in both the UK’s Track One industrial decarbonisation clusters: the East Coast Cluster and the HyNet North West Cluster. Both aim to include electrolysers to provide some of the hydrogen; HyNet even includes medium-scale UHS in salt caverns and the East Coast Cluster has the potential for easy access to future large-scale UHS in the North Sea. These are very welcome developments. However, it is notable that in these projects the majority of the hydrogen is ‘blue’, synthesised from natural gas with CCS. This reflects the generally more favourable near-term economics offered by going ‘blue’. The depth of decarbonisation in this case has been questioned and is indeed contingent on the proper design and operation of the whole supply chain, especially on the control of fugitive gas emissions. The key near-term objectives in the Track One clusters include decarbonising existing industrial hydrogen demand and displacing natural gas firing in high-temperature industrial processes, another key use of hydrogen for the UK and elsewhere. These projects provide vital testbeds for hydrogen technology at scale and key anchor points from which to grow a network that includes seasonal storage capacity. Longer term, having a plentiful supply of low-cost renewable electricity, bringing down the cost of electrolysers and exploiting the UK’s natural availability of subsurface hydrogen storage sites are key targets for minimising the cost of this option for enhancing energy security and independence from fossil fuels.
Hydrogen is not the answer to every decarbonisation challenge (biomethane offers a complementary route for energy balancing and decarbonising future chemical manufacturing, for example), but it may prove indispensable in areas where alternatives fall short. For seasonal electricity storage, its value lies in its ability to provide long-duration, low-carbon backup at the scale required by a renewables-led energy system. If the UK and other countries of similar geography are serious about combining deep decarbonisation with energy security, then hydrogen storage deserves to be considered as an essential part of the solution.
More detailed descriptions of the technical challenges and likely costs of using hydrogen plus renewables in hybrid power, heating and other electrification technologies are given in two recent IChemE webinars [6]. We are grateful to David Simmonds for useful discussions and suggestions for this commentary.
Sources
- Llewellyn Smith, C. (2023). Large-scale electricity storage. The Royal Society. https://royalsociety.org/news/2023/09/electricity-storage-report/
- Zongtai Zhang et al (2026). A system-level assessment of geological hydrogen storage, renewable generation and demand prediction for clean electricity pathways: A Great Britain case study. Applied Energy, 421, 128171. See also: Durham Energy Institute, North Sea hydrogen storage could power UK for 7 years, https://www.durham.ac.uk/research/institutes-and-centres/durham-energy-institute/about-us/news/north-sea-hydrogen/
- Mac Dowell, N. et al. (2021). The hydrogen economy: A pragmatic path forward. Joule, 5(10), 2524-2529. https://doi.org/10.1016/j.joule.2021.09.014
- Martínez de León, C. et al. (2024). Levelized Cost of Storage (LCOS) for a hydrogen system. J. Hydrogen Energy, 52(A), 1274-1284. https://doi.org/10.1016/j.ijhydene.2023.07.239
- Patonia, A. et al. (2025). Underground storage for decarbonisation: trade-offs between hydrogen, natural gas, and carbon dioxide. The Oxford Institute for Energy Studies. https://www.oxfordenergy.org/wpcms/wp-content/uploads/2025/06/ET47-Underground-storage-for-decarbonisation.pdf
- Simmonds, D (2026). IChemE Oil, Gas and Energy Transition Special Interest Group Webinars:
- Our Energy Transition Part 1 - The Case for Electrification with Hydrogen to Reduce Costs, 24 March, 2026
- Our Energy Transition - Part 2: The Case for Hybrid Technologies to Offer Consumers More Choice, 21 April, 2026
Professor Martin Blunt, Professor of Flow in Porous Media
Professor Paul Fennell, Professor of Clean Energy
Professor Niall Mac Dowell, Professor of Energy Systems Engineering
Professor Geoffrey Maitland, Professor of Energy Engineering
Professor Ann Muggeridge, Professor of Subsurface Physics
Professor Ronny Pini, Professor of Multiphase Systems
Professor Martin Trusler, Professor of Thermophysics
Imperial College London, Transition to Net Zero Group