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As part of global decarbonization initiatives, there is a clear need to substantially increase power generation levels in order to electrify – directly or indirectly – other parts of the energy system, particularly through displacing fossil fuels in industry, heating and transport. In the UK, the Committee on Climate Change estimates that a fourfold increase in power generation will be required by 2050.

Low carbon options for this increased power generation are (i) renewables, (ii) nuclear power, and (iii) natural gas or biomass if carbon capture and storage (CCS) is applied.

However, direct electrification alone will not achieve net zero goals. Many major energy users are currently found in hard-to-abate and hard-to-electrify sectors, for example, industries using hydrogen as a feedstock or for reactivity (e.g., fertiliser production and refineries) or those needing hydrogen (or natural gas) for combustion. Moreover, relying on batteries may not be a technically or economically viable option for certain segments of the transport sector, such as shipping, aviation and heavy freight. Gas systems, particularly in countries with extensive gas networks, provide a valuable resource to address the predicted strains on future electricity systems. While using natural gas with CCS for power and industry is a potential carbon abatement route for clusters of large users – if sited at locations with potential access to CO2 pipeline networks and storage structures – CCS is not a viable option for the majority of current gas use.

Hydrogen, although not an energy source, can be produced from low carbon as a flexible energy vector, bringing energy from a low-carbon energy source to an end use that cannot rely on it directly.

Hydrogen can also help stabilise an electricity grid with high penetration of renewables. Indeed, renewables such as wind power and photovoltaic power (PV), although currently proving relatively low-cost generators, have intermittency issues – and often location constraints – which result in high (and often underestimated) system costs. For example, IEA models show that, accounting for such system costs, PV, with a penetration of 40%, would see its overall value reduced by one-quarter (even without accounting for any local grid bottlenecks or the cost of storage). This is particularly the case when they reach a sufficient level of penetration, and where they are not backed up by other reliable and/or flexible power sources. Given the projected increases in overall electricity flows – resulting from increased electrification – electrical grid capacity will become an ever-increasing challenge, even more so where there is a high level of intermittent renewable generation on the system.

Furthermore, limited electrical storage capacity means that, without additional mechanisms, electrical systems will be unlikely to be able to deal with the very substantial energy consumption variations, notably those caused by weather patterns in heating. Yet, hydrogen can provide both an electricity peak-shaving function and an electricity storage.

Hydrogen therefore has a clear value in hard-to-abate/electrify sectors – particularly in industry and heavy transport – and, through its (electricity) storage and distribution potential, also has value in addressing very real electricity network constraints, especially in networks with a high renewables penetration.

Nonetheless, given its relatively high cost as an energy vector, hydrogen alone is not the most cost-efficient way of addressing intermittency and related systems problems. Nuclear power, as a zero-carbon energy source, has the resilience, capacity and flexibility to assist in addressing the variable output of renewable energy and to significantly reduce the system costs of power on a low-carbon electricity grid, where used synergistically with renewables and hydrogen.

Indeed, nuclear facilities – including small modular reactors (SMRs) and advanced modular reactors (AMRs) – can also provide zero-carbon industrial (or district) heat, which reduces the strain on the system caused by widespread electrification. Moreover, when considering the future deployment of SMRs and AMRs – which, for safety and size reasons, have greater flexibility in locations than the current gigawatt-scale nuclear plants – there seems to be the potential to even better address grid constraints and stability issues, especially those posed by large concentrations of offshore renewables.

Beyond these advantages, one of the main future values of nuclear power lies in its capacity to produce hydrogen at scale, in a way that addresses the other inherent constraints of large-scale electrification in a decarbonised economy.

Indeed, hydrogen production from renewables also faces intermittency issues, and this potentially limits the potential to utilise electrolyser capacity at high-load levels, which both increases the cost of production and means a need for high storage capacity. The synergistic production of electricity from renewables and nuclear sources ensures that excess clean electrical generation for hydrogen production is available consistently, regardless of weather patterns, and potentially reduces storage capacity needs and costs. The nuclear production of hydrogen is reliable and can ensure high utilisation of expensive electrolysis capacity.

Moreover, the use of nuclear heat enables a reliance on more efficient hydrogen production processes. Firstly, using nuclear waste heat, one can carry out electrolysis (i.e., the splitting of water into hydrogen and oxygen) at a high temperature, which is ‘easier’ chemically speaking and results in higher production levels of clean hydrogen per unit of electricity compared to low-temperature renewables-based electrolysis, further reducing the cost of hydrogen production. Recent studies have found that, per unit of installed electrolyser capacity, nuclear power can produce 2.3 times as much clean hydrogen as wind power and 5.4 times as much as PV production of hydrogen. Secondly, while not proven yet at commercial scale, there is the potential for AMRs, operating at more than 800°C, to generate hydrogen through thermochemical processes at very high rates of efficiency, which potentially provide the lowest cost of clean hydrogen, and the ability to do so on a consistent and geographically distributed basis.

Lastly, recent studies show that a clean energy transition from hydrocarbon to hydrogen-based fuels that would be based on nuclear, renewable and other hydrogen sources could be achieved with a global investment level substantially lower than the expected expenditure needed in order to maintain fossil fuel flows, and substantially lower than the investment needed for an equivalent hydrogen strategy based only on wind and solar.

For these reasons, policymakers have shown a keen interest in nuclear hydrogen.

Paula Abreu Marquez, Head of Unit for Renewables and CCS Policy at the European Commission’s Energy Directorate, had indicated that the Commission would consider hydrogen produced from nuclear power as “low carbon” within the Commission’s Hydrogen Strategy.

The French National Hydrogen Strategy sees a clear and valuable role for nuclear-based hydrogen. In France, EdF operates a fleet of nuclear units plus hydro, wind and solar generation, which enables it to produce 96% CO2-free power. The ability to adapt nuclear production depending on renewable production means that it regularly has excess amounts of clean power to export to renewable-heavy neighbours (such as Germany) with intermittency issues. However, this also means that EdF has a large amount of surplus, marginal-cost and clean electricity available to produce hydrogen.

The role of nuclear as a balance to renewables and the advanced production of hydrogen is also part of the UK’s Energy White Paper. The white paper references the 2050 electricity system analysis model, used to assess decarbonisation options in the UK, which shows that the most cost-effective solutions for a low-emissions pathway can only be achieved with a combination of new nuclear and gas with CCS complementing significant levels of renewables. It also concludes that bringing hydrogen into the energy mix can achieve the same result with a reduced level of new generation.

Companies have also understood this, and a number of companies are developing proposals around combinations of renewables, nuclear and hydrogen. EdF has formed a subsidiary (Hynamics) to focus on opportunities in this area, while Shearwater Energy, a UK-based hybrid clean energy company, is developing a wind, SMR and hydrogen production hybrid energy project in North Wales designed to produce 3 GW of zero-carbon energy and over 3 million kg of green hydrogen per year.

In conclusion, one point all studies agree on is that achieving decarbonisation to net zero levels by 2050 requires a massive amount of change in current energy systems, and that all appropriate methodologies need to be employed if we are to have any chance of succeeding in these ambitions. A strategy around complementary renewable and nuclear electricity production, together with associated production of hydrogen, is perhaps the surest and lowest-cost way of achieving the goal of having decarbonised, secure, stable and affordable energy.

Author

Neil Donoghue is a partner in the Firms’ Energy Mining and Infrastructure Practice with over 30 years of experience throughout Europe, Middle East, Africa and Asia. Neil is Head of Baker McKenzie’s Global Nuclear Energy Practice.

Author

William-James Kettlewell is an Associate in Baker McKenzie Brussels office.