In May 2025, the Net Zero Energy and Transport committee held four evidence sessions on the potential role of low carbon hydrogen at the Grangemouth industrial site. The role that hydrogen could play in a low carbon future is considered in two new SPICe blogs – the first considers the options for the supply and transportation of hydrogen, and the second looks at the potential uses for hydrogen fuel.
The blogs act as an update to the previous SPICe publications from 2001:
Hydrogen now and in the future
Hydrogen is currently used in the UK as a feedstock in the chemicals industry (a raw material in chemical production) and as part of the crude oil refining process, with a very small amount of hydrogen used as a fuel in transport.
There are thought to be very limited natural sources of pure hydrogen (more on this below) and thus it has to be manufactured. Almost all of this involves the use of fossil fuels; globally it is 47% from gas, 27% from coal and 22% from oil with a very small remainder made using electricity.
The latest figures record 0.62 Mt/year of hydrogen produced in the UK. Over 90% is from reforming, natural gas (mainly steam methane reformation (SMR)), with the rest resulting as a by-product from ethylene and styrene production. In Europe there was a total of about 11Mt of hydrogen produced in 2023, with major producers being Germany (1.98Mt), the Netherlands (1.48Mt) and Poland (1.18Mt). Hydrogen production in China in 2023 was 97Mt, again, almost all made using fossils fuels.
In Scotland, there is currently hydrogen produced via SMR at the Grangemouth industrial site and also produced as a by-product in the production of ethylene at the Mossmorran industrial site.
Production via these means produces GHG emissions and is termed ‘grey hydrogen’. While the production may be polluting, the combustion of hydrogen as fuel does not release GHG emissions, only water, and as a result, there is an increasing interest in hydrogen as a low carbon source of energy. There are a variety of different methods of production being considered, each with its own colour code.
The currently prominent and prospective methods of production are:
- Grey hydrogen: hydrogen produced using natural gas and from steam methane reformers (SMR), resulting in GHG emissions. This grouping sometimes also includes hydrogen produced as a by-product in oil refining. The Scottish Government use the term ‘unabated hydrogen’.
- Black / Brown hydrogen: produced using coal, resulting in GHG emissions.
- Blue hydrogen: the same as grey hydrogen, but the carbon is captured and stored (CCS). CCS will likely not capture 100% emissions (more information below). The Scottish Government sometimes use the term ‘low-carbon hydrogen’.
- Green hydrogen: produced using electrolysis, where electricity is used to split water into hydrogen and oxygen. When using renewable electricity this is termed green hydrogen. The Scottish Government use the term ‘renewable hydrogen’.
- Pink (or purple) hydrogen: electrolysis to produce hydrogen but using electricity from nuclear power.
- Gold/White hydrogen: Taken from natural subsurface accumulations, sometimes termed geological hydrogen. Until recently this has been thought to be very rare but there have been recent discoveries of geological hydrogen in Mali, Australia, the USA and France.
The following sections looks in more detail at the most prominent means of producing low carbon hydrogen being considered in Scotland.
Green hydrogen
Electrolysis is the process of using electricity to split water into hydrogen and oxygen. With an increasing abundance of renewable energy in Scotland, there is potential for electrolysers to be used to make renewable or green hydrogen. For more information on the process see the previous SPICe blog.
The Scottish Government set out that:
‘There are two main factors that will impact the cost competitiveness of green hydrogen production: capital cost reductions and reductions in the cost of renewable power … Capital costs are expected to fall as a result of technology improvements such as electrolyser efficiencies and a significant scale-up of supply chain capacities driven by the automated production of electrolysers and other supply chain key components.’
Electrolysers can range in size from small, appliance-size equipment suited for small-scale distributed hydrogen production to large-scale, production facilities linked to wind or solar farms. In 2023, the largest electrolyser manufacturers by capacity were a mix of American, Chinese and European companies (including ITM Power based in Sheffield).
While developments in electrolyser technology are important, it is the cost of electricity which is most critical to the overall cost of green hydrogen, making up an estimated 73% of the overall cost. As with so many other parts of the prospective green transition it is the supply and cost of electricity that is of central importance.
The Scottish Government has commissioned research via ClimateXChange which ‘explores the costs of producing green hydrogen in Scotland, Chile, Norway, Morocco and France and the northeast region of the USA and exporting to northwest Europe (Rotterdam)’. It considers transport by pipeline, shipping as ammonia (derived from hydrogen) or as compressed hydrogen. It concluded that:
‘It is more costly to produce hydrogen in Scotland as compared to all other case study countries. This is because the cost of offshore wind generated power in Scotland is higher than the other low carbon power technologies used.’
The lowest cost of hydrogen production is found to be in France using nuclear energy. In the Study, the production of hydrogen is modelled as coming from offshore wind in Scotland, nuclear energy in France, hydroelectricity in Norway, solar in Morocco and onshore wind in Chile and the USA. Despite its higher costs, there is still thought to be a place for Scottish exports:
‘if the cost of production remains higher in Scotland than in other European countries, Scotland will likely still be a market player as France and Norway alone cannot meet EU hydrogen import targets’
Green hydrogen is thought to be the lowest carbon means of producing hydrogen with any associated emissions almost entirely contained in the embedded emissions of the renewable technology.
The UK Government have an explicitly ‘twin-track approach’ to hydrogen production policy, supporting green and blue. Although not explicitly in policy documents, the Scottish Government has been thought to have a similar approach. According to the UK’s Scottish Affairs Committee report on Hydrogen in Scotland:
‘The UK and Scottish Governments have taken a twin track approach to hydrogen… the dual approach supported “both electrolytic (green) and CCUS enabled (blue) hydrogen’
In Scotland, there has in recent years been a pivot in government attention to green rather than blue hydrogen. The then Cabinet Secretary for Net Zero said in January 2023:
‘That area has changed dramatically over the past year. If we were having this discussion last year, I would be saying that blue hydrogen would probably play a big part in the early development of the hydrogen economy. What has significantly changed over the past year is that, because of gas prices and so on, there has been a big switch in the sector to being much more focused on green hydrogen, because its potential production costs have dropped significantly. Companies that previously focused on blue hydrogen are now looking at going straight to green hydrogen, because the cost base has dropped sufficiently.’
Estimates as to the role of the different hydrogen production methods in the future have typically found green hydrogen playing a much bigger role than any other. For example, the consultants Wood Mackenzie estimate that globally by 2050 green hydrogen will entail over 80% of total hydrogen produced. Scottish Enterprise estimate a similar figure for the planned hydrogen production capacity in Scotland. In other regions with lower cost natural gas (like the Middle East and North America) some estimates suggest blue hydrogen may be more common.
The Scottish Hydrogen Assessment recognised green hydrogen production as the largest contributor to jobs in all scenarios with between over 70,000 to 310,000 jobs in its most ambitious scenarios relative to less than 20,000 for blue hydrogen.
In Scotland, the Hydrogen Innovation Scheme (part of the Emerging Energy Tech Fund) has offered grants totalling over £7m to 31 projects. They also fund a Hydrogen Business Development Service delivered through the Energy Technology Partnership. In September 2024, a new support fund for green hydrogen was announced with up to £7m available. Applications were open until the end of September with a maximum of £2m in match funding on offer.
At the UK level, the Hydrogen Production Business Model scheme, awarded its first contracts (15 years in length) in July 2022 (two in Scotland), in Hydrogen Allocation Round 1 (HAR1):
‘The 11 projects have been agreed at a weighted average strike price of £241/MWh (£175/MWh in 2012 prices). This compares well to the strike prices of other nascent technologies such as floating offshore wind and tidal stream.’
There is an HAR2 shortlist with 27 electrolytic projects, including various Scottish projects, hoping for a contract. One of those looking for a contract is a green hydrogen project at Grangemouth. A project being described as the largest green hydrogen plant in Europe, that at Kintore, Aberdeenshire, is not on the HAR shortlist;. It received planning approval from Aberdeenshire Council in April 2025, with an initial 0.5GW phase, possibly scaling up to 3GW.
These projects are based on land, but there is potential for green hydrogen production at sea, alongside offshore wind farms. The attraction is that the electricity used could by-pass the national grid and its associated charges, while the barriers include the practicalities of carrying out operations at sea, and sourcing electrolysers that have large capacity but are compact. According to the Hydrogen Action Plan in 2022:
‘Many of the successful applicants for ScotWind leases are considering hydrogen production as part of their plans.’
There have been challenges in the sector with the fourth phase of the world’s largest offshore wind farm (Dogger Bank) dropping a plan for a green hydrogen project and solely focusing on the sale of electricity.
Blue hydrogen
For a full description of blue hydrogen production see the previous SPICe blog. As highlighted, blue hydrogen is essentially the conventional means of producing hydrogen with carbon capture and storage (CCS) added on. Its progress is therefore, very much tied to the economics and scaling of CCS. In the UK, the HyNet hub in Merseyside and the East Coast Cluster hubs in Teesside are part of the UK Government’s Track 1 CCS support process. The Acorn CCS Project in Scotland had, controversially, only been included on an ‘ambiguous’ reserve list, but in June 2025 it received £200m in development funding from the UK Government in order to reach a final investment decision by the end of this parliament. The Track 1 projects have progressed in their financing, with both the Teesside and Merseyside projects having reached final investment decisions and construction expected to begin in 2025.
The UK Government is thought to be more open to the potential of blue hydrogen than other parts of Europe with only half of their 2030 production target earmarked for green hydrogen and their Net Zero Hydrogen Fund including blue hydrogen projects within its scope. Storegga, one of the companies behind Acorn, have some early-stage plans for blue hydrogen projects alongside Acorn (if it becomes reality). HyNet includes two blue hydrogen projects — Essar Energy Transition’s (EET) 350-megawattHydrogen Production Plant 1 and 1-gigawatt Hydrogen Production Plant 2 — that will use autothermal reformers to split natural-gas molecules into hydrogen and carbon.
The NZET committee heard that in Scotland, blue would likely be available at scale earlier than green, with the majority of witnesses seeing a role for both blue and green. The Scottish Hydrogen Assessment in 2020, forecast that blue hydrogen was likely to be lower cost (than green) in the near term, but the difficulty in making it fully zero carbon and the expectation of the cost of green hydrogen falling, meant that they viewed blue as more likely to be a ‘transition technology’. Blue hydrogen is unlikely to ever be as low carbon as green, and analysis suggests it can only be considered low carbon (specifically 50 grams of CO2 equivalent per megajoule of hydrogen) ‘when emissions are minimized at all stages: upstream, midstream, and during production’. The UK Government and wider environmental regulators, are expecting the industry to achieve at least 95% capture, although to capture at a rate above 90% is thought to impact the economics of the technology. Blue hydrogen also relies on the exploitation of fossil fuels which, of course, have finite availability and are liable to geopolitical price spikes.
There are storage considerations for both the CO2 captured and the hydrogen produced. For the Acorn project the plan is for storage in the sandstone rock of depleted gas fields, 2.5km under the seabed. Carbon storage licenses are administered by the North Sea Transition Authority with 21 licences in depleted oil and gas reservoirs and saline aquifers granted in 2023. The considerations around hydrogen storage are considered in the transportation and storage section below.
Other shades of hydrogen in Scotland
As far as the other shades of hydrogen go, in Scotland there is little interest in pink hydrogen as the last remaining nuclear power plant in Scotland, Torness in East Lothian, is due to cease operation in 2030, and the policy of the current Scottish Government is to oppose any new nuclear plants. There are companies currently looking for white/gold hydrogen (sometimes termed geological hydrogen) in Scotland.
Hydrogen transportation and storage
A critical consideration for the prospective Scottish hydrogen industry, is the means by which Scottish hydrogen would reach demand centres, at home and abroad. Currently, 87% of European hydrogen production is for ‘on-site captive consumption’ and thus there is limited need to consider transportation needs. By 2050, however, it is estimated that about two thirds of hydrogen consumed will be transported over long distances (defined as greater than 1,000km), from lower cost production sites.
Currently the hydrogen that is transported goes by road, however in the future, options for transporting larger amounts include by boat, or by pipeline. Transportation of hydrogen over long distances is, unlike oil or natural gas, ‘not an easy task’. This is because it has low ambient density, which means it must be compressed/liquified, and that it is easily dispersed (leaky) and combustible when combined with air.
The International Energy Agency (IEA) view is that:
‘where feasible, hydrogen will generally be transported by onshore or offshore pipelines, as it is the most efficient and affordable option for relatively short distances’.
Research commissioned by the Scottish Government and published in January 2024, concluded that, pipelines will be most cost-effective, particularly if a re-purposed pipeline is used (as opposed to one purpose-built) and the line is fully utilised (it transports hydrogen on a consistent basis). Compressed hydrogen on a ship may become a cost-competitive option in the future.
The CCCs Seventh Carbon Budget analysis modelled:
‘ …a transmission network which connects industrial clusters, starting in the north of England in the early 2030s and expanding to Scotland, Wales, and other parts of England over the remainder of the decade.’
‘Project Union’ is the name given to proposals for the development of local networks to connect existing industrial clusters i.e. Grangemouth etc. via pipeline with ‘strategic hydrogen production and storage sites’. Eventually these local networks would be connected by a GB wide 1,500-mile hydrogen transmission network. These plans are being led by National Gas Transmission (the company that owns and operates the existing gas transmission system) and involves repurposing parts of the 5,000-mile gas National Transmission System to carry 100% hydrogen.
It is suggested that Project Union could be operational by the ‘early 2030s’ and would connect to the proposed European Hydrogen Backbone, an initiative which brings together gas network operators from around Europe. Its aim is to connect major sources of demand (industrial clusters) with the anticipated major sources of supply. The sites for hydrogen production depend in part on the method of production, with green hydrogen production projected to be more dispersed, while blue hydrogen production may be more geographically limited.
The Net Zero Technology Centre (created as part of the Aberdeen City Region Deal, UK and Scottish Government funding) has set out proposals for a ‘hydrogen backbone link’ that could transport hydrogen via a pipeline from Scotland to Central Europe. The project is sometimes termed the Scotland-Germany Hydrogen Backbone Link as this is where the terminus is expected to be located and where many of the potential sources of demand are.
The SoutH2 Corridor is a plan to transport hydrogen from North Africa, to Italy, Austria and Germany, and the H2Med project sees a hydrogen network across the Iberian peninsula, France and North West Europe. These plans generally entail the northern transportation of green hydrogen made from wind and solar in Southern regions. They use a mix of re-purposed existing networks and new dedicated infrastructure.
A key consideration in the development of all these networks is the matching of supply with demand and whether investments will be made in hydrogen transport networks when levels of demand are uncertain. The roll-out of existing European gas networks in the mid-20th century, was propelled by the superior economics of natural gas, and the judgement that widespread uptake was assured once networks were built.
Alongside the development of transportation logistics, the storage of hydrogen is critical to a functioning industry. The Hydrogen Transport and Storage Networks Pathway from the UK Government in 2023, sets out that in the short term ‘the hydrogen economy needs onshore salt cavern storage’ (more on this on the accompanying blog on hydrogen demand).
The lack of certainty over the future of hydrogen transport and storage was a common complaint in the NZET evidence sessions. The National Energy System Operator (NESO) is due to publish its first Strategic Spatial Energy Plan in 2026. This is focused on the generation, storage and distribution of electricity and hydrogen, for example where a hydrogen transportation network should run and where the best locations for storage are. The Scottish Government is bullish on the prospect of Scotland being a large exporter of hydrogen. Their Trading Nation report set out plans in 2024. At the time, the Acting Cabinet Secretary said :
‘This plan focuses on the significant international trade opportunities presented by hydrogen and sets out the key steps required to secure and maximise the economic benefits’
There are, however, some that are more sceptical about the potential for export. Jim Skea, the current Chair of the Intergovernmental Panel on Climate Change (IPCC), giving evidence to the Economy and Fair Work Committee in 2023 (in his capacity as Just Transition Commission Chair):
‘We might come on to this later but, for example, in relation to hydrogen, the assumption is that a lot of the market might lie in export opportunities. We did not see the evidence there about where those markets might be to justify that assumption’
Chris Stark, the former Chief Executive of the CCC, giving evidence to the NZET committee in 2024:
‘The one thing that I would say relates to the Scottish Government’s plans to be a big export industry for hydrogen. I am rather more dubious about that, and I would not want us to hitch our wagon to that particular horse … without some serious thought being given to it’
Niall Kerr, SPICe