Hydrogen can be a low-carbon fuel. When it is burned, it releases energy without producing carbon dioxide. It can either come from fossil fuel sources or produced using electricity and water. If the electricity used to produce it comes from a renewable source, hydrogen can have low carbon emissions. In the UK, the government is aiming to increase UK production and usage of low-carbon in some industries, and has been supporting the development of pipeline and storage infrastructure to enable transport and supply. What does the development of low-carbon hydrogen mean for rural areas? Jessica Sellick investigates.
Hydrogen is increasingly being positioned as a low-carbon fuel for sectors that are difficult to electrify. The UK government has been supporting the development of hydrogen production, storage and transport infrastructure, with natural gas operators developing regional pipeline networks to serve industrial clusters. Looking ahead, these regional systems could eventually be linked through a national transmission-level network. The development of this infrastructure may prove just as important as hydrogen production itself because it will influence where investment flows, which businesses can access hydrogen, and which places are connected to future energy markets. What’s the potential of a National Hydrogen Network, and what could it mean for rural areas?
What is low-carbon hydrogen and why does it matter now?
Back in 2022, the government’s British Energy Security Strategy described how ‘we have virtually no low-carbon hydrogen in our system today – but technology is making this a near-term reality with vast potential applications’.
According to National Grid, ‘hydrogen is a clean alternative to methane, also known as natural gas. It’s the most abundant chemical element, estimated to contribute 75% of the mass of the universe’. While it is present in nearly all molecules in living things, it’s been very scarce as a gas. Hydrogen can be produced from a variety of sources, including natural gas, nuclear power, biogas, and renewable energy such as solar and wind.
There are a rainbow of hydrogen colours, with different types of technology used to produce each:
- Green hydrogen is made by using clean electricity from surplus renewable energy sources, such as solar or wind power, to electrolyse water.
- Blue hydrogen is produced mainly from natural gas, using a process called steam reforming which brings together natural gas and heated water in the form of steam. As well as hydrogen, carbon dioxide is produced as a by-product and so carbon capture and storage (CCS) is used to trap and store this carbon.
- Grey hydrogen is created from natural gas, or methane, using steam methane reformation but without capturing the greenhouse gases made in the process.
- Pink hydrogen is generated through electrolysis powered by nuclear energy. Nuclear-produced hydrogen is also referred to as purple hydrogen or red hydrogen.
- Turquoise hydrogen is made using a process called methane pyrolysis to produce hydrogen and solid carbon.
- Yellow hydrogen is made through electrolysis using solar power.
- White hydrogen is naturally occurring, found in underground deposits and created through fracking.
- Black and brown hydrogen involves using black coal or lignite (brown coal) in the hydrogen-making process.
Understanding how hydrogen is produced is important because different forms of production have different carbon intensities, costs and infrastructure requirements. In the UK, most low-carbon hydrogen is expected to be either electrolytic hydrogen (i.e., produced through the electrolysis of water) or carbon-capture-enabled (i.e., produced through steam reforming of methane). This means that white, black and brown hydrogen are not currently part of the UK policy or market development and are generally omitted from strategic documents.
The British Energy Security Strategy (2022) sought to provide long-term signals for low-carbon hydrogen, including setting out ambitions to:
- Increase low‑carbon hydrogen production capacity to up to 10GW by 2030, subject to affordability and value for money, with at least half of this coming from electrolytic hydrogen.
- Run annual allocation rounds for electrolytic hydrogen, moving to price competitive allocation by 2025 as soon as legislation and market conditions allow, so that up to 1GW of electrolytic hydrogen is in construction or operational by 2025.
- Design new business models for hydrogen transport and storage infrastructure by 2025, which will be essential to grow the hydrogen economy.
- Level the playing field by setting up a hydrogen certification scheme by 2025, to demonstrate high-grade British hydrogen for export and ensure any imported hydrogen meets the same high standards that UK companies expect.
The British Energy Security Strategy built on the UK hydrogen strategy which was published in August 2021 and made the case for low carbon hydrogen and the importance of scaling up the hydrogen economy into the 2020s to realise economic benefits for the UK.
In February 2025, the Climate Change Committee (CCC) published its Seventh Carbon Budget (CB7), which sets out legally binding limits on UK greenhouse gas emissions for the period 2038 to 2042. In June 2026, the government passed CB7 into law, setting a limit of 535 MtCO₂e, including emissions from international aviation and shipping, as a binding target:
‘This would be an ambitious target, reflecting the importance of the task. But it is deliverable, provided action is taken rapidly. Our advice is based on the latest technological, social, and economic evidence; extensive sector modelling; engagement with stakeholders including businesses, trade unions, and farmers; and a citizens’ panel testing what would make changes accessible and affordable to households’.
CB7 sets out the role a range of low-carbon fuels can contribute to the pathway in areas that are less suited to electrification, including playing a key role in aviation and shipping. The document
itself contains almost 200 references to hydrogen, setting out how it can be produced from electrolysis or by methane formation with CCS.
‘…by 2040, our Balanced Pathway sees hydrogen play a small but important role, particularly in industrial sectors such as ceramics and chemical production that may find it hard to electrify. Hydrogen also has an important role within the electricity supply sector as a source of long-term storable energy that can be dispatched when needed and as feedstock for synthetic fuels. However, we see no role for hydrogen in buildings heating and only a very niche, if any, role in surface transport’.
Alongside this, the Department for Energy Security and Net Zero (DESNZ) updated its Low Carbon Hydrogen Standard (LCHS), a methodology for calculating lifecycle emissions from hydrogen production, which sets compliance requirements, including a Greenhouse Gas (GHG) emissions threshold for hydrogen to be defined as ‘low carbon’. The LCHS places a requirement on producers to generate hydrogen that meets a GHG emission intensity of 20g CO2e/MJLHV or less. More recently, in April 2026, the International Organization for Standardization (ISO) published a standard for hydrogen technologies, which contains a methodology for quantifying greenhouse gas emissions associated with hydrogen production from raw material extraction up to the production gate. It is anticipated that this will provide transparency for potential investors and customers, and clarity on how different products comply with the requirements of different countries.
In July 2025, the DESNZ published a hydrogen update to the Market, building on a previous update in December 2024. It sought to commit to continue driving deployment through Hydrogen Allocation Rounds and the launch of a Hydrogen to Power Business Model. It also confirmed a commitment of over £500 million in the Spending Review 2025 to support hydrogen infrastructure. It highlights how:
‘Since the last Hydrogen Strategy was published four years ago, we have seen a huge amount of progress in this sector but also change. Electrification technologies have moved on rapidly, pointing to a more focused and essential role for hydrogen complementing electrification in our energy system. Looking forward, hydrogen can help us decarbonise critical, hard-to-electrify industries, creating and retaining jobs, attracting investment, and positioning UK firms to take advantage of international opportunities. It can also provide low-carbon dispatchable power and inter-seasonal energy storage, to help balance a renewables-based power system’ (page 5).
In March 2026, the House of Commons Environmental Audit Committee published the findings of its inquiry into the Government’s approach to setting CB7 and the CCC’s statutory advice. It highlighted how CB7 ‘assumes rapid scale up of hydrogen and carbon capture and storage, particularly through industrial clusters, but delivery remains exposed to uncertainty over infrastructure sequencing, commercial readiness and long-term policy signals’ (page 24).
Low-carbon hydrogen matters because UK policy, carbon budget requirements, technological readiness and industrial demand are converging – but there is uncertainty about how quickly hydrogen and carbon capture, utilisation and storage (CCUS) can be deployed. If the CB7 pathway depends on the timely availability of these first-of-a-kind technologies at scale in the UK, how will hydrogen contribute to industrial decarbonisation between 2038 and 2042, and what does this all mean for rural areas?
What infrastructure is needed to produce, transport and store hydrogen?
The hydrogen production business model (HPBM) provides revenue support to hydrogen producers to overcome the operating cost gap between low carbon hydrogen and high carbon fuels. It is designed to incentivise investment in low carbon hydrogen production and encourage users to switch to low carbon hydrogen by making it a price competitive decarbonisation option. Administered by the DESNZ, and delivered by the Low Carbon Contracts Company (LCCC), the subsidy provides producers with price support (because low carbon hydrogen is more expensive than counterfactual fuels) and volume support (because the low carbon hydrogen market is nascent and demand uncertain). In Hydrogen Allocation Round 1 (HAR1), launched in December 2024, the key features of support included:
- Price support: provided by a variable premium payment per unit of hydrogen produced and sold. This is calculated as the difference between a bilaterally agreed Strike Price reflecting the cost of producing hydrogen with an allowed return on investment and a Reference Price reflecting the price of hydrogen achieved by the Producer. This model provides the opportunity for the level of subsidy to adjust as the hydrogen market develops – if the Producer can sell the hydrogen at a higher price, the variable premium model provides a lower subsidy.
- Volume support is provided by a sliding scale approach, in which the subsidy per unit of hydrogen is higher if hydrogen sales fall below a defined threshold. However, if volume falls to zero in any Billing Period of a month, no subsidy is received that month.
Other key features in the HPBM include:
- Reference price: used to calculate the variable premium in the Producer’s Achieved Sales Price (i.e., the amount paid by the offtaker for the hydrogen commodity), with a floor at the natural gas price. A higher floor of 1.2 x natural gas price is applied where the hydrogen is used for feedstock purposes (i.e., as an input material to produce another product). A Price Discovery Incentive is available to incentivise Producers to increase the Achieved Sales Price and therefore reduce the variable premium subsidy.
- Strike prices: in HAR1,electrolytic Producers were indexed to the Consumer Price Index (CPI).
- For volumes of hydrogen to qualify for subsidy, they must meet the Low Carbon Hydrogen Standard and be sold to a Qualifying Offtaker. Non-Qualifying Offtakers are i) Risk-Taking Intermediaries, ii) those that plan to export hydrogen for use outside the UK or import hydrogen to a location outside the UK and iii) those that inject hydrogen into the UK natural gas system.
- Limited costs for hydrogen transport and storage may be supported through the HPBM. These are agreed bilaterally with Producers, considering necessity, affordability and value for money. An LCHA Sales Cap is agreed bilaterally with each Producer. This caps the total volume (Qualifying and Non-Qualifying) that Producers can sell throughout the term of the LCHA. A Permitted Annual Sales Cap is also applied, which limits the amount of hydrogen that can be sold on an annual basis by each Producer.
- The LCHA expires on the earlier of the LCHA Sales Cap being reached or 15 years after the Start Date (or 15 years after the end of the Target Commissioning Window if that is earlier than the Start Date).
Final versions of the Standard Terms and Conditions and the Front End Agreement template for HAR1 were published in February 2025 – and the LCCC announced a cohort of 11 electrolytic hydrogen projects which is ‘the largest single allocation of such projects at a commercial scale announced simultaneously in Europe. This establishes Great Britain as a key player in advancing low carbon hydrogen technologies. These projects will play a pivotal role in decarbonising critical industries, while supporting regional economic growth and bolstering the UK’s journey to net zero’. The projects include Cromarty and Whitelee (Scotland) and West Wales which will have a combined capacity of 31.8MW, with other locations including Barrow-in-Furness (21.0MW), Bradford (24.5MW), High Marnham (9.3MW) and Plymouth (7.0MW).
In May 2023, the DESNZ published a market engagement document, setting out its approach for HAR2 – intended to support up to 875MW of capacity by the end of 2025 subject to affordability and value-for-money alongside HAR1. HAR2 was streamlined using lessons from HAR1, simplifying the application process and Agreeing an Offer stage. The HAR2 allocation round took place between December 2023 and April 2024. In April 2025, the DESNZ announced a shortlist of 27 projects invited to the next stage of the process. While final contracts were expected to be awarded in 2026, a written parliamentary answer in July 2026 indicated that HAR2 had not yet reached the Invite to Offer stage and that the government is “working hard…to start that stage as soon as possible, [with contract awards to follow] shortly afterwards”.
In December 2023, the DESNZ published a hydrogen transport and storage pathway. It built on the outcome of a consultation which found there was a need for a degree of strategic planning in hydrogen transport and storage. The pathway includes an ambition to support up to 2 hydrogen storage projects and associated regional pipeline infrastructure to be in operation or construction by 2030, and to conduct more analysis into the potential benefits of regional and a national transmission-level networks.
The main methods of transporting hydrogen are by pipeline, road, rail or boat, in the form of either gaseous or liquid hydrogen, or a hydrogen carrier such as ammonia. Research has suggested that over long land distances, pipelines will be substantially cheaper than road. National Gas estimates that it may be at least five times cheaper to repurpose existing gas pipelines for hydrogen than to build new pipelines. The National Transmission System (NTS) is owned and operated by National Gas, with distribution managed through 8 Gas Distribution Networks (GDNs) which are owned and operated by 4 companies.
There are several factors that influence the cost, safety and lifetime of repurposing gas pipelines for hydrogen:
- Pressure: gas operates at higher pressure in the transmission system and lower pressure in the distribution system. National Gas’ compression project explored the possibility of repurposing existing compressors for hydrogen blends and for 100% hydrogen, finding that existing compression equipment can be repurposed to support 2-5% hydrogen blends, but that 100% hydrogen will require new compressors at significant cost. In April 2025, National Gas announced that it was allocating over £350 million to upgrade gas compressors at 3 sites (Peterborough, St Fergus and Wormington).
- Materials: gas transmission pipelines are made from steel whereas distribution pipelines from polyethylene, steel, copper or cast iron – with compressors needed to push gas through the system. As part of its FutureGrid test facility, National Gas has found no evidence of materials, welds and fittings degrading with hydrogen.
- Transmission: SGN, a National Gas distribution company, has been delivering a Local Transmission System (LTS) futures study which in 2025 trialled a 30 km pipeline running from Grangemouth to Granton for transporting hydrogen. This included adding two new connections to the pipeline through ‘live hot works’ and conducting safety tests on pipeline fatigue, defects, performance and leakage. The final report, published in June 2026, concluded that the LTS can be successfully repurposed for hydrogen transport, with conversion costs estimated at £0.5-2.5 million per kilometre compared with £31.4-37.8 million per kilometre for new infrastructure. It was accompanied by a blueprint document, providing a methodology for repurposing existing pipelines and installations for hydrogen service.
- Distribution: the H21 project was a collaboration between National Gas and Gas Distribution Networks which examined leakage and safety risks from repurposing the natural gas distribution network for 100% hydrogen. While the project found the fire risk of hydrogen was lower, the explosion risk was higher because of metallic distribution pipes. The Iron Mains Reduction Programme which replaces these components found no greater risk of hydrogen than natural gas.
National Gas is leading Project Union, a 100% hydrogen transmission-level pipeline network. National Gas has been awarded £164 million from Ofgem for the engineering and design phase to look at how to connect hydrogen sites, industrial clusters, storage facilities and regional networks. The pipeline would be 2,500 km in length, extending from St Fergus in Scotland to Southampton in England and Milford Haven in Wales – and involve repurposing up to 25% of the existing National Transmission System (NTS). Project Union is taking places in stages, with the first section, East Coast, expected to create more than 300 miles of underground pipeline connecting sites in Teesside, Yorkshire and Humber, the East Midlands and East Coast of England. It is intended to transport hydrogen from multiple producers, connect industrial users and storage sites, anchor a national hydrogen supply chain, and support decarbonisation across the region. In September 2026, National Gas announced that Project Union is entering a new phase, with a 350 mile 100% hydrogen section connecting North East Scotland to Teesside entering into advanced engineering design.
Eventually, a UK national hydrogen network may allow UK producers to export to Europe. Indeed, National Gas is already part of the European Hydrogen Backbone (EHB) initiative, a consortium of 33 energy operators which aims to promote collaboration between countries on hydrogen pipeline development. More broadly, the European Commission, through REPowerEU, is seeking to diversify gas supplies including through higher levels of hydrogen, setting a target of generating 20 million tonnes of renewable hydrogen per year by 2030. Back in 2024, analysis found over a fifth of all European projects were stalling or being cancelled (equivalent to 20.3% of its planned pipeline) due to high costs, failure to obtain funding and lack of demand. The development of a national hydrogen network may allow UK producers to export to Europe.
The International Energy Agency’s (IEA) Global Hydrogen Review tracks hydrogen production and demand worldwide. The latest release signals how:
- The conflict in the Middle East has disrupted global production and trade of hydrogen-based products: the region is home to around one-sixth of global hydrogen production and several refineries and petrochemical plants have halted operations. Much of the production output is exported, meaning the consequences of the conflict reach far beyond the region.
- Hydrogen-based fuels can help to diversify the energy sector, but their impact will not be immediate: governments can support the development of new supply chains for low-emissions hydrogen and hydrogen-based products, but their uptake will not happen overnight and it will take time to build the scale and infrastructure needed to make a significant contribution to energy markets.
- Low-emission hydrogen progressed in 2025, growing by 20% to reach almost 1 Mt, but this is concentrated in a relatively small number of projects. Persistent barriers – particularly around policy and regulatory implementation, targeted support and enabling infrastructure are preventing sustainable growth.
- Demand for low-emissions hydrogen remains the crucial missing piece for the sector to take off: demand creation is reported by project developers as a key barrier to investment, while offtake agreements remain insufficient to unlock large-scale investment.
The Review is part of the IEA’s Clean Energy Ministerial Hydrogen initiative which also includes a hydrogen production and infrastructure projects database and a hydrogen tracker.
Low‑carbon hydrogen in the UK relies on scaling production and developing the transport and storage infrastructure to move from early projects into industrial use. Trials across the transmission and distribution networks show that parts of the existing gas system can be repurposed, while major investments such as Project Union indicate a shift toward a future national hydrogen network. Choices made in the next few years will determine which areas are connected and able to participate in this emerging market. These developments set the wider context for considering how hydrogen deployment may intersect with rural areas, and their future role in the UK’s energy system.
What does low carbon hydrogen mean for rural areas?
Back in 2022, the Scottish Government, Highlands and Islands Enterprise and Scottish Enterprise commissioned a hydrogen production and export locations site requirements study. This concluded that island and rural areas may be particularly well suited to hydrogen production where high energy costs and constrained infrastructure make local generation and use more commercially attractive. Indeed, the study identified opportunities for these locations to become future hydrogen export hubs serving Scotland, the rest of the UK and Europe. Many of the assets needed to support a low-carbon hydrogen economy are available in rural and coastal areas: renewable energy generation, land availability, geological storage capacity, ports and energy infrastructure.
Hydrogen development is already taking place in a number of rural and coastal locations. Publicly funded projects are operating in Orkney, Shetland, the Outer Hebrides and Ceredigion; while private sector investment is also taking place with examples including Hynamics and Four Zeros Energy’s green hydrogen project at Exxon Mobil petrochemical complex in Fawley and Severn Valley Railway hydrogen powered shunting engine. However, the most important question is not whether rural areas are participating in the hydrogen economy, but what role they play within it. Will rural areas primarily host hydrogen infrastructure, or will they capture a meaningful share of the economic value being created?
In March 2025, Cenex and the Royal Agricultural Society of England (RASE) examined potential hydrogen demand across the agricultural sector and within the proposed East Coast Hydrogen network. Their analysis found little evidence of immediate demand for hydrogen-powered agricultural machinery, grain drying, livestock housing or other on-farm applications. Red diesel remains the dominant agricultural fuel and the report concluded that alternatively fuelled agricultural vehicles are unlikely to see widespread deployment before 2030 without further government intervention. Interestingly, researchers found farmer interest was not in consuming hydrogen but in producing it. The research found considerable interest amongst farmers in generating hydrogen locally from renewable electricity, mirroring existing approaches to anaerobic digestion and biogas production. However, significant barriers remain, including the cost of electrolysers, expensive refuelling infrastructure and lengthy planning and installation times for permanent facilities. While the report suggests pipeline-delivered hydrogen could become a competitive fuel source for horticultural heating from the late 2030s onwards, there is currently no immediate business case for large-scale hydrogen deployment across most agricultural sectors.
These findings chime with earlier feasibility work. For example, a study commissioned by Scottish Enterprise found that a bespoke wind-ammonia production system capable of producing around 50 tonnes of ammonia per annum would require capital investment of approximately £1.2-£2 million. Revenues to farmers were estimated at approximately £35,000 per annum for smaller installations and up to £100,000 per annum for larger systems, with payback periods ranging from 15 to 30 years depending on local circumstances. While technically feasible, the study highlighted the difficulty of converting hydrogen production into commercially attractive rural business opportunities without ongoing market development and demand growth.
Alongside questions about economic value are wider questions about land use. In March 2026, the House of Commons Environmental Audit Committee published the findings of its inquiry into the Government’s approach to setting CB7 and the CCC’s statutory advice. The Committee warned that hydrogen, sustainable aviation fuels, bioenergy, carbon capture and agricultural production all depend on access to the same constrained systems and that poor policy alignment risks placing competing demands on land and infrastructure:
‘Our evidence highlighted growing competition for limited low-carbon electricity, sustainable feedstocks and land, with delivery of CB7 reliant on multiple sectors drawing on the same constrained systems. We were warned that assumptions about the availability of sustainable aviation fuels, hydrogen, bioenergy and engineered removals are closely interlinked with wider energy system capacity and land-use choices, and that misalignment between policies on aviation, energy, agriculture and industrial decarbonisation risks placing competing demands on the same resources. Without clear prioritisation and sequencing of infrastructure, generation and end-use demand, policies in different sectors risk working at cross-purposes, weakening delivery confidence and increasing the risk that progress in one area displaces or constrains decarbonisation elsewhere’ (pages 19-20).
The Committee further included a section on land use and agriculture, highlighting how:
‘Land use decisions increasingly sit at the intersection of climate mitigation, food security and rural livelihoods, and failure to integrate these objectives risks creating tensions in rural communities and weakening trust in the transition. Credible delivery of CB7 therefore depends on clearer cross-government prioritisation of land use, robust and consistent sustainability standards for biomass and sustainable aviation fuel feedstocks, and long-term policy and funding frameworks that enable farmers and landowners to manage competing demands on land in a stable and economically viable way’ (pages 29-30).
The Committee concluded that land use decisions increasingly sit at the intersection of climate mitigation, food security and rural livelihoods, and that delivery of carbon budgets will require clearer cross-government prioritisation and long-term funding frameworks. This raises important questions for rural businesses and landowners. If hydrogen production facilities, storage sites and transmission pipelines are increasingly located in rural areas, how can local economies capture value from that investment? Which sectors are most likely to benefit—agriculture, manufacturing, ports, logistics or energy generation? And how can hydrogen development be balanced alongside other demands on land, including food production, biodiversity recovery, renewable energy and environmental land management?
Geography may prove particularly important. Investment has been concentrated around industrial clusters, ports and strategic energy corridors. However, not all rural areas will sit within these emerging networks. Some locations may become important production and storage hubs, while others remain largely outside hydrogen infrastructure investment. For rural areas, this raises important questions about which places will be connected to future hydrogen networks and which will remain outside them. As decisions are made about future transmission routes and storage capacity, there is a risk that new spatial inequalities emerge between areas connected to hydrogen networks and those left outside them.
Funding is another significant uncertainty. Moving from pilot projects and regional clusters to a functioning hydrogen economy will require substantial investment in production, storage and transport infrastructure. However, uncertainty remains around how this infrastructure will be funded. The Government consulted on a proposed Gas Shipper Obligation (GSO) in 2025 as a potential long-term funding mechanism for hydrogen production support. The LCCC is expected to become the GSO administrator, with the planned levy on gas shoppers licensed in the UK expected to come into effect in 2027. Meanwhile, the Hydrogen Transport and Storage Business Model, originally expected in 2024, has been delayed, though in a subsequent statement in October 2025 the government reiterated its support for the National Energy Systems Operator (NESO) to produce a strategic spatial energy plan (by the end of 2026) and for the UK’s first regional hydrogen network to become operational from 2031. In the meantime, the continuing uncertainty over subsidy distributions and timescales has led operators to pause planning applications and investment decisions. For rural areas, this raises important questions about the feasibility of early-stage pipeline projects and investment returns.
However, perhaps the greatest uncertainty remaining is demand. The International Energy Agency (IEA) identifies demand creation as one of the principal barriers to hydrogen deployment globally. At the same time, the Climate Change Committee’s CB7 sees hydrogen playing a focused role in hard-to-electrify sectors such as industry, energy storage and synthetic fuels, while identifying little or no role for hydrogen in domestic heating or surface transport. If future demand remains concentrated in industrial sectors, many rural communities may find themselves closer to hydrogen infrastructure than hydrogen markets.
Rural areas already have a strong track record in renewable energy generation and energy storage. The next phase of hydrogen policy will determine whether rural areas become active participants in a new energy economy or host locations through which the infrastructure passes. How can rural businesses participate in hydrogen supply chains? How can rural communities secure economic returns from infrastructure rather than simply hosting it (e.g. through community benefit schemes)?
Where next?
A significant amount of the policy, regulatory and market framework underpinning hydrogen remains in development. At the same time, strategic planning responsibility for hydrogen transport and network infrastructure is transferring from the DESNZ to NESO, with NESO’s first output – the Strategic Spatial Energy Plan – due by the end of 2026; though the DESNZ retains the decision-maker for business model support. All of this work will have a major influence on where and how hydrogen develops over the next decade and beyond. Notwithstanding how hydrogen is expected to play a relatively focused role in the UK’s future energy system overall, how can policymakers and industry build sufficient hydrogen demand to unlock investment at scale while ensuring the benefits extend beyond industrial clusters? And in the countryside, how can rural businesses and communities capture greater value from hydrogen production, storage and transport infrastructure? Which rural areas will be connected to future hydrogen networks, and which may be left outside emerging hydrogen corridors? Without further government commitments soon, will we see hydrogen play less of, or a diminishing role in, the UK’s transition to net zero?
