Procuring heat for your business – either for an industrial process, or simply to heat premises – is about to get a lot more complicated. At the moment, most businesses have the choice of electricity or gas to fulfil that function. Decarbonisation means that has to change, because pumping fossil gas through the network will no longer an option in the long term.
The very ubiquity of the existing gas network makes changing a complex and long-lived operation. The outcome will have more options overall – but which are available will depend on your location. The options for you are likely to become clearer over the next decade, but businesses cannot wait that long to begin asking questions about the future. Whether you depend on heat or have plans to move, expand or extend your business, you should already be thinking about which heat options will be available.
The need to decarbonise heating has been clear from the start, but for a long time it was parked in the ‘too difficult’ bay while government and the energy industry made huge progress in decarbonising electricity supply. But the decision point is getting closer: the government has promised to take some big decisions on decarbonisation routes in 2026 so the energy industry – and customers – can start to commit to investment.
Will you have access to a gas network? Gas in the form of methane (largely chemically identical to fossil gas) will almost certainly not be available to users, except for a few very limited local arrangements where biogas is available.
WHAT ABOUT HYDROGEN?
One option sounds superficially attractive: convert the existing gas network to carry hydrogen, and produce the hydrogen in a way that does not send greenhouse gas emissions into the atmosphere. In fact, this is neither simple nor feasible across the country.
Think about the constraints. There is already a market for hydrogen, which is a key gas for industry, both as a chemical reagent as a source of direct heat to replace gas. With this in mind, the government has focused hydrogen development around some major industries, which tend to cluster in specific areas (such as major estuaries) so production and use is more efficient. There is also a need to use hydrogen as a replacement for fossil gas in some power stations, which means some hydrogen will be transported to those sites. With these calls on available hydrogen, in the medium term so-called ‘green hydrogen’ which is produced without greenhouse gas emissions, is expected to be a scarce resource, and using it to supply homes is likely to get the least value from it.
Nevertheless, it remains a possibility in some areas. To get an idea of the likely hydrogen regions we can use two sources. National Grid Gas has set out how it expects to be developing a network to transport hydrogen in dedicated pipelines over the next 20 years, and UK’s industrial cluster map shows where there are industrial users.
In July, the system operator (NGESO) produced its annual ‘Future Energy Scenarios’ – different versions of how the future energy system might look depending on decisions now. It says hydrogen is not expected to play a role for domestic heating until 2028 at the earliest. “Before 2030, demand for low carbon hydrogen will be dictated by proximity to a hydrogen production project, supported with government funding.” It too places hydrogen use around industrial and primarily for industrial processes (a map is on p20).
There are other constraints: transporting hydrogen “can be technically challenging and costly without a hydrogen network”, and in that case “developers must co-locate hydrogen production with the demand.” It also warns that short-term deployment is affected by the challenges of the transition from hydrogen to gas: in order for one household to transition to using hydrogen, either a new network of pipes would need to be installed, or existing gas network infrastructure converted to deliver hydrogen. This would require users in the area to switch over at the same time, all requiring hydrogen-ready boilers (or an alternative solution) to be in place.
Pathfinder projects have found these issues hard to address. In July, proposals for a ‘hydrogen village’ (that is, a trial area of around 2,000 properties) in Whitby were withdrawn, after protests from inhabitants. It was one of two potential sites for such a pilot, which would see homes and business premises converted so their gas pipes would deliver hydrogen instead of gas. A second potential trial site, in Redcar, remains on the ‘possible’ list.
WILL YOU HAVE ACCESS TO A HEAT NETWORK?
Typically, heat networks will be used in cities, where there are clusters of heat customers, industrial, commercial and domestic. They have not traditionally been used in the UK. The government’s heat network planning database lists those in operation and in the pipeline and its historical data shows how heat networks have grown recently. Move the slider on the application date parameter in the database and before 2010 there are barely any projects on the map. Even by 2015 only 19 are listed. By 2020 the sector had started to take off, with 119 projects in operation or in the pipeline. But the sector has had a huge boost from the government’s Green Heat Network Fund (GHNF) and over the last three years over 650 projects were added, bringing the total to 783 in mid-2023.
If the GHNF does its job, it should start to raise awareness among councils and bring costs down simply because of the ‘learning by doing’ effect. Many more heat networks are planned – helped by the fact that they are common in other European countries, so there is a wealth of experience in different areas to draw on. Investors who have funded heat networks elsewhere already have the UK in scope. For example, Bradford’s district heat network is under construction, funded partly through a GHNF grant and partly through private investment from 1Energy. In its first phase the district heating network will provide a heat for key buildings in Bradford city centre, starting from 2025. There is, however, the ambition and potential to expand the network significantly over the near term to areas adjacent to the city centre.
A major investor in the Bradford network is Asper, which has pumped more than £20 million into it. But the company says it plans to invest several hundred million pounds into heat networks in the UK over the next 5-10 years.
One reason heat networks are of interest is the wide variety of heat sources that can be used. Many take advantage of local resources, such as geothermal heat, waste heat from industrial processes or energy from waste plants, or water source heat pumps for areas around a river. But Bradford is the largest so far using air source heat pumps, which have very flexible installation options.
WILL YOU BE ABLE TO GO ELECTRIC?
Using hydrogen or district heating may entail limited on-site changes for businesses, but require third parties to invest in building or converting an external network. Switching to electricity for your business may require upgrades in the local electricity network (potentially taking up to a decade) but it also has implications, both negative and positive, for the site itself.
The option of switching from gas to electricity will have different cost implications for each company, depending on issues such as whether process heat is needed and whether there are off-site implications for the network.
The overall cost will also depend on whether the company has also taken other steps towards electrification, such as moving vehicle fleets to electric, or has reduced electricity demand from the grid with on-site renewables such as rooftop solar. It may be possible to alleviate the cost of using electricity for heat (and transport) if the company is able to offer flexibility. Some flexibility services receive a direct payment from NGESO or a supplier.
Which of these options will be available? No-one is likely to have access to all the options.
In its FES, the system operator said: “Designating zones for specific heating systems provides a more cost-optimal system than full consumer choice, particularly when considering growth of technologies with greater local infrastructure requirements such as district heating or hydrogen for heat.”
The government has promised to begin making decisions on how much to commit to converting the gas network to hydrogen in 2026, but that may be delayed because of the slow start to its hydrogen trial. The regulator Ofgem has begun making steps to taking location-based decisions. In July, it published a tender seeking a contractor for a six-month ‘Hydrogen Likely Areas Study’.
Decisions are taking place against a supply profile that is also changing. Gas use has been declining for many years in GB and this is expected to continue, especially after the process shocks of the past winter. NGESO expects “to see more industrial consumers move away from natural gas in our net zero scenarios,” especially after 2026.
We are not there at the moment, or near it (except for some tower blocks), but NGESO warns that “Fuel switching and adoption of alternate heating technologies across all sectors increasingly affects gas demand in the late 2020s across the net zero scenarios”.
NGESO says, “The planned government decision on the use of hydrogen for heat by 2026 is needed urgently to give clarity to on the future role of hydrogen.” Business customers will want that clarity too - not just on what options will be available, but when and where.
BOX: WHAT TO THINK ABOUT IN HYDROGEN CONVERSION
A report by consultants Aecom for the Department for Energy Security and Net Zero (DESNZ), published this summer, explored the implications of choosing hydrogen for heat at seven volunteer industrial sites. It found that design and installation guidance for hydrogen may result in significant modifications at site to bring the gas from the supplier to the end user. Much of the existing natural gas piping and infrastructure on the site would have to be replaced; even when the piping was acceptable, small parts – for example valves and pipe fittings – may not be.
Hydrogen has a lower ignition energy, wider flammable limits, is more explosive and has a lower detonation energy than natural gas. Additional risk controls were recommended at all sites surveyed to mitigate the additional risks, ranging from additional ventilation, to redesigning and replacing major pieces of equipment. Safety measures for legacy equipment require detailed appraisal.