ETI analysis has shown that hydrogen has the potential to play a highly versatile role in a future low carbon energy system. This is because hydrogen can be used in many different applications including industry high-temperature heat, peak power generation, fuel cell vehicles and potentially for heating buildings. We believe this versatility makes investment in de-risking hydrogen a low regrets option.
Today, hydrogen is mostly used as a high-value feedstock in the chemical and refining industries, and most production is via Steam Methane Reforming, resulting in a sizeable carbon footprint. For hydrogen to make sense in a decarbonised context, it must be produced using low carbon methods. From our assessment of the full range of technology options, the most cost-effective solutions for large-scale production involve the use of carbon-based feedstocks such as gas, coal, biomass and so rely on Carbon Capture and Storage (CCS) technology to reduce the emissions impact. In the case of biomass gasification this results in producing negative emissions which in itself is as valuable to the wider energy system as the hydrogen product itself.
Industry appears to be an obvious first choice for a nascent hydrogen market. This sector is already familiar with handling hydrogen as a process feedstock. Additionally, there are relatively few alternatives for industry carbon abatement, making hydrogen use almost inevitable in the longer term. Finally, where hydrogen is produced in large centralised CCS facilities, these are likely to be near existing centres of heavy industry. By serendipity, the best CO2 storage sites lie in UK waters off some of our major industrial regions. This would minimise the need for immediate investment in long distance transmission infrastructure. As the market develops, dedicated pipelines could then be built out to support other sectors across the UK.
In transport, much depends on consumer attitudes and behaviours. In the consumer market, people may become relatively comfortable with the range and charging times associated with electric vehicles, meaning limited opportunity remains for hydrogen fuel cell vehicles once these are eventually ready for large-scale deployment. In the market for commercial vehicles, especially heavy-duty vehicles, the energy density of hydrogen over batteries may tip the scales. The economics of infrastructure roll-out would also favour the latter market, minimising the need for initial hydrogen refuelling facilities to a small number of commercial depots. Hydrogen for transport would likely be delivered through a combination of pipelines to major refuelling centres, along with truck deliveries to smaller facilities in the further reaches of the country.
Hydrogen for heat in buildings is beginning to be explored seriously, with testing and demonstration required before an accurate cost assessment can be made. In principle though, this could enable some parts of the extensive UK gas distribution network to continue to provide a highly responsive means of heating homes. Inevitably though, the unit cost of hydrogen will be higher than for gas today, with resource extraction costs compounded by conversion costs and CCS costs. As a result it is not obvious that hydrogen is a clear winner for domestic heating.
Hydrogen boilers may need to be combined with interventions such as household retrofits and installation of electric heat pumps. If these measures are to be adopted anyway, then on a regional basis there will need to be strategic decisions as to whether it makes better sense to take these measures far enough that the gas network can be decommissioned altogether. There is also a challenge in getting low carbon hydrogen supplies at sufficient scale rolled out across the UK, but this may be an easier challenge than installing heat-pumps in the majority of houses and upgrading the electricity distribution system. Once better evidence is in place for hydrogen heating, then the national and regional fit of heat-pumps, hydrogen and district heating can be compared on a firm basis. The national and regional infrastructure implications of different choices are quite different.
In light of the current interest in hydrogen for heat, and with the inclusion of a hydrogen pathway in the government’s Clean Growth Strategy, we recently devised a pathway which assumes maximal use of hydrogen by energy consumers across heat, transport and industry. This means by 2050 all cars and vans on the road are hydrogen models, the gas distribution network is fully converted, and 20% of industrial energy use is from hydrogen. Also, consistent with the Clean Growth Strategy, we prevented the use of bioenergy with CCS.
The production of hydrogen is consequently very high at over 530TWh in 2050 (vs ~160TWh for Clockwork, ~90TWh in Patchwork). This would require a huge investment to build the production, transmission and distribution infrastructure for an entire new energy sector, overtaking electricity generation in the space of 20 years. The pathway also hinges on the successful roll-out of CCS infrastructure from around 2030. With an annual abatement cost in 2050 of £121bn, the cost implications of a hydrogen only pathway seem clear (especially without bio-energy). A strategy to enforce comprehensive adoption of hydrogen across the economy looks grossly inefficient based on current understanding of the relevant technologies.
This implies there is a role for hydrogen but the boundaries have to be understood, and it needs to be part of a blended mix of technologies for the most cost-effective transition to low carbon. All cost-effective ETI energy scenarios include increased electrification, an increased role for hydrogen, increased sustainable UK bio-energy production and CCS. The optimum balance of these and other elements is still uncertain. We need to develop a range of plausible options, which definitely includes hydrogen.