Download pdf - 1 MB

Authors

Szebasztian Csernik-Tihn, Gemserv
Jamie Mitchell, Gemserv
Joshua Wilson, Gemserv
Harry Morton, Gemserv

Published

28 May 2025

Contact

Dr Nicola Dunn

Project Manager - Climate and energy

nicola.dunn@ed.ac.uk

Back to Publications

Review of demand for hydrogen derivatives and products

Research completed October 2024

DOI: http://dx.doi.org/10.7488/era/5798

Executive summary

Aims

Scotland has abundant renewable energy resources that could supply significantly more energy than it consumes. This presents a substantial opportunity for Scotland to become a net exporter of low-carbon energy, boosting employment, supporting economic growth and helping to deliver international decarbonisation.

In our research, we review, assess, and rank the potential of technologies that could enable cost-efficient domestic and international trade of hydrogen, as well its derivatives and products. Hydrogen derivatives are substances that contain hydrogen, manufactured for the purposes of transporting energy and converted back to hydrogen before use (e.g. ammonia). Hydrogen products are anticipated to be used directly, with no need for reconversion (e.g. sustainable aviation fuel). Further, we identify offtake sectors and countries, assess the scale of demand in potential markets, and identify gaps and opportunities in domestic and international policy.

We carried out desk-based research and targeted stakeholder interviews to gather data and review a range of hydrogen derivatives and products.

Findings

Hydrogen and derivative offtake markets

Scotland’s hydrogen potential poses an unprecedented opportunity to strengthen domestic industrial capabilities and cut greenhouse gas emissions. Hydrogen production capacity is anticipated to exceed Scottish demand in the future.
Industrial clusters in Scotland, England and Wales all provide a large local market for hydrogen and its derivatives and products. Existing industrial demand, proximity, and a similar regulatory framework offer key advantages over mainland Europe.
The European Union and its member states are unlikely to meet their low-carbon hydrogen demand on their own, creating an export opportunity for Scotland. Germany and the Netherlands are likely to become the dominant hydrogen offtakers in Europe. But because international trade requires extensive infrastructure and harmonised low-carbon certification frameworks, we identify domestic hydrogen offtake markets as having greater potential.

Hydrogen derivatives

Subsea hydrogen pipelines are critical to enhancing the competitiveness of Scottish hydrogen for trade within Europe. Alternative delivery methods and hydrogen derivatives have substantially higher costs.
Ammonia is expected to be the dominant hydrogen derivative in the medium to long term for global trade. This is due to high technical maturity, relatively high roundtrip efficiency, low production and transport costs, and established global market.

Hydrogen products and end use cases

Industry – including oil and biofuel refining, ammonia, and synthetic fuel production – will be the biggest driver of hydrogen demand in 2030 in both the EU and the UK. By 2045, other sectors like aviation, shipping, power generation are also expected to be major players in the hydrogen economy.
Some end-use sectors, such as chemicals and aviation, will be able to use hydrogen derivatives and products directly, avoiding substantial costs on reconversion. Emerging policies in the UK and in the EU make the market highly attractive to potential hydrogen exporters.
Synthetic methanol will be key to decarbonising existing industrial uses of methanol and in initial low-carbon maritime projects. However, uncertainty around maritime policy and the future availability and cost of biogenic CO₂ remains.
In the long term, hydrogen is also expected to play a significant role in power generation, where it could replace natural gas and other fossil fuels in peaking plants.
Hydrogen-based Sustainable Aviation Fuels (SAF) are well-placed to decarbonise the aviation sector due to compatibility with existing infrastructure, policy support in the UK and Europe, and no commercially viable low-carbon alternatives.
The main low-carbon alternatives to hydrogen include Carbon Capture, Utilisation, and Storage (CCUS) and bio-based technologies.

Recommendations

Stimulate demand by improving alignment – Align the UK and EU Emissions Trading Systems to avoid potential carbon taxes on UK products including maritime fuels. The timely launch of the UK Carbon Border Adjustment Mechanism (CBAM) is also critical.
Stimulate demand by supporting trials and demonstration projects – Subsidy schemes, such as the Hydrogen Innovation Scheme, trials and demonstration projects help to create learnings, improve investor certainty and get initial projects off the ground.
Support infrastructure – Support key new-built and repurposed infrastructure projects including a core UK hydrogen network, ports, terminals, hydrogen boilers, refuelling stations and salt cavern storage.
Enhance competitiveness of Scottish hydrogen – To effectively compete with renewable rich regions, Scotland needs to meet a lower levelised cost of hydrogen. High electricity prices are one of the biggest weaknesses in Scotland’s hydrogen ambitions.
Reform the planning and permitting regime – Streamline complex processes where possible to avoid unneeded congestion and accelerate decarbonisation. Work with the Health and Safety Executive (HSE) to develop the safety case for hydrogen.
Optimise low-carbon policy frameworks – The Hydrogen Production Business Model needs to be optimised to interact with other low-carbon policy frameworks, such as the Contracts for Difference Scheme, Hydrogen T&S Business Models and the H2P Business Model.
Co-ordinate with the EU – Infrastructure projects have long associated lead times and limited flexibility once approved. Therefore, coordinating infrastructure deployment with the European Hydrogen Backbone and port infrastructure is essential.
Continue progress on low-carbon certification – A mutually recognised low-carbon hydrogen standard is critical to the success of hydrogen trade.
Engage local communities – Continue to engage with local communities and improve public understanding of hydrogen’s role in a net zero energy system.
Set out strategy on hydrogen trade – The Scottish Government could work with the UK Government on a clear strategy for how to develop hydrogen export capacity.

Glossary and abbreviations

Glossary

Dehydrogenation	The process of removing hydrogen from a chemical or organic compound.
Electrolytic (also known as green) hydrogen	Hydrogen produced by splitting water into hydrogen and oxygen molecules using electricity.
Gravimetric energy density	The amount of energy per unit mass of substance, usually expressed in terms of Watt-hours per kilogram (Wh/kg) or megajoules per kilogram (MJ/kg).
Hydrogen	Hydrogen is the most abundant and smallest molecule in the universe, made up of two hydrogen atoms.
Hydrogenation	The chemical process of bonding hydrogen and another compound.
Hydrogen derivatives	Substances that contain hydrogen and at least one other element. They are manufactured for the purposes of transporting energy and are converted back into hydrogen before use.
Hydrogen products	Substances that contain hydrogen and at least one other element, but which are intended to be used directly, with no need for reconversion to hydrogen.
Low-carbon alternative	In this report, low-carbon alternatives include all technologies that are economically viable substitutes to hydrogen solutions, such as electric, CCUS and biomass technologies.
Method of transport	Compressed hydrogen molecules can be transported in many ways, including through pipelines, ships and tube trailers.
Technology Readiness Level (TRL)	TRL is a scale used to identify, rate and compare the technical maturity of different technologies, with 1 being the least mature and 9 being the most mature and widely deployed technology.
Volumetric energy density	The amount of available energy per unit volume of substance. Often shown in terms of Watt-hour per litre (Wh/L) or Megajoules per cubic meter (MJ/m³).

Abbreviations

BEIS	Department for Business, Energy & Industrial Strategy
BECCS	Bioenergy with Carbon Capture and Storage
CAPEX	Capital expenditure or capital cost
CBAM	Carbon Border Adjustment Mechanism
CCGT	Combined Cycle Gas Turbine
CCS	Carbon Capture and Storage
CCUS	Carbon Capture, Utilisation and Storage
CO2	Carbon dioxide
DESNZ	Department for Energy Security and Net Zero (formerly known as BEIS)
ETS	Emission Trading Scheme
FCV	Fuel Cell Vehicle
GHG	Greenhouse gas
HEFA	Hydro Processed Esters and Fatty Acids
HPBM	Hydrogen Production Business Model
HVDC	High Voltage Direct Current
LH₂	Liquified hydrogen
LOHC	Liquid Organic Hydrogen Carrier
LPG	Liquified Petroleum Gas
MCH	Methylcyclohexane
MgH₂	Magnesium Hydride
NH₃	Ammonia
RFNBO	Renewable Fuels of Non-Biological Origin
TRL	Technology Readiness Level

Introduction

Context

Scotland has abundant renewable energy resources which could supply significantly more energy than is consumed nationally. This presents an opportunity for Scotland to become a net exporter of low-carbon energy, potentially boosting employment and economic growth, and helping to deliver international decarbonisation.

In addition to electricity interconnectors, low-carbon energy is expected to be exported via mediums including low-carbon gases such as hydrogen. Scotland has ambitions to produce 5 GW of low-carbon hydrogen by 2030, rising to 25 GW by 2045 [1]. As emphasised by the Scottish Hydrogen Assessment, Scotland has the potential to grow a strong hydrogen economy [2]. The Scottish Government signalled its ambition for Scotland to ‘become a leading producer and exporter of hydrogen and hydrogen derivatives for use in the UK and in Europe’ [3]. Projections estimate that 75% of this production (by volume) could be exported to UK and European markets [3] [4]. This rise in production is expected to coincide with hydrogen demand growth in the rest of the UK and the European Union (EU), with the EU targeting 20 Mt of hydrogen per annum by 2030, half of which is expected to come from imports [5]. European industrial clusters are likely to be major offtakers and importers of hydrogen and derivatives due to high industrial demand, ambitious decarbonisation targets and limited renewable resources.

The movement of hydrogen over longer distances is not yet well proven. While existing research has confirmed the cost efficiency of future hydrogen pipelines linking the UK and mainland Europe [6], subsea hydrogen pipeline interconnectors are capital cost-intensive and have long lead times [7], making the Scottish Government’s ambition to export hydrogen in the 2020s [3] challenging without alternative options. Due to the low volumetric density of gaseous hydrogen, hydrogen-carrying derivatives are likely to be used in the absence of a centralised hydrogen pipeline network.

Hydrogen derivatives are substances that are manufactured using hydrogen and are generally capable of transporting hydrogen with higher volumetric energy density. Hydrogen products are also made with hydrogen, but are anticipated to be used directly, with no need for reconversion.

A range of technologies are available to increase the volumetric energy density of hydrogen for easier long-distance transport and storage. At a low temperature, gaseous hydrogen can be turned into liquid hydrogen. Liquefaction can help with storing hydrogen in smaller spaces for longer periods of time, transporting it and using it as aviation or shipping fuel. Hydrogen can also be reacted with nitrogen at high temperature and pressure to produce ammonia. Liquid ammonia can be stored more readily than liquified hydrogen due to it having a higher volumetric energy density. When transported to its destination, ammonia can be cracked back into hydrogen and nitrogen or used directly as ammonia in industrial applications. Liquid Organic Hydrogen Carriers (LOHCs) absorb hydrogen in an organic compound. This work focuses on the most advanced organic carrier, methylcyclohexane, which can be easily broken down to hydrogen and toluene. Lastly, metal hydrides, such as magnesium hydride, can carry hydrogen in a solid state, making international trade safer and simpler.

Methodology

We carried out desk-based research and targeted stakeholder interviews simultaneously to gather data and review a range of hydrogen derivatives and products. This dual approach was key to ensuring the interdisciplinarity of the research and bringing together technical, economic and policy aspects. More details can be found in the appendices (section 10).

To assess hydrogen derivatives and products and produce a clear, non-technical output, we assigned Red-Amber-Green (RAG) ratings to each hydrogen derivative and product. Clarification of these RAG categories is provided in Table 1.

RAG rating	Classification
GREEN	Low technical risks, high suitability, or high economic attractiveness.
AMBER	Moderate level of technical risk or suitability.
RED	High levels of risks, limited suitability or no economic attractiveness.

Table 1: Red-Amber-Green rating classification

Hydrogen Product and end use case mapping

Hydrogen is already used in a wide range of sectors, with 2022 consumption in the UK reaching more than 568,000 tonnes (22.3 TWh_HHV) [8]. Most existing hydrogen demand is taken up by oil refining. While hydrogen today is mainly used for oil desulphurisation, its use in biorefineries for hydrogenation is anticipated to grow in the future as demand for biofuels increases [9]. Hydrogen is critical for ammonia and fertiliser manufacturing, making it the second largest end use case in the UK in 2022 [8]. It is also used as a feedstock in the chemical sector, most importantly, for methanol production. While the methanol industry is limited in the UK, low-carbon methanol production is an area of emerging interest domestically. Furthermore, demonstration projects are underway to investigate the use of hydrogen in steel manufacturing. Hydrogen is not currently used in steel making, but directly reduced iron may become the dominant technology by 2050 (see section4.2).

In addition to existing end use cases in industry, we also reviewed end use cases in three sectors: high-temperature heat, transport, and power generation (see Table 2). UK research suggests that hydrogen can be used in most industrial equipment for heat generation, reducing capital costs (CAPEX) in the manufacturing sector as compared to installing new industrial equipment [10]. Low-carbon alternatives include carbon capture and storage (CCS) and biomass technologies. Hydrogen and its derivatives are also well placed to decarbonise some hard-to-electrify transport applications. While hydrogen can be used directly in fuel cell vehicles, the low volumetric density of gaseous hydrogen or high storage costs associated with liquified hydrogen could require it to be converted into derivatives such as methanol, ammonia or other synthetic fuels. This is particularly the case for long-distance and heavy transport. Lastly, our literature review and stakeholder engagement suggested that hydrogen technologies have a high potential to decarbonise dispatchable power production. Existing power plants can be run on hydrogen, ammonia, biomass or retrofitted with CCS technologies. Technologies shown in Table 2 are assessed in section 4.2.

	Industrial feedstock	Industrial heat	Transport	Power
Hydrogen based technologies	Hydrogen for ammonia and methanol production, refining and as a reducing agent	Hydrogen for high temperature heat	Hydrogen (fuel cell) SAF, ammonia and methanol (maritime)	Hydrogen turbines Ammonia turbines
Alternatives	None or very limited alternatives	CCUS-enabled heat generation Biomass	Battery electric vehicles Biofuels	CCUS and biomass turbines

Table 2: Hydrogen products and end use case mapping from our research

Hydrogen Derivative and Product Assessment

Hydrogen, derivatives and low-carbon alternatives

A range of hydrogen and alternative low-carbon technologies are available to export surplus renewable energy from Scotland to domestic and international demand centres. Table 3 summarises RAG ratings for hydrogen, derivatives and interconnectors. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

Table 3: RAG ratings for hydrogen, derivatives and interconnectors

High voltage direct current (HVDC) interconnectors already connect the UK with neighbouring countries, allowing the energy system to manage electricity peaks and enhance energy security. To increase export capacities and achieve higher system benefits, HVDC interconnectors can be complemented with hydrogen production, using excess renewable energy and exporting it to UK and European demand centres.

Hydrogen pipelines are the most mature and cost-efficient way to transport hydrogen over short and medium distances. However, due to long lead times and high capital costs they are not expected to be available at larger scale in the short term. Like other gases, hydrogen can be shipped in liquid form, which requires an extremely low temperature of −253°C. Hydrogen derivatives are simpler to transport due to their higher energy density and higher transport and storage temperature.

The most widely used hydrogen derivative is ammonia (NH₃), which is produced by reacting hydrogen with nitrogen at high temperatures and pressures. Ammonia has an established global market and is simpler to handle than liquid hydrogen as the boiling point of liquified ammonia is more than 219°C higher than that of liquefied hydrogen.

Organic compounds can also absorb hydrogen into their structure, forming LOHCs. These compounds remain stable as a liquid during transport even at ambient temperature and pressure, making them highly compatible with existing oil assets.

Although metal hydride technologies are relatively new, their simplicity and safety case could make them competitive with other hydrogen technologies. We took magnesium hydride as a case study as it can be easily shipped in a solvent slurry. Methanol is unlikely to be reconverted back to hydrogen at the point of destination. This is due to the economic case and carbon emissions associated with the methanol steam reforming reconversion process.

Hydrogen products

In some cases, hydrogen and its products can be used directly without the need to reconvert derivatives back to hydrogen or low-carbon power. This direct use can significantly improve overall round-trip efficiency, making the trade of hydrogen products an area of emerging interest. The availability of low-carbon alternatives is introduced as an additional factor in the analysis. A green rating is assigned to end-use cases with no or limited availability of alternatives, supporting the case for hydrogen use. A red RAG rating indicates widespread availability of low-carbon alternatives.

Industrial feedstock

The four main non-energy applications of hydrogen in industrial feedstock are ammonia for fertiliser, methanol production, oil refining and green steel production [11]. Table 4 summarises RAG ratings for selected end-use cases for hydrogen products. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

Table 4: RAG ratings of selected end use cases for hydrogen products

(* – depending on whether hydrogen is used as a reducing agent or in blast furnaces)

Hydrogen is critical for oil refining and the production of ammonia, a key chemical used for fertiliser, plastic or synthetic fibre fabrication. In oil refining, hydrogen is primarily used in hydrocracking and hydrotreating processes. Hydrocracking uses hydrogen and a catalyst to break down heavy hydrocarbons into lighter fractions like jet fuel, petrol and diesel. Hydrotreating removes impurities from hydrocarbon streams with desulphurisation being a key process to improve petrochemical quality and reduce sulphur oxide emissions at the point of use, thereby preventing acid rain.

While its role in fossil fuel refining may decline, low-carbon hydrogen will remain crucial in biorefineries for producing synthetic and biofuels like hydro-processed esters and fatty acids (HEFA), hydrotreated vegetable oils (HVO) and biodiesel.

Hydrogen is essential for both conventional and synthetic methanol production. Although methanol can be produced using bioresources [12], bio-based methanol alone is unlikely to meet global demand [13]. This makes synthetic methanol crucial for timely and large-scale industrial decarbonisation. Syngas, a mixture of hydrogen, CO and CO₂ molecule can be produced through natural gas reforming or by combining low-carbon hydrogen with sustainably sourced CO₂. This mixture undergoes methanol synthesis, a process where it reacts at high pressure and moderate temperatures to produce methanol (CH₃OH).

In contrast to the end use cases mentioned above, producing green steel requires new steel making equipment. Hydrogen, as an effective reducing agent for iron ore, holds significant potential to decarbonise steel and iron production. While some low-carbon alternatives exist, the IEA anticipates hydrogen-based direct reduced iron (DRI) technology coupled with electric arc furnace will dominate, contributing 44% of all emission reductions in the iron sector [14].

High temperature heat

High temperature heat is essential for various industrial processes including cement, ceramic and glass manufacturing. However, decarbonising high-temperature industrial heat is among the most challenging tasks due to technical difficulties and cost inefficiencies associated with generating such heat (>1000 °C) using existing electric technologies [15].

The need for low-carbon technologies is becoming more urgent as approximately 4,300 industrial heating units in the UK rely on gas, representing 70% of the country’s industrial gas consumption [10]. Existing equipment can be retrofitted to use hydrogen, generating direct and indirect heat up to 1000 °C.

Low-carbon alternatives including biofuels such as biomass or biomethane, and CCUS technologies are also viable. With CCUS, industrial plants are upgraded with post-combustion carbon capture systems, which store the resulting greenhouse gases in underground reservoirs.

Table 5 summarises RAG ratings for high temperature heat use. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

Table 5: The RAG ratings of selected high temperature heat use

Transport

Hydrogen can be used in fuel cell vehicles and has been shown to be able to be cost competitive with other fuels with government subsidies [16]. While the economic case for fuel cell heavy good vehicles (HGVs) is fairly well established [17], there is more uncertainty around lighter vehicles [18]. Battery-electric passenger vehicles and light duty vehicles (LDV) are likely to be more cost competitive compared to their fuel cell equivalents.

Sustainable Aviation Fuel (SAF) is currently used in aviation to reduce carbon emissions, and the similar composition as current options allows for storage for long periods of time in the same infrastructure [19]. While the industry continues to explore alternatives to SAF, there is a wide consensus that aviation is a hard-to-electrify sector. Both the EU and the UK have mandated the use of SAF from 2025 (see Figure 1). SAF is anticipated to be the dominant decarbonisation pathway, with other low-carbon fuels such as hydrogen taking up very small shares of the market [20].

Synthetic methanol and ammonia will increasingly be used as fuels in the maritime industry, as there are not many other alternatives. In case of shorter distances, some ships and ferries may be powered electrically with batteries or fuel cells [21]. A Norwegian ferry currently powered by hydrogen fuel cells can reduce yearly emissions by 95% [22].

Table 6 summarises RAG ratings for transport uses. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

Table 6: The RAG ratings of selected transport uses

Power generation

Renewables are well placed to decarbonise a large share of the electricity supply. However, due to intermittency challenges, electricity generation cannot always meet electricity demand. Hydrogen, ammonia and biomass are all low-carbon fuels that can be used in turbines to meet electricity demand when required. Alternatively, CCUS enabled gas turbines are an alternative that do not require major alterations of existing fossil fuel infrastructure, with the CO₂captured stored underground.

While all technologies reviewed in this section can generate power, they are not necessarily perfect substitutes (see Figure 1). Our stakeholder engagement confirmed that the main role of hydrogen is expected to be in peaking generation, with bioenergy with carbon capture and storage (BECCS) running at baseload due to high capital costs and substantial carbon benefits [23].

Power generation in Great Britain is dispatched in the order of merit or cost. Baseload units, for example nuclear power plants, run throughout the year. Mid-merit units, for example combined-cycle gas plants operate up to thousands of hours per year. Power plants that operate no more than 5% of the year are generally referred to as ‘peaking plants’ [24].

Table 7 shows the RAG ratings of selected power generation methods, with the ‘low-carbon alternative’ factor not being applicable to non-hydrogen technologies, such as gas CCUS, biomass and ammonia.Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

Table 7: The RAG ratings of selected power generation methods

E-METHANOL IN MARITIME

FEWER ALTERNATIVES

MORE ALTERNATIVES

LOW TECHNOLOGY READINESS

HIGH TECHNOLOGY READINESS

REFINING

CHEMICALS

HYDROGEN
INTERCONNECTORS

STEEL

HIGH-TEMPERATURE
HYDROGEN HEAT

AMMONIA
IN MARITIME

AMMONIA
POWER GENERATION

SMALL-SCALE
HYDROGEN
POWER AND CHP

HYDROGEN IN
LIGHT VEHICLES

HYDROGEN IN
HGVs

SUSTAINABLE

AVIATION FUEL

SMALL MARITIME
APPLICATIONS

LOW-TEMPERATURE
HYDROGEN HEAT

LARGE-SCALE HYDROGEN
POWER

Figure 1: Technical and alternative technology assessment of selected hydrogen products and end use cases

ENERGY CARRIER

POWER GENERATION

TRANSPORT

INDUSTRIAL HEAT

INDUSTRIAL FEEDSTOCK

Offtaker Market Assessment

We assessed potential offtake markets for hydrogen derivative and products, covering Scotland, the rest of the UK, the Netherlands, Belgium, Germany and the European Union as a whole. Our findings are summarised in Table 8.

A Scottish Flag. A diagonal white cross on a circular blue background.

A flag with a cross with Great Britain in the background

Description automatically generated

Table 8: The RAG ratings of selected offtaker markets

Distance from Scotland and rest of UK

Our stakeholder engagement confirmed that distance is a key factor determining the price of both domestic and international hydrogen transport. The cost associated with all methods of hydrogen transportation increases linearly with the distance. Shorter distances between hydrogen production sites and demand centres result in lower capital costs for pipelines or tube trailers, compared to long-distance shipping. This means that the lowest associated costs are found within Scotland. Multiple stakeholders highlighted the potential benefits of co-locating hydrogen production and end-user project, substantially reducing the cost of hydrogen transport.

The nearest potential demand hotspots to Scotland are in the rest of the UK, with the closest being the industrial clusters in the North of England and Wales. Internationally, the closest industrial offtake markets are in the Netherlands, Belgium and Germany, in order of proximity. While distance to the nearest hydrogen terminal is highly relevant in the short term, its importance is expected to decrease as the intra-European hydrogen infrastructure, the European Hydrogen Backbone, becomes available. Once a centralised hydrogen market is in place, Central or Eastern European markets are anticipated to be accessible from Western Europe.

Infrastructure gap and opportunity

Hydrogen trade infrastructure, including ports, terminals, onshore and offshore pipelines, is key to removing barriers to trade. In contrast to the UK’s limited hydrogen infrastructure, Europe has around 2,000 km of hydrogen pipelines [25], with further extensions needed to avoid market inefficiencies. Existing infrastructure, for example gas interconnectors, can be leveraged and repurposed to bring down CAPEX costs. Subsea natural gas interconnectors already link Great Britain with Northern Ireland, Ireland, Norway, the Netherlands and Belgium. While IEA analysis suggests that the cost of hydrogen transport can be significantly reduced using repurposed pipelines [26], our stakeholder engagement suggests that the majority of the natural gas assets are unlikely to be altered, to maintain energy security.

While some of the fossil fuel infrastructure is required to stay in place, it is critical to develop purpose-built hydrogen assets, especially given the long lead times associated with new developments. To supplement and link up regional pipelines, the European Hydrogen Backbone project aims to develop 53,000 km of hydrogen pipelines by 2040. The REPowerEU Plan set out three major import corridors via the Mediterranean, the North Sea area and Ukraine. Germany and the UK signed a Memorandum of Understanding in 2023 strengthening collaboration on energy and climate, including security of energy infrastructure [27]. Research conducted by the Net Zero Technology Centre is ongoing to explore the feasibility of a subsea hydrogen pipeline between Scotland and mainland Europe [28]. Stakeholders suggested that further coordination with the European Union is key to ensure alignment between infrastructure.

All selected European countries have strategy on domestic pipeline infrastructure roll-out. Germany has a well-established network of pipelines especially in the north-west and is aiming to add 4,500 km of hydrogen pipeline using Important Projects of Common European Interest (IPCEI) funding [29]. The Netherlands is also aiming to link industrial clusters with a national hydrogen network by 2030 [30].

European ports and terminals, critical for long-distance import and export, are developing similar strategies. The Port of Rotterdam aims to supply 4.6 million tonnes of hydrogen per year by 2030 (181.2 TWh_HHV) [31], with projections suggesting a capacity of 20 million tonnes per year by 2050 (788 TWh_HHV ) [32] become major renewable energy hubs. More detail on infrastructure projects can be found in Table 11 (Appendix B).

As well as infrastructure to support the supply and trade of hydrogen, there is also a need for demand-side infrastructure to complete the value chain with offtake. This includes hydrogen refuelling stations, hydrogen boilers, salt caverns for storage and hydrogen-powered furnaces etc. For example, the EU’s Alternative Fuels Infrastructure Regulation includes a required number of hydrogens refuelling stations along it’s TEN-T core network, a road network that includes the most important connections between major cities and nodes, planned for completion by 2030. The regulation states that a hydrogen fuelling station with a cumulative daily capacity of one tonne, dispensed at least a 700bar, is required every 200km to “ensure a sufficiently dense network to allow hydrogen vehicles to travel across the EU.”

Meanwhile, many European countries are targeting a phase out of fossil-fuel powered household boilers by 2035, with clean hydrogen boilers seen as a key alternative. Development of demand infrastructure currently requires support from similar policies across the value chain, with several EU policy schemes such as the Emission Trading Scheme, SAF Mandates and Road Transport Fuel Obligation (RTFO). With the policy and investment progressing, demand-side infrastructure will follow. This presents an opportunity for Scotland to partner with the EU to shape and support these supply chains as they develop and provide the necessary hydrogen supply.

Existing demand for hydrogen and hydrogen products

While existing demand is mainly met by fossil fuel derived hydrogen and derivatives, the share of low-carbon hydrogen is expected to increase given emerging mandates, policy frameworks and increasing carbon prices. The Netherlands and Germany were the leading hydrogen trading countries in 2023, with a total import of 194,096,000 m³ and 6,322,280 m³ of overwhelmingly fossil-based hydrogen, respectively [33] (see Figure 15 in Appendix B).

Figure 2, below, shows the consumption of hydrogen in the UK, Belgium, Germany, the Netherlands and the whole of EU for the year 2022. In the EU, Germany is the largest consumer of hydrogen followed by the Netherlands, whereas Belgium is the 9^th largest consumer. Together, these three countries account for roughly 41% of the total consumption of hydrogen in EU [8].

Figure 2: Total hydrogen consumption in the EU, the Netherlands, Belgium, the UK and Germany in 2022

Projected demand for hydrogen derivatives and products

As countries progress toward net zero targets, demand for hydrogen and hydrogen derivatives and products is expected to rise. On a European scale, the UK and Germany have the most ambitious short-term demand for hydrogen. The UK Government has estimated between 80 and 140 TWh in demand by the end of 2035 [34] [35]. For Scotland, as shown in section 7.3, analysis by Gemserv projects hydrogen demand to range from 0.6 TWh to 2.8 TWh by 2030, and from 2.9 to25 TWh by 2045.

Germany set a target of 95 – 130 TWh by 2030 [29] with independent projections in line with this range (42 – 72 TWh of demand by 2030) [4]. By 2045, forecasts range from 184 to 694 TWh depending on assumptions. Belgium anticipates a demand of 20 TWh by 2030 but expects a sharp increase to 200-230 TWh by 2050 [36]. The Netherlands has projected demands of 120 TWh (2050) [37]. Demand scenarios developed as part of this research are discussed in Appendix E.

Policy landscape and net zero ambitions

Scotland has an ambitious net zero target for 2045. This is five years ahead of the UK’s net zero target. Both Governments have published strategies and action plans on hydrogen production. However, stakeholders highlighted the lack of clarity on regional and hydrogen trade strategy. This perceived lack of clarity and of commitment to specific targets and routes could be a competitive disadvantage compared to other European countries.

In the UK, hydrogen production projects will be subsidised under the Hydrogen Production Business Model (HPBM). The HPBM will ensure it only stimulates production of hydrogen that is low-carbon by requiring volumes to comply with the Low Carbon Hydrogen Standard (LCHS) which sets a maximum emissions limit of 20 gCO_2e/MJ [38]. While hydrogen production using imported natural gas is eligible for support under the Cluster Sequencing programme, the HPBM is not expected to support any form of hydrogen or hydrogen derivative import [38] and export [39].

In the absence of UK-wide policies supporting hydrogen trade, its main driver is expected to be international hydrogen import subsidies, mandates and targets. While the UK has committed to designing generous hydrogen business models, our stakeholder engagement suggests that regulatory bottlenecks remain, particularly around electricity market and the planning and permitting frameworks. According to stakeholders, the Review of Electricity Market Arrangements (REMA) is critical to cut the currently ‘very high’ grid electricity prices in the UK, particularly in Scotland. With hydrogen costs highly sensitive to electricity prices, reducing these will be essential to improving Scottish hydrogen competitiveness.

Stakeholders also reported that hydrogen regulation is fragmented and dated, with the planning and permitting process being more complex and lengthier compared to ‘other industrial countries’. These findings are in line with a 2023 research paper commissioned by DESNZ [40]. Scotland and UK specific regulatory bottlenecks are detailed in Table 18 (Appendix D).

The EU aims to be carbon neutral by 2050 [41]. It adopted a strategy on hydrogen in 2020 which focussed on 5 key areas: investment aid, production and demand, creating a hydrogen market (including infrastructure), research and international co-operation [42]. In the 2022 REPowerEU Plan, the European Commission set an ambitious 20 million tonne (equivalent to approximately 330 TWh) hydrogen target for 2030, with the EU aiming to import half of this [43]. Ambitious European import targets could offer potential opportunities to Scottish hydrogen exporters.

The German Federal Government established H2Global in 2021, a double auction model designed to facilitate inter-continental hydrogen trade [44]. In 2023, the European Commission decided to link the European Hydrogen Bank with H2Global to allow all EU member states access to the funding mechanism and agreed to jointly develop a European auction for international hydrogen imports [45]. Germany laid out an ambitious net zero target for 2045 [46] and their national hydrogen strategy states both a domestic hydrogen production target of 10GW alongside an import target of 90 TWh, potentially above 90% of the total demand forecast for 2030 [29]. They anticipate 2030 hydrogen demand to reach 95-130 TWh, around 50-70% (45 to 90 TWh) of which is forecasted be imported [29]. According to the National Hydrogen Strategy, pre-2030 imports are anticipated to be delivered by ships, with imports gradually expanding to pipeline-based solutions after 2030 [47].

Both the Netherlands and Belgium have net zero targets for 2050 and published national hydrogen strategies [48] [49]. The Netherlands has announced hydrogen import targets for 2030 for the Port of Rotterdam, 4.6Mtpa in 2030 increasing to 18Mtpa by 2050, and the Port of Amsterdam, 1Mtpa by 2030 [50]. Belgium has also set an import target of 0.6Mtpa, meaning that 62% of the continent’s 10Mtpa target could be met by these three ports [50].

The EU, along with member states are working towards a harmonised certification framework for low-carbon hydrogen to remove trade barriers [29] [51] [52]. Our stakeholder engagement suggests that misalignment between certification frameworks is expected to be the main bottleneck for international trade. UK and international hydrogen-related policies are further detailed in Table 19 (Appendix D).

SWOT Analysis

To shortlist high-potential hydrogen derivatives, products and end use cases, we considered the strengths, weaknesses, opportunities and threats associated with hydrogen derivatives and the trade of these products from a Scottish perspective.

Strengths

Strengths focus on the competitive advantages of Scotland.

As highlighted by a number of stakeholders, Scotland’s main competitive advantage in the hydrogen sector is access to abundant renewable generation capacity. As future renewable capacity is likely to exceed future electricity demand, Scotland is well placed to transition into an international hydrogen hub. Existing jobs, skills, and infrastructure, especially in the oil and gas and offshore wind sectors, could also confer a competitive advantage. Existing oil and gas infrastructure, such as gas interconnectors, ports, terminals and vessels, can be repurposed, resulting in savings in CAPEX. For example, due to the similarity of LPG and liquified ammonia, existing LPG terminals can be repurposed to import and export ammonia.

While Scotland does not have direct access to geological salt formations required for salt cavern hydrogen storage, depleted and partially depleted gas and oil reservoirs off the coast of Scotland could be suitable for large-scale hydrogen and CO₂ storage. Existing feasibility studies, demonstration projects, and trials funded by the Scottish and UK Governments are critical to get initial commercial projects off the ground.

Weaknesses

Weaknesses focus on the competitive disadvantages of Scotland.

Our research identified high grid electricity prices as the main competitive disadvantage of Scotland. Despite abundant renewables potential, high prices and network charges seem to prevent Scottish industry and consumers to capitalise on this advantage. Additionally, compared to other regions aiming to export surplus low-carbon hydrogen to European demand hotspots, Scotland’s relative disadvantage in solar generation could lead to greater intermittency, translating into higher hydrogen production costs.

In terms of infrastructure, electricity network constraints and limited energy storage capacity could prevent the energy system from mitigating temporal and geographic electricity imbalances. Lack of geological salt formations beneath Scotland will also amplify the challenge of storing large volumes of hydrogen in the absence of a UK-wide centralised hydrogen network.

Other weaknesses include limited experience in the production of ammonia, methanol, LOHC, and other derivative, as well as the lack of low-carbon hydrogen production on a commercial scale.

Opportunities

Opportunities focus on the future potential of Scotland as well as Scotland’s environment, offtake markets and competitors.

Hydrogen presents the opportunity to cut carbon emissions, reduce wind curtailment costs, boost economic growth and enhance energy security and resilience. In trade terms, stakeholders highlighted the opportunity for Scotland to strengthen existing industrial clusters and focus on high value-added industries instead of exporting low value-added fuels.

Although electricity prices are currently high, reforms under REMA could reduce costs for consumers. From an offtake market perspective, the main opportunity is to export hydrogen to industrial clusters in England and Wales. Once online, a core network connecting demand and supply hotspots can transport gaseous hydrogen in a cost-efficient manner. The North of England has the added benefit of large potential hydrogen storage capacities. By transporting hydrogen to Cheshire, Teesside or the Humber, Scottish producers could utilise large-scale storage facilities, enhancing flexibility and hedging against supply and demand-side shocks.

Regulatory misalignment—particularly around certification—is less of a barrier within the UK, as the Low Carbon Hydrogen Standard is expected to be applied nationally. Internationally, the increasing willingness of the EU, Germany and the Netherlands to import and subsidise low carbon hydrogen is a significant opportunity. Partially driven by the RED III directive, industry in the EU will have to meet a substantial share of their hydrogen demand from low-carbon by 2030.

Threats

Threats focus on the future risks in Scotland as well as risk associated with Scotland’s environment, offtake markets and competitors.

As our research identified hydrogen export to England as a high-potential opportunity, any delay in building out a core network connecting UK supply and demand hotpots is a threat to the growth of the hydrogen economy. In terms of international transport, lack of progress with hydrogen interconnectors, ports, terminals and vessels could further delay hydrogen derivative and product trade.

While Scotland is well-placed to supply hydrogen molecules through high-pressure pipelines, it may be outcompeted in the European market by lower cost, low-carbon hydrogen from renewable rich countries particularly in the form of ammonia, methanol and other hydrogen derivatives. This is because of high electricity prices, intermittency challenges and high hydrogen transport costs in the absence of subsea hydrogen interconnectors. However, the main threat on an international scale is the lack of a harmonised certification framework. As emphasised by the IEA, inconsistencies in low-carbon hydrogen standards risk becoming the main barrier for the development of international hydrogen and derivative trade [53].

Hydrogen Derivative and Product Demand

This section discusses the findings of the analysis, with the methodology used to develop these estimates shown in Appendix E. The analysis estimates the annual demand for hydrogen in the EU, the Netherlands, Germany, Belgium and England and Wales. Annual demand scenarios were developed for the years 2030 and 2045, and the demand was divided into various sectors and hydrogen products. The years 2030 and 2045 are selected due to their significance to policy targets for both the EU and Scotland. The RED III targets set out by the EU focus on accelerating the demand for hydrogen, among other fuels, by the year 2030 [54] and Scotland has a target of achieving net zero by the year 2045. Finally, in our analysis, hydrogen demand is modelled under three scenarios: High, Central, and Low in 2030 and 2045. The full demand mapping results can be seen in Appendix E.

Sectoral Demand

Figure 3 shows the modelled annual demand, by sector, for the whole of the EU for the years 2030 and 2045. Hydrogen demand is expected to be significantly higher in 2045, compared to 2030. The industrial demand^[3] shown in Figure 3 captures all industrial demand for hydrogen including demand for methanol and ammonia. The subsequent graphs in Figure 4 break down the industrial demand by product type.

Figure 3: Modelled annual demand for hydrogen and hydrogen derivatives in the EU

Figure 4 and Figure 5 show the expectation that demand for hydrogen use directly will be greater than demand for ammonia or methanol in both the 2030 and 2045 timeframe for the EU and nations considered. Demand for ammonia and methanol using low-carbon hydrogen will be driven by the RED III mandate which specifies that 42% of industrial hydrogen use (except refining) must utilise renewable fuels of non-biological origin (RFNBOs) by 2030. By 2045, it is expected that almost all ammonia and methanol will rely on low-carbon hydrogen.

Figure 4: Central Scenario EU Industrial Hydrogen Demand by Product in 2030 and 2045

Figure 5: Central Scenario National Industrial Hydrogen Demand by Product in 2030 and 2045

In all modelled scenarios for 2030 and 2045, the industrial sector is expected to remain the dominant driver of hydrogen demand in the EU. However, demand is likely to diversify between 2030 and 2045 largely because of increasing forecast contributions from the power generation sector – where hydrogen is expected to serve an important role in balancing the power system during times of low renewable generation.

For example, in 2030 the share of the industrial sector in the mix of total hydrogen demand ranges from 88% to 96% (Figure 6) but is expected to fall to within a range of 28% to 59% by 2045. Hydrogen demand in the transport sector is estimated to grow rapidly between 2030 and 2045 – largely driven by growth in demand for hydrogen as a low-carbon fuel for heavy transport, including maritime transport, aviation and HGV transport. In some scenarios, hydrogen consumption is further diversified between 2030 and 2045 by an increasingly large demand from the heating sector – which comprises as much as 14% of total hydrogen demand in the EU in the high scenario for 2045.

Figure 6: Share of different sectors and hydrogen derivatives of total hydrogen demand in the EU

Figure 7 and Figure 8 depict the modelled annual demand for hydrogen for Germany, Belgium, the Netherlands and England and Wales for different sectors in the years 2030 and 2045.

Figure 7 indicates that, consistent with the EU wide hydrogen demand, the industrial sector is anticipated to comprise most hydrogen demand in all countries by 2030. Similarly, reflecting EU-wide trends, hydrogen demand is expected to become increasingly diverse by 2045, when power generation, road transport and aviation will all likely also contribute to hydrogen demand in each of these markets. Hydrogen demand in the heating industry could also grow significantly in these markets; however, this is entirely dependent on the national policy landscape. For both 2030 and 2045, Germany and England and Wales are anticipated to drive most of the hydrogen demand.

Figure 7: Hydrogen demand for countries across all scenarios and sectors for the year 2030

Figure 8: Hydrogen demand for countries across all scenarios and sectors for the year 2045

Demand by Hydrogen Product

The total final demand for hydrogen, ammonia, methanol and sustainable aviation fuel (SAF) in the EU is shown in Figure 9. It is expected that hydrogen demand will be greater than any of the products assessed for both 2030 and 2045 making up 68% and 78% of demand, respectively. Of the products assessed, final demand for ammonia is likely to be greatest, estimated at 42 TWh in 2030. This is driven by low-carbon ammonia demand for use in fertilisers. It is expected that ammonia demand will rise to 206 TWh, with demand for maritime fuel making up over half of this total. Final demand for methanol derived from low-carbon hydrogen is expected to increase from 15 TWh to 20 TWh between 2030 and 2045. SAF demand from power to liquids in the EU is projected to increase from 4 TWh to 59 TWh between 2030 and 2045, due to the emerging SAF mandates.

Figure 9: Central EU Final Demand for Hydrogen and Products in 2030 and 2045

Figure 10 shows the central annual final demand for hydrogen and products by country. Similar to the EU as a whole, it is estimated that hydrogen has the highest demand for each region in both time periods. However, demand for ammonia could be significant, particularly in regions with significant maritime activity such as the Netherlands, where ammonia is estimated to form 44% of final demand in 2045. SAF demand is expected to be more evenly distributed across regions due to greater distribution of aviation activity. Methanol demand is relatively low across all regions ranging between 1 and 7 TWh per year by 2045.

Figure 10: Central National Final Demand for Hydrogen and Products in 2030 and 2045

Demand Scenarios for Scotland

As Figure 11 shows, the projected demand in Scotland is likely to be limited for the year 2030, ranging from just 0.6 TWh to 2.8 TWh from the Low to the High scenarios. The demand jumps up for the year 2045, ranging from 2.9 TWh in the Low scenario to 25 TWh in the High scenario^[4].

Figure 11 shows that for the year 2030, industry is the main driver for demand in Scotland. However, for the year 2045, other sectors like Road Transport and Power Generation play significant roles as drivers of demand.

These results reaffirm the export potential for Scotland as the hydrogen production capacity of Scotland is expected to be larger than the demand for hydrogen.

Figure 11: Annual demand for hydrogen and hydrogen derivatives for Scotland for 2030 and 2045

Figure 12 shows the range of demand for hydrogen and its derivatives for Scotland. The graph shows that the demand for all sectors, other than industry, is limited in all scenarios for the year 2030, with demand varying by sector significantly in 2045. For example, in the transport sector, the Low and High scenarios estimate a demand of 0.6 TWh and 7 TWh, respectively. This wide range is the result of high uncertainty of demand for hydrogen in the maritime and road transport sectors of Scotland for 2045.

Figure 12: Range for hydrogen & hydrogen derivatives across all sectors for Scotland

Comparison to Literature

A European Commission [55] (JRC) study reviewed a diverse range of literature and used the projections from different studies to determine average annual demand for hydrogen in the EU. According to the JRC study, the total projected annual demand for hydrogen in 2030 is 230 TWh [55], which lies towards the upper bound of this report’s estimate of 108-236 TWh. Similarly, the EU Commission’s study projects the annual demand to be 900 TWh in 2040 and 1,270 TWh in 2050. Whereas this report’s analysis projects the demand for hydrogen for 2045 to be within the range of 733 TWh to 1852 TWh.

A 2021 study conducted by European Hydrogen Backbone [56] estimates that the annual demand for green and blue hydrogen in Industry (for both the EU and the UK) will reach 692 TWh in 2040 and 983 TWh by 2050 [56]. Whereas this report projects the demand in industry in both EU and UK to range from 534 TWh to 711 TWh in 2045.

Figure 13 provides a full comparison between the results of this study and those of two external studies. The results estimated for this report are shown as a range of total projected annual demand of hydrogen for EU, for the years 2030 and 2045. The results of the other two studies are not shown as ranges; and the years for these studies are 2030, 2040 and 2050. It is also worth noting that this study includes demand for the heating sector, which is not accounted for in the other two.

Figure 13: Comparison of this study’s results with the literature

The comparison of these estimates is challenging as their geographical scope and timelines vary, with a number further differences in modelling methodologies.

Policy Gap Analysis

Our stakeholder engagement and desk-based research highlighted the following policy gaps. Further regulatory gaps can be found in Table 18.

In the United Kingdom, reserved matters are decisions taken by the UK Parliament, as opposed to devolved matters where devolved institutions, including the Scottish Parliament, hold decision making authority. As such, we have split our policy gap analysis into Scotland based, UK based and international policy gaps.

Policy Gaps in Scotland

Scottish policy gaps are set out below.

Lack of clarity on hydrogen trade strategy

Clear signals from the Scottish Government are required for the Scottish industry to prepare and make strategic decisions to enable successful trade.

Planning and permitting

Planning and permitting processes need to be faster and streamlined. Hydrogen projects typically require long lead times, due to infrastructure requirements as well as typical barriers to the implementation of innovative technology. This finding is in line with our stakeholder engagement and 2023 report commissioned by DESNZ [57]. Streamlining and accelerating the planning processes is key to alleviating investment barriers.

While our stakeholder engagement and desk-based research was conducted prior to the announcement of ‘the Planning Hub’ [58], this new body is anticipated to improve consenting speed and make the planning system more efficient for hydrogen projects.

Regional Strategic Planning

Stakeholder engagement highlighted that Scotland is home to diverse regions, with varied geographical environments. Blanket, national strategic planning risks overlooking localised requirements and optimal use cases =. Scotland needs regional hydrogen strategies that are integrated with a cohesive national strategy.

Increasing need for trials and demonstration projects

The hydrogen industry, especially the trade sector, will utilise new technologies, which still need to be proven and developed. Trials and demonstration projects are increasingly needed to build the case for these technologies.

Policy Gaps in the UK

As outlined above, some policy gaps relate to the UK Government as a reserved power, as opposed to the Scottish Government, as a devolved power. The policy gaps for the reserved power, in this case the UK government, are detailed below.

Hydrogen Trade Strategy

The UK is currently lacking a clear strategy on hydrogen trade as well as a holistic strategy incorporating natural gas, electricity and hydrogen. This is urgently required to provide clarity, allow for strategic decisions to be taken and stimulate investment.

The establishment of National Electricity System Operator (NESO) is a positive step towards solving this issue. NESO is expected to address issues regarding whole system strategy by integrating electricity, gas and hydrogen infrastructure into one energy system plan. NESO has developed whole energy system models, titled Future Energy Scenarios, which support planning and identify the opportunity for Scotland to be an energy exporter. This work should be expanded to include economic modelling on trade, culminating in a developed and full strategy.

Infrastructure

A clear commitment to a core hydrogen network, linking industrial clusters in Scotland, England and Wales is needed. More clarity on the timeline is key to improving investor certainty and get initial projects off the ground.

Dated and fragmented hydrogen regulation

Onshore hydrogen projects are currently regulated under the Gas Act 1986 and Planning Act 2008, with hydrogen generally being defined as a ‘gas’. Our stakeholder engagement suggested that current regulation is fragmented, with more concise and ‘net-zero-aligned’ regulation increasingly needed in the UK.

Hydrogen Production Business Model

Risk-taking intermediaries (RTI), market players who take ownership of the hydrogen molecules before selling it on to transporters or end users, need to be recognised as an eligible offtake option. Stakeholders warned that without the recognition of RTIs, large-scale and efficient hydrogen trade, transport and storage may not materialise. Additionally, the current allocation round set up of the HPBM has also raised a competitive element between projects. This reduces collaboration between key stakeholders. The UK Government should assess how they can reduce this competition driven fragmentation within current funding mechanisms.

Misalignment between UK and EU ETS

The UK and EU ETS need to be aligned to successfully foster low-carbon trade of goods. Clarity is urgently needed around the scope of inclusion for the maritime sector.

Review of Electricity Market Arrangements (REMA)

The current electricity market pricing structure needs reforming to help bring down prices. As electricity prices are a major driver of hydrogen production costs, reforms are critical to increasing uptake and improving competitiveness of UK hydrogen.

Wider and international policy gaps

Alignment between international policy is critical to facilitating successful trade between nations. International policy gaps are shown below.

Lack of clarity on emission factors

Standardised emission factors for alternative fuels (e.g. methanol) are needed. This is highly relevant to sectors such as maritime and aviation where synthetic fuels may play a major role. Standard values are needed for carbon accounting, from accredited sources, to ensure reporting consistency.

Misalignment between certification frameworks

Differences in low-carbon hydrogen certification frameworks create complexity in international trade. The development of mutually recognised standardised certification frameworks is essential to facilitate cross-border trade in hydrogen and its derivatives.

Conclusions

Scotland has significant opportunities in the production, use and export of hydrogen, its derivatives and products, particularly to nearby markets in England, Wales, and the European Union. England and Wales offer a large local market due to existing industrial demand, geographical proximity, and similar regulatory frameworks. The EU is also a potential market because its member states are unlikely to meet their own low-carbon hydrogen demand, creating an opportunity for Scottish exports.

While Germany and the Netherlands are anticipated to import significant amount of hydrogen and derivatives, the extensive infrastructure and harmonised certification frameworks necessary for international trade are not yet in place. Subsea hydrogen interconnectors are crucial for intra-European trade as alternative delivery methods and hydrogen derivatives are associated with substantially higher costs. Without such a pipeline, other renewable resource-rich regions, such as the Middle East, South Africa and South America, may outcompete Scotland in the European market.

For global trade, ammonia is expected to become the dominant hydrogen derivative due to its technical maturity, efficiency, and well-established global market. Other hydrogen transport methods, like liquified hydrogen, LOHCs and metal hydrides, are anticipated have a more minor role. The most suitable hydrogen derivative for export will depend on factors including scale of production, transport distance, infrastructure readiness and end use application.

Key UK and EU industrial sectors such as chemicals, aviation, and steel are well-positioned to use hydrogen and hydrogen products directly, supported by rising carbon prices and emerging policies like the Sustainable Aviation Fuel mandates in the UK and the European Union. Although synthetic methanol will play a key role in decarbonising industrial use and maritime projects, uncertainties remain around maritime policy and biogenic CO₂ availability.

As low-carbon ammonia markets and propulsion technologies mature, the maritime sector is projected to transition from ammonia to methanol in the medium to long term. Hydrogen has also been found to be critical for the decarbonisation of the iron and steel industry, with the majority of steel plants expected to use directly reduced iron (DRI) technology.

The success of international hydrogen trade will depend on robust infrastructure, emission trading schemes, and the timely implementation of the CBAM, alongside mutually recognised certification frameworks.

Recommendations

Stimulate demand by improving alignment – With carbon prices being among the strongest demand-side incentives, the Scottish Government could work together with the UK Government and the EU to maximise its benefits. As pointed out by stakeholders, the UK and EU Emissions Trading System need to be aligned to avoid potential carbon taxes on UK products including maritime fuels. The timely launch of the UK Carbon Border Adjustment Mechanism (CBAM) is also critical to stimulate demand domestically and achieve better alignment and consistency with the EU policy framework. Section 8 of the report discusses these policies, and more, in higher detail.
Stimulate demand by supporting trials and demonstration projects –The Scottish Government is encouraged to continue its approach with supporting hydrogen demand projects through subsidy schemes, such as the Hydrogen Innovation Scheme, helping end users overcome barriers to investment. More trials and demonstration projects are key to create learnings, improve investor certainty and get initial projects off the ground.
Support infrastructure – Scotland should support key new-built and repurposed infrastructure projects including a core UK hydrogen network, ports and terminals (see Section 5.2). This includes working with the UK Government to give developers more clarity on the timeline of a core hydrogen network and how this will link with UK ports and terminals. There should also be an equal amount of focus on developing demand- and storage-based infrastructure, like hydrogen boilers, refuelling stations and salt cavern storage.
Enhance competitiveness of Scottish hydrogen –To effectively compete with renewable rich regions, Scotland needs to meet a lower levelised cost of hydrogen. This is because the main contributor to the levelised cost of hydrogen is electricity price. High electricity prices are identified as one of the biggest weaknesses in Scotland’s hydrogen ambitions, as laid out in section 6.2. While the power of devolved administrations is limited, the Scottish Government is recommended to (1) commission research into alternative electricity market arrangements and (2) work with the Office of Gas and Electricity Markets (Ofgem) and the UK Government, representing the Scottish industry from an evidence base position.
Reform the planning and permitting regime and ensure safety case is developed – With Scotland having a longer and more complex planning and permitting framework compared to other industrialised countries, developers need more guidance. The Scottish Government should look to streamline these processes where possible to avoid unneeded congestion and accelerate decarbonisation. Work with the Health and Safety Executive (HSE) to ensure that the safety case for hydrogen is developed in a timely manner and disseminate the results effectively.
Optimise low-carbon policy frameworks – While current policy is designed to get initial projects off the ground, our research found that the Hydrogen Production Business Model needs to be optimised and designed considering interactions with other low-carbon policy frameworks, such as the Contracts for Difference Scheme, Hydrogen T&S Business Models and the H2P Business Model. The UK Government allowing risk-taking intermediaries in subsequent allocation rounds is critical to strengthen the hydrogen supply chain and unlock domestic hydrogen trade.
Co-ordinate with the EU –Infrastructure projects have long associated lead times and limited flexibility once approved. Therefore, coordinating infrastructure deployment with the European Hydrogen Backbone and port infrastructure is essential. More coordination with the EU, in the form of trade policies, was also one of the key takeaways and a commonly brought up point in the stakeholder engagement that Gemserv conducted. Key findings from the stakeholder engagement are discussed in Appendix G.
Continue progress on low-carbon – A standardised low-carbon hydrogen standard is critical to the success of hydrogen trade. The Scottish Government is recommended to work with the UK Government, European bodies and other international stakeholders to accelerate the harmonisation or the mutual recognition of low-carbon certification frameworks.
Engage local communities – Public perception has been seen to be a critical aspect in the successful implementation of hydrogen as a technology. The Scottish Government should continue to engage with local communities and improve the public understanding hydrogen’s role in a net zero energy system as well as the stringent safety and regulatory measures undertaken in implementation. The Scottish Government could also look at forming a strategy of how best to disseminate the benefits of hydrogen trade to local consumers.
Set out strategy on hydrogen trade – The Scottish Government could work with the UK Government on a clear strategy on how hydrogen export, and potentially import capacities, are planned to be developed.

Appendices

Hydrogen derivative and product assessment

Hydrogen, pipelines, derivatives and low-carbon alternatives

Economic implications

As shown in Figure 14 below, repurposed 48-inch pipelines are likely to have the lowest levelised cost of delivering hydrogen [26]. Since there are no existing pipelines between the Scottish mainland and the proposed hydrogen export markets in Europe, this option would likely involve the construction of a large length of new 48-inch pipeline. The construction of pipelines over long distances, however, would require a significant initial investment of both time and capital. Therefore, conventional tanker transport may provide a short-term solution, especially in cases where scale, distance or the end use case would not justify pipeline construction [59]. From a market perspective, our stakeholder engagement and existing research [60] [61] suggest that compressed pipelines are critical to ensure the competitiveness of Scottish hydrogen in European market. This is because alternative delivery methods and hydrogen derivatives are associated with substantially higher costs. Without a subsea pipeline, other renewable resource-rich regions, such as the Middle East, South Africa and South America, may outcompete Scotland in the European market.

Owing to its higher volumetric energy density of 70.85 kg/m³[62], it is possible to transport the same amount of liquified hydrogen in a smaller tanker compared to gaseous hydrogen. Compared to compressed hydrogen pipelines, this option is still relatively expensive per volume of hydrogen transported, with the liquefaction process estimated to add up to almost half the total cost of hydrogen transport [63]. Liquified ammonia has been shown to be the lowest cost of selected hydrogen derivatives over long distances [26]. When ammonia is used directly as a feedstock, it is not necessary to reconvert the ammonia to hydrogen upon arrival.

Direct use of hydrogen derivatives is further discussed in section 4.2. Our research used offshore high-voltage direct current interconnectors as a reference point, as they are also suitable to alleviate curtailment issues to some extent. Despite no ‘conversion costs’, transporting renewable electricity through HVDC cables could have higher costs compared to repurposed hydrogen pipelines due to efficiency and flexibility restrictions, described within Section 5.1.1.2.

Figure 14: Levelised cost of delivering hydrogen Source: International Energy Agency (IEA) (2022)

Technical feasibility

Subsea high voltage cables are highly mature, with a technology readiness level (TRL) of 9 and nine electricity interconnectors already connecting Great Britain to neighbouring countries [64]. However, congestion issues, relatively low efficiency over long distances and the lack of long-term flexibility could make electricity interconnectors less suitable to export larger amounts of renewable energy compared to hydrogen technologies [7] [65] (Table 15)

Transporting hydrogen through new-built pipelines is a mature technology (TRL 9), with more than 2,000 km of pipelines operational in Europe [26]. Given limited commercial deployment, repurposed pipelines have lower technical maturity (TRL 7) [26]. Investigation into the repurposing of networks is ongoing in the UK as part of National Gas Transmission’s FutureGrid project [66]. Scotland has 17,000 miles of gas pipeline [67], with an additional 100% hydrogen North Sea pipeline being considered as part of the Hydrogen Backbone Link. This would enable export of hydrogen from Scotland to Germany through a 10 GW hydrogen pipeline by 2045, transporting 2.4 kt of hydrogen per day [4] [68]. Liquified hydrogen has been used for a long time, with the first liquefaction taking place in 1898 [69]. As liquified hydrogen has not been produced on a commercial scale, it has a TRL level of 8 [70] [63].

Although conversion and reconversion processes are needed, the simpler handling and higher hydrogen density of hydrogen derivatives make them more attractive. While some liquified ammonia could boil off during transport (approximately 0.098 % /day) [63], ammonia loss is less significant compared to liquified hydrogen, given the relatively high boil point of -33 °C. Stakeholders agreed that while low-carbon hydrogen production is in its infancy, ammonia production and shipping has competitive advantage in technical maturity compared to other derivatives. While no ammonia or liquid hydrogen port projects have been announced in Scotland, some of the existing infrastructure, for example LNG and LPG terminals, can also be repurposed to reduce capital costs [71]. Strategically important Scottish ports are discussed in further detail in Table 11. The final step in the value chain is ammonia cracking, splitting ammonia into hydrogen and nitrogen molecules. Ammonia crackers are not as mature as ammonia synthesis plants and have an overall TRL between TRL 4 and 6 [72].

The main technical advantage of LOHCs, for example methylcyclohexane (MCH) and dibenzyl toluene (DBT), is that they are compatible with existing liquid fuel assets, with no boil off during shipping. While interest in LOHCs is limited in Scotland, some UK-based developers are investigating this technology. Magnesium hydride has a volumetric H₂ density of 106 kg H₂/m³, which makes it a suitable alternative to ammonia in ports that do not allow its import or export, due to stringent safety regulation. Magnesium hydride is easier to handle than ammonia, and magnesium as feedstock is widely available, reducing total costs. Some stakeholders highlighted the increasing need for the HSE’s updated guidance on hydrogen safety, with most stakeholders mentioning the lack of guidance on hydrogen planning and permitting as a significant bottleneck. Several UK-based projects, including, HyDus [73], HEOS [74] and HydroStar [75], are investigating metal hydride technologies. Further research is being undertaken to increase the uptake efficiency and the dehydrogenation process, which does not require high temperatures. Our stakeholder engagement suggests that strategic co-location of hydrogen derivative plants with other heat-intensive processes could offer additional efficiency gains through heat recovery. Strategic planning with holistic and regional approach, however, is critical to unlock these opportunities. Technical advantages and disadvantages are displayed in further detail in Table 12.

Sustainability

Overall greenhouse gas (GHG) emissions associated with hydrogen and derivative transport are highly sensitive to the fuel and technology used for the conversion, transport and reconversion processes, also known as hydrogenation and dehydrogenation. Among all hydrogen and derivative transport methods, compressed hydrogen pipelines are associated with the lowest greenhouse gas emissions [76], with low energy requirement and compression being easy to decarbonise. Other derivatives, like ammonia and LOHC, require more energy, with some of the processing and transport methods being hard-to-decarbonise [77]. As Haber-Bosch synthesis accounts for approximately one third of all energy consumed in the ammonia production process [78], it is critical that any future ammonia plants are designed to run on low-carbon energy. However, only a limited amount of work has been done on electrifying ammonia synthesis and cracking [79]. A 2022 E4Tech research paper found that low-carbon ammonia would not necessarily meet the UK Low Carbon Hydrogen Standard even if electricity were to be used for ammonia synthesis [76]. Ammonia and most LOHCs are toxic to humans and marine ecosystem, with further sustainability and environmental concerns detailed in the Table 14.

Industrial feedstock

Economic implications

Low-carbon hydrogen can be integrated into ammonia and oil refining processes without significant modifications to existing equipment. This infrastructure readiness may offer cost benefits. As highlighted by stakeholders, there is better economic case for using ammonia directly compared to reconverting it to hydrogen. This is because costs and efficiency losses associated with reconversion, also known as dehydrogenation, can be avoided [80]. In Table 4, ammonia production and refining are not assigned economic RAG ratings due to the lack of a viable low-carbon alternative for reference. The future cost competitiveness of synthetic methanol remains uncertain, given the unknowns surrounding hydrogen and biogenic CO₂. Existing research, however, suggests that bio-based methanol could be produced at a cost up to 55% lower than synthetic methanol [13]. Conventional methanol plants can also operate on bio-feedstock. The economic competitiveness of green steel varies, with a RAG rating of green and amber, depending on the chosen technology. Despite high costs, DRI technology is expected to capture a growing share of the green steel market due to its carbon neutrality. As sustainability becomes a priority, hydrogen-based iron reduction will likely become more cost competitive, gradually reducing reliance on highly polluting blast furnaces [81].

Technical feasibility

In contrast to ammonia and refining plants, synthetic methanol production necessitates significant infrastructure investment or substantial upgrades. The process requires the capture and storage of high purity biogenic CO₂, with the technology currently at a TRL of 8-9 [13]. These plants operate at high efficiencies, ranging from 89 to 95% [82]. However, multiple stakeholders have emphasised the growing need for strategic planning, especially on regional scale, due to the geographical misalignment between biogenic CO₂ and hydrogen supplies which is a challenge to efficient production. For steel production, electrolytic hydrogen has been successfully demonstrated for DRI, but it has not yet reached commercial scale (TRL 7) [83]. Currently, it is estimated that less than 1% of steel in Europe is produced using DRI [84], with the majority of planned DRI projects yet to be operational [85]. Steel production in Scotland has declined in recent years, with annual output falling below 6,000 tonnes of crude steel [86]. Although some plants have outlined their decarbonisation strategies, the path to fully decarbonising Scottish steelmaking remains uncertain. When asked about technical challenges, most stakeholders were not concerned about early-stage technical maturity. Stakeholders suggested that the complexity of the planning and permitting process and the length of consideration are more significant bottlenecks in project development.

The use of low-carbon hydrogen in oil refining and fertiliser production presents minimal technical challenges, as the transition primarily involves fuel switching. INEOS intends to use low-carbon hydrogen, starting as early as 2029 [87]. However, with no ammonia and fertiliser production facilities in Scotland, interest in ammonia production is limited. Meanwhile, plans to establish a renewable methanol plant in Scotland by GEG and Proman are underway [88].

Sustainability

Hydrogen has been used as industrial feedstock for decades, with strict adherence to safety regulations by producers and users. Beyond the environmental benefits associated with fuel switching and decarbonisation, hydrogen also plays a crucial role in desulphurisation which prevents sulphur oxide emissions and reduces the risk of acid rain. While some fugitive emissions may occur (see Table 14), regulations and commercial incentives are in place to minimise these. Further details on environmental impact are detailed in Appendix C.

High temperature heat

Economic viability

Hydrogen has a high gravimetric energy density of 120 MJ/kg compared to 44 MJ/kg of natural gas [89], making it an attractive option for decarbonising high temperature industrial heat. However, hydrogen’s low volumetric energy density compared to natural gas makes it more expensive to store and transport, due to the increased capacities required. For this reason, among others, transitioning to hydrogen as fuel comes with significant costs. For example, converting a furnace in the basic metals sector to hydrogen would cost approximately £730,000 for 10 MW of capacity [10]. It is estimated that £2.7 billion in capital investment would be required to convert UK industrial sites and equipment. CCUS is also considered relatively high cost even though costs are expected to decline with technology maturity [90]. Our stakeholder engagement confirmed that CCUS technologies will become more cost-effective with scale and concentration of demand. The carbon capture process itself is the most expensive component accounting for 80% of the total costs [90]. On the contrary, bio-based fuels are widely available, scalable and cost-competitive in certain locations. Our stakeholder engagement highlighted that while bio-based fuels are widely available today, feedstocks are limited, preventing larger-scale and widespread adoption in the future.

Technical feasibility

Most industrial equipment, such as boilers, kilns, ovens, furnaces, has been demonstrated to be compatible with hydrogen through the Hy4Heat project [10]. While the technology is available, it has yet to be demonstrated at a commercial scale (TRL 7-8; industrial fuel switching). Minor technical challenges persist, including issues with pipe sizes, flue gas composition and different heat transfer characteristics [91]. Additional details on hydrogen heating technical challenges are in Table 13. Many natural gas-fire gas furnaces can be retrofitted, with only certain components requiring modification [91] [92]. However, retrofit options and associated GHG and cost savings depend on the end use sector and the complexity of the industrial site. Our stakeholder engagement confirmed that more trials and demonstration projects are needed to increase the technical readiness of hydrogen technologies and create learnings in a Scottish context.

CCUS systems can be integrated with existing boilers and heaters [93]. However, carbon capture infrastructure requires large investment. The UK’s geological advantage and access to depleted hydrocarbon fields provide a competitive advantage for carbon storage [94]. As pointed out by stakeholders, scale is critical for operating CCUS systems cost-effectively. Therefore, these systems must be strategically located, near concentrated demand, favourable geology and potential biogenic CO₂ offtakers. Although large-scale CCUS projects are not yet operational in Scotland, the Acorn Project has advanced directly to Track 2 of the UK Government’s Cluster Sequencing Programme. By reusing the existing hydrocarbon infrastructure, the Acorn project aims to capture and store between 5 and 10 Mtpa of CO₂under the seabed by 2030 [95].

Hydrogen boiler and indirect dryer	Hydrogen direct dryers and ovens, furnaces	Kilns	Carbon capture (depending on technology)	Biomass technologies
TRL 7 [96]	TRL 4 [96]	TRL 5 [97]	TRL 6-9 [98]	TRL 9[99]

Table 9: Technology Readiness Level of selected high temperature technologies

Solid biomass is a well-established technology, with most biomass boilers, kilns and furnaces achieving a TRL of 9 [99]. While the majority of biomass is currently used to generate electricity, over 37% is utilised to produce heat [100]. Given that CCUS and hydrogen technologies are not yet commercially available, many industrial plants aiming for long term decarbonisation opt for biomass. Unlike hydrogen, biomass can be stored at ambient pressure and temperatures. However, biomass technologies are generally unsuitable for direct heating applications, such as kilns, furnaces and dryers, as they may affect the product quality [99].

Sustainability

Burning hydrogen does not produce CO_2, but it can generate increased levels of nitrogen oxides (NOx) compared to natural gas combustion due to the higher temperatures used [101]. Nitrogen oxides are a mixture of gases, worsening air pollution, impacting human health and, reacting with other gases, indirectly contributing to global warming. However, research indicates that the higher stable combustion temperature of hydrogen may offset NOx emissions [102]. This is because the increased air to fuel ratio enabled by hydrogen leads to lower combustion temperatures which in turn reduces NOx emissions [102]. While CCUS technologies cannot capture 100% of CO₂ emissions, pairing them with biomass kilns and furnaces may result in negative emissions. Additional details on sustainability benefits and challenges are provided in Table 14.

Transport

Economic implications

For LDVs, Fuel Cell Vehicles (FCVs) achieving cost parity with fossil fuel powered LDVs before 2040 will be challenging, unless the fuel cell costs decrease due to higher volume production. When looking at 5-year total cost of ownership, fuel cell powered and battery electric powered LDVs will likely be close or marginally lower than fossil fuel powered LDVs by 2040 [103]. The Advanced Propulsion Centre conducted a battery and fuel cell vehicle cost comparison for a range of vehicle types. Findings included that fuel cell powered vans will be the preferred technology type by 2030 [104].

Fossil methanol has an established global market, with synthetic methanol production growing each year [105]. Existing ships and vessels that run on liquid fossil fuels, like diesel and kerosene, can be retrofitted to run on low-carbon, synthetic liquid fuels, like methanol, allowing owners to avoid the capital cost of a new ship. Although sales of methanol dual-fuel ships have significantly increased in recent years [106], the high cost of synthetic methanol may change commercial incentives [107]. Our stakeholder engagement also suggests that ammonia will be the dominant maritime fuel in the short and medium-term due to the lower cost of the fuel. This is in line with the analysis of the IEA estimating the cost of synthetic methanol production to be 25 to 100% higher than the production cost of low-carbon ammonia [107]. The difference in fuel costs is partially due to the high cost and limited availability of biogenic CO₂, making methanol ships uncompetitive in the long-term, especially once ammonia technologies are mature. This is despite the higher transport and storage cost of ammonia, requiring cooling and compliance with a range of national and international regulations.

According to the International Air Transport Association (IATA) the average price of jet fuel in 2022 was roughly £3.18 per gallon, a 149% increase on the previous year, yet comparatively, in 2022, the current average price of SAF within the US was £7 per gallon [108]. While the IATA estimates that all SAF products are 2-4 times more expensive than alternative aviation fuels [108], costs could reduce with the emerging SAF mandate.

Technical feasibility

Hydrogen fuel cells have faster refuelling times than Battery Electric Vehicles (BEVs), making them well suited for long heavy-duty trips [16]. Fuel cells also have other potential applications in maritime, rail and aviation (HyFlyer) sectors. The Scottish Government has funded multiple hydrogen buses in Aberdeen that have been successfully implemented since 2015 [109]. On the whole, fuel cells have a high TRL, however this can vary slightly by use case. For example, the Aerospace Technology Institute label a generic fuel cell as TRL 8, with a fuel cell in aviation use cases at TRL 5 [110].

Ships can be retrofitted for ammonia engines easier than for fuel cells, which need a complete makeover of the engine infrastructure. Ammonia blends of 70% have been successfully implemented [111] in certain engines. The energy transfer chain of ammonia has a number of conversions resulting in efficiency losses. From the initial renewable energy produced, 17% will make it to the ship’s propeller [112]. On the other hand, it is more complicated to produce synthetic fuels in large quantities limiting the long-term applications. Ammonia must be stored at -33◦C. This gives e-fuels a storage advantage, as the conditions are much milder and not different to the current fuels used. The IEA’s report on International Shipping reports that in 2022, 90 (11% by tonnage) new-build orders were for ammonia-ready vessels, 43 (7%) were for methanol vessels and 3 were for hydrogen-ready vessels [113]. SAF encompasses a range of technologies or SAF production pathways, detailed in Table 10.

TECHNOLOGY	TECHNOLOGY READINESS
Hydrogen fuel cell engine in light vehicles	TRL of 9
Hydrogen fuel cell engine in heavy vehicles	TRL of 7-9
Sustainable Aviation Fuel	TRL of 9 (HEFA)
Low-carbon methanol as a maritime fuel	TRL of 9
Low-carbon ammonia as a maritime fuel	TRL of 9

Table 10: Technology readiness of transport technologies

Sustainability

Whilst SAFs release carbon when burned, they could reduce carbon emissions by 80% over the lifecycle compared to traditional jet fuel [114], while having similar combustion characteristics and safety considerations. Ammonia burns less easily and is less flammable than conventional shipping fuels, and therefore is safer from a health and safety perspective [115]. Hydrogen fuel cells do not result in any emissions of greenhouse gases when in use [116]. Further sustainability benefits and challenges are detailed in the Table 14.

Power generation

Economic implications

The capital cost associated with large scale hydrogen peaking plants is estimated to be between £350 and £600 per kW, whereas capital costs associated with fossil fuel based peaking plants is between £300-600 per kW [117] [118]. The overall cost of electricity, however, will depend on several factors, for example, load factor, efficiency of the turbine, heat and water recovery [119]. While large scale hydrogen power plants can technically provide both mid-merit and peaking generation, they are expected to be cost competitive when running as a peaking plant and below a load factor of 20-30% [118] [120]. This is due to higher operating costs compared to low-carbon alternatives. Despite additional costs, there is an economic case for retrofitting existing natural gas power plants with CCS (Table 17). This is because retrofitting is estimated to extend the lifetime of a power plant by 10 years, resulting in substantially lower capital costs [23]. The estimated cost of retrofit is around £110 per kW compared to the new-build gas turbine’s capital cost of £740 per kW [120]. Due to increasing scale and simplification, it is estimated that the cost of CCS-power plants could reduce by 45% after the first three installations, with technical innovation leading to an additional reduction of 5-10% thereafter [121]. With widely available biomass supply and highly mature technology, unabated biomass generation is currently the most prevalent among the selected technologies. However, as CCS technologies become commercially available, unabated biomass generation is anticipated to be phased out. This is due to the relatively high cost of power generation. While retrofitted hydrogen plants could reach a levelised cost as low as £65 per MWh in 2035, the Contract for Difference of biomass plants guarantees £100 per MWh (2012 prices) [23]. The levelized cost for unabated gas plants may reach £170-£180 per MWh while gas CCS plants’ levelized costs are estimated to be £75-£90 per MWh [23]. Despite this challenging economic case, biomass plants coupled with CCS technology are expected to have high potential due to substantial carbon benefits. While the cost of hydrogen-fired turbines could reduce over time, they are expected to be used for low load factor operation, with CCUS-enabled power generation running on higher load factors.

Technical feasibility

While only minor alterations are required to existing gas power plants to reach hydrogen/gas blends around 70% [122], 100% hydrogen power plants have more potential in the long term due to higher carbon benefits. Retrofit to 100% hydrogen plants is also technically feasible, with a few technical challenges including changes to pipes and combustors due to differences in hydrogen’s volumetric density. Ammonia is the least mature power generation technology among the four. A few projects have demonstrated the viability of co-firing up to 20% and 70% with coal and natural gas, respectively [123]. Some technical challenges such as flame stability, and the low combustion speed of ammonia do not only make ammonia-fired power generation less efficient than the baseline but also result in incompatibility with larger gas-turbines [124]. The main technical advantage of biomass power plants is that existing coal power plants can be easily retrofitted to run on biomass. Given high technical maturity, capacity for electrical generation from biomass in the UK reached 12% of all capacity in 2023 [125]. Despite high hydrogen potential, there is limited experience with hydrogen power generation in Scotland. The Peterhead Power Station is planned to be coupled with CCUS technology as part of the Acorn project, positioning the facility as one of the first CCUS-enabled gas power plants. In addition, there are eight major diesel generation sites in Scotland used as backup supply for remote locations [64] [126]. A few hydrogen power projects, like the Kirkwall Airport CHP, are operational in Scotland, but further trials are needed, particularly on remote Scottish Islands, to provide learnings of this sector in a Scottish context, according to our stakeholder engagement. Further technical details can be found in Table 17.

Sustainability

Main sustainability concerns include CO₂ leakage rate from underground reservoirs, ammonia’s toxicity and NOx emissions. Due to high carbon benefits, a 2018 CCC Biomass report concluded that available biomass should be used with BECCS applications ‘to the maximum extent possible’ [127]. Further sustainability challenges and benefits are detailed in Table 14.

Offtaker Market Assessment

Existing demand

Figure 15: Import of hydrogen in 2023 in selected countries [33]

Figure 16: Value of ammonia trade in EU, Belgium, Germany and the Netherlands. Source: Eurostat

Infrastructure log

Country	Name	Type	Description
Shetland, Scotland, UK	Sullom Voe	Terminal	Shetland has some of the most abundant wind resources in the UK but is somewhat isolated from the mainland grid. This makes development of curtailment options including green hydrogen a top priority. Sullom Voe is a deepwater port that already has three existing tanker jetties designed for ultra-large crude oil tankers and one for medium sized LPG tankers. It is suitable for ammonia export based on similarities to the technology currently in use at the terminal for LPG.
Orkney, Scotland, UK	Flotta Terminal	Terminal	Flotta Terminal has a crude oil import pipeline and a jetty. It has been earmarked as the location for Hydrogen Hub Orkney test facility, owing to its remote location and significant industrial space available in the immediate vicinity for hydrogen production. Approval has been obtained for a 220MW interconnector to the Scottish mainland in order to facilitate future offshore wind generation.
Scotland, UK	Port of Cromarty Firth	Port	Plans to produce, use and export (via LOH and liquefaction) hydrogen are already in development. The port has a depth of up to 14m and is able to provide more than 2000m quayside in an ideal location to serve several of the North East ScotWind option areas. It was awarded Green Freeport status in 2023 and this is expected to attract further investment in a number of offshore wind and hydrogen projects.
Scotland, UK	Outer Hebrides Hydrogen Hub		An expansion of the green hydrogen production capacity has been put forward in the updated Energy Strategy for the hub. The Stornoway Port Masterplan included development of a 400m long, 10m deep port, that could accommodate LPG/NH₃ gas carrier vessels that are unable to make use of the 6m port currently in operation. It is well placed to serve the northerly ScotWind option areas.
Scotland, UK	St Fergus Gas Terminal	Terminal	It is the central gathering hub for gas production from the Northern North Sea region and contains the SEGAL system and the SAGE gas terminal. Extensive international (Norway) and North Sea gas pipeline infrastructure have made the terminal the primary candidate for any new hydrogen export pipeline. The site is well positioned to receive any hydrogen produced offshore in the North Sea through these existing gas pipelines. The Acorn project intends to enable production of blue hydrogen, for the domestic market, next to the terminal, as a part of the “Hydrogen Coast” initiative.
Scotland, UK	Grangemouth/Hound point	Terminal (+ refinery)	The Hound point marine terminal appears to be the obvious export port suitable for the loading of VLGC. The company LNG9 have allegedly proposed a blue hydrogen/CSS project in the area already.
England, UK	Port of Immingham	Port	ABP and Air Products are collaborating to construct a jetty at the port that is capable of handling green hydrogen.
England, UK	Stanlow Terminals	Terminal	There has been an announcement of an intention to open a major new import terminal for green ammonia in the port of Liverpool. The new terminal is expected to be able to import and store in excess of one million tonnes (39.4 TWh_HHV) of green hydrogen per year.
England, UK	Teesport	Port	While plans on low-carbon ammonia imports are unclear, Teesport is the main point for ammonia imports for fertiliser production in Teesside.
Antwerp, Belgium	Antwerp NH3 Import Terminal	Terminal	Aims to become a large hydrogen import hub and has excellent connections to the Shell and Exxon Mobil refineries and three steam crackers. A conceptual ammonia storage facility is planned for completion here in 2027.
Zeebrugge, Belgium	Zeebrugge New Molecules development	Other	Conceptual ammonia cracking facility planned for completion in 2030.
Brunsbüttel, Germany	Ammonia Brunsbüttel	Port	Ammonia cracking facility in the feasibility study stage. It has a projected capacity of 300 kt ammonia and a projected 2026 completion date.
Wilhelmshaven, Germany	Green Wilhelmshaven	Other	Ammonia cracking site with an announced size of 295 kt H₂/year).
Hamburg, Germany	Ammonia import at Hamburg	Port	Conceptual ammonia cracking and storage facility at the port of Hamburg – planned for completion in 2026.
Maasvlakte, Netherlands	ACE Terminal	Terminal	Conceptual ammonia cracking and storage facility intended for completion in 2026.
Rotterdam, Netherlands	H2Sines.RDAM	Other	LH2 regassification facility in the feasibility study stage, with an announced size of 100 tpd LH2, with upscaling to 300 tpd and an intended start date of 2028.
Maasvlakte, Netherlands	Global Energy Storage (GES)	Other	Ammonia storage facility in the conceptual stage.
Maasvlakte, Netherlands	OCI Import terminal	Terminal	A terminal that is expected to be expanded to a capacity of 1.8Mt of ammonia
Maasvlakte, Netherlands	Koole & Horisont Energi	Other	Ammonia storage in feasibility study stage.

Table 11: Infrastructure opportunities in Scotland, the rest of the UK and selected European countries

Techno-economic tables

	Round-trip efficiency (%)	Storage temperature (°C)	Gravimetric energy density (MJ/KG)	Volumetric energy density (MJ/L)	TRL	MRL	CRL
Compressed hydrogen pipeline transport	37	Ambient	Depends on pressure	6.456	7-9	N/A	N/A
Liquified hydrogen	9-22	-252.8	120-142	~70.8	6-9	3-6	1-5
Liquified ammonia	22	– 33	21.18- 22.5	107.7-120	7-9;6-7	4-6;3-4	1-5;~1
LOHC	~18	Ambient	7.35	5.66	4-7	1-4	~1
Metal hydrides (magnesium hydride)	N/A	Ambient	26.32	86-109	4-7	1-4	~1

Table 12: Technical table of hydrogen carriers

Sources: [128]; [129]; [130]; [131]; [77]; [132]; [133]

In order to attract investment, hydrogen transport must be financially profitable within a specifically defined niche. A number of methods of hydrogen transport are available, all with differing properties which determine how cheaply and safely the hydrogen can be transported. Although hydrogen is incredibly dense by mass, it takes up a lot of volume, which makes it expensive to transport. It can therefore be compressed or even liquified to decrease the price of transport, or alternatively it can be transported in the form of other substances that contain a large amount of hydrogen but have different properties (for instance density) that make them cheaper to transport. Physical properties such as the volumetric density and storage temperature of each carrier are important factors that would have to be accounted for in the supply chain. On the other hand, technology readiness level (TRL), market readiness level (MRL) and commercial readiness level (CRL) are all technoeconomic properties that reflect how mature each technology is and whether the carrier is likely to be financially viable. Technoeconomic properties are not fixed in the same way as physical properties and so as the technologies develop, certain carriers may become increasingly viable. Ultimately both physical and technoeconomic properties of each transport option must be weighed up and used by decision makers to predict the best course of action.

Hydrogen heat technical challenges

Challenge	Description
Difference in flame speed	The combustion of hydrogen results in a much greater flame speed compared to the combustion of natural gas (1.7 ms^-1compared to 0.4 ms^-1). If existing natural gas combustion equipment is used to combust hydrogen, there is a risk that the flame speed will exceed the gas velocity exiting the burner nozzle. This can cause an event called a “flashback” which can damage the nozzle and other components of the burner.
Adiabatic flame temperature	Hydrogen flames are much hotter than natural gas flames. This is referred to as a large difference in “stochiometric adiabatic flame temperature”. The adiabatic flame temperature of hydrogen is 2,182°C, whereas it is 1,937°C for natural gas – a difference of 245 °C. This temperature increase poses a risk to natural gas combustion equipment if operated with a hydrogen fuel source and additionally increases the NO_xemissions.
Flame emissivity	Hydrogen flames radiate more UV radiation in comparison to natural gas flames, which makes them paler in colour and more difficult to see.
Safety considerations	Hydrogen has a higher flammability limit than natural gas and due to its molecular size (the smallest of all molecules), hydrogen is more prone to leakage. This is most problematic in poorly ventilated or confined situations where the leaking hydrogen cannot diffuse into the atmosphere and thus poses a risk of explosion.

Table 13: Technical challenges with high temperature heat equipment

Sources: [134]; [135]

Environmental log

Impact Sub-category	Description		Hydrogen derivative
		Emissions reduction
NO_x	Nitrogen oxides are a mixture of gases, worsening air pollution, impacting human health and, reacting with other gases, indirectly contributing to global warming. Ammonia typically generates high NOx levels during combustion, however recent research and development suggests that ammonia can be used to reduce NOx emissions at the point of combustion [136].		Hydrogen, ammonia
CO₂	Combusting ammonia significantly reduces CO₂ emissions, and any CO₂produced can be stored in geological storage in Scotland that have reliable leakage rates below 0.1% [137].
Fugitive hydrogen emissions	Hydrogen leakages in the NH₃-H₂ conversion process are estimated at 5% but stringent protocols and advanced processes are designed to minimise this risk [138] [139].
CO₂	Utilises captured CO₂ in production, offsetting any released CO₂ and lowering atmospheric concentrations [140].		Synthetic methanol
SO_x and NO_x	Produces fewer NOx and SOx during combustion compared to fossil fuels [141].		Synthetic methanol
CO₂	Use of SAFs reduces lifecycle CO₂ emissions by up to 80% compared to conventional jet fuel [114] and SAFs made from biomass or waste materials can be carbon neutral [142].		SAF
Indirect emissions	SAF as a drop in solution, is compatible with existing engines, reducing additional emissions by eliminating the need for new infrastructure [143].		SAF
		Air quality
Particulate Matter	Upon combustion ammonia produces significantly less particulate matter [144].		Ammonia
Particulate Matter	Burns cleaner than fossil fuels, producing less particulate matter [13].		e-methanol
Particulate Matter	Typically generates fewer particulates and soot due to lower amounts of aromatics and sulphur [145] [146]. Evidence shows a reduction in contrail cloudiness when using SAFs [147].		SAF
	Resource depletion and land use
Resource demand	The ammonia-hydrogen conversion process is energy intensive, requires significant volumes of water and involves extracting critical minerals for catalysts, potentially impacting direct or indirect land use changes [148] [149]/		Ammonia
Land Use Competition	Challenges arise if crops are specifically grown to capture biogenic CO₂, leading to land use competition. Thus, other CO₂ sources, like concentrated or engineered carbon capture, are preferred [150].		e-methanol
Use of renewable feedstock	SAF can be produced from waste materials or renewable sources like algae or plant oils, reducing the need for virgin resources and minimising land use competition [145], [151]. However, using food crops for SAF production displaces food crops, leading to the expansion of cropland into forests and grasslands, which reduces natural carbon sequestration [151] .		SAF
	Ecotoxity
Environmental contamination	While ammonia is linked to eutrophication and acidification of soil and water bodies which impacts ecosystems [152], the effect is highly dependent on several factors and relatively higher concentration of ammonia [112].		Ammonia
Environmental contamination	Methanol is less toxic to the environment than many conventional fuels. Spills or leaks are less harmful and easier to remediate due to its quick evaporation. In addition, methanol does not dissociate into ions when dissolved in water, avoiding acidification [153].		e-methanol
Environmental contamination	Current reports indicate potential toxicity to aquatic life and suggest that certain SAF production methods may contribute to eutrophication [154].		SAF
	Human / General toxicity
Acute toxicity	Ammonia is highly toxic and corrosive, posing life threatening health risks upon exposure though acute toxicity is usually a result of direct contact with it [155].		Ammonia
Flammability	Ammonia is not highly flammable but can form explosive mixtures with air at certain uncontrolled concentrations [155].		Ammonia
Chemical exposure	Prolonged, direct exposure to methanol via inhalation or ingestion is harmful to human health but small quantities are not [156].		e-methanol
Flammability	Methanol is highly flammable and poses a significant fire hazard [156].		e-methanol
Chemical exposure	Some SAF production pathways may produce volatile organic compounds or harmful substances, though in minimal quantities [157].		SAF
Combustion emissions	Whilst SAFs produce less particulate matter and NOx than conventional aviation fuels, they still emit fine particles and NOx which can cause respiratory issues when inhaled [146].		SAF

Table 14: Environmental log

	HVDC interconnectors	Hydrogen pipelines	Liquified hydrogen	Ammonia	LOHC	Metal hydride
Energy transfer capacity per project (current maximum)	12 GW [65]	20-30 GW [65]	Depends on ships	Depends on ships	Depends on LOHC type and conditions of transport Example of LOHC type (H-18 DBT): 47 MWh [158]
Technical advantage	Technical maturity and experience	Long-duration, inter-seasonal storage. Potential to decarbonise industrial processes directly. Long-duration, inter-seasonal storage. Potential to decarbonise industrial processes directly.	Long-duration, inter-seasonal storage. Potential to decarbonise industrial processes directly.	Long-duration, interseasonal storage. Potential to decarbonise industrial processes directly.Long-duration, inter-seasonal storage. Potential to decarbonise industrial processes directly.	Long-duration, inter-seasonal storage.	Long-duration, inter-seasonal storage.
Technical advantage	High voltage capacity with low energy to heat losses High power transmission capacity therefore low power losses Efficiency over long distances [65] [159]	Can transport large volumes of energy over long distances [65]	More efficient for long distance transport. Space efficiency by allowing more storage by volume relative to gaseous hydrogen [160]	Established global market High volumetric density thus easier to store and transport Efficiency over long distances [161]	Hydrogenation is exothermic, therefore, while efficiencies are low, heat recovery can increase overall efficiency. [162]	Operates at near room temperature and atmospheric pressure) Enhanced safety during operation No leakage [163]
Technical challenge	Congestion issues Inefficiency over long distances [65] Wind pattern correlation across the North Sea	Metal pipelines are susceptible to embrittlement (mainly an issue for distribution pipes) [65]	Requires high energy demand for liquefaction and regasification of hydrogen Leakage through boil off is common [160]	Intermittent ammonia production is challenging. Conversion and reconversion process are energy taxing [161]	Needs to be purified Needs to be returned after dehydrogenation. Dehydrogenation is endothermic [162]	Tanks can be heavy, due to metal hydrides’ low mass-specific storage density Dehydrogenation requires high temperatures [163]

Table 15: Technical table of hydrogen derivative technologies

Name	Feedstocks	Notes
HEFA – Hydroprocessed Ester and Fatty Acids	Waste and residue fats (vegetable oil) Purposefully grown plants	TRL 8-9. Already used commercially in aviation, as well as in road transport, so pressures on supply exist.
AtJ – Alcohols to Jet	Agricultural and forest residues Sugar or starch crops	TRL 7-8. AtJ (and Gas+FT) can are considered advanced biofuels if produced from REDII compliant feedstocks.
Gas + FT – Biomass Gasification + Fischer-Tropsch	Same as AtJ (listed above) Municipal solid waste	Gas+FT has significant carbon reduction and supply potential.
PtL – Power to Liquid	Hydrogen Carbon dioxide	The CO2 can be sourced from biomass, waste processes (with CCS) or via direct air capture.

Table 16: An overview of SAF production pathways [77]

	TRL [164]	Efficiency (%)	Levelized cost in 2035
Unabated gas (CCGT)	9	57	170-180
CCUS (CCGT)	8	50	75-90
Retrofit hydrogen	7	55	£65-100/MWh
New-built hydrogen	7	55	£90-125/MWh
Unabated biomass	9	20 [165]	£98 per MWh [166] and existing low-carbon contracts are for £100 per MWh (in 2012£)
BECCS	6-7	31-38 [167]	Approximately $170/MWh [168] OR 193 per MWh (2018 prices) [166]
Ammonia	4	50 – 60 Ammonia: zero-carbon fertiliser, fuel and energy store (royalsociety.org)	Approximately between $167 and $197 pwe MWh at 25% power plant capacity factor in 2040 [169]

Table 17: Techno-economic table of power generation technologies

Policy tables

UK Regulatory Barriers

	Policy gap	Description
1	HSE	The safety case for hydrogen still needs to be signed off by the HSE in the UK. This will remove uncertainty and confusion about the potential role of hydrogen in decarbonising heat, and other applications. The uncertainty that currently exists stops stakeholders from forward planning and making strategic decisions.
2	ADR regulation	Hydrogen transport is currently prohibited through ten road tunnels in the UK based on its classification under the European ADR rules (carriage of dangerous goods by road). Reviewing hydrogen-specific ADR regulation, along with restrictions for ammonia and LOHCs, transport efficiency could be significantly increased. However, any changes to these regulations should be dependent on safety cases being proven.
3	Offshore licensing	While it is confirmed that the North Sea Transition Authority will be the licensing and decommissioning body for offshore hydrogen projects [170], the industry seeks more clarity on the timeline and details of future hydrogen regime.
4	Gas Safety Management Regulation (GSMR)	GSMR currently prohibits injecting more than 0.1% hydrogen into the networks. This will need to be updated to unlock the UK’s line pack capacity. The UK Government will make a policy decision in 2023 on whether to allow blending of up to 20% hydrogen by volume into the gas distribution networks [16].
5	Planning and consenting	Our research suggests that developers face a number of constraints surrounding the delivery of critical regulatory consents, particularly planning and environmental permitting. Delays around consenting can significantly extend the lead time of hydrogen storage projects. Some stakeholders suggested streamlining the Nationally Significant Infrastructure Project (NSIP) regime in England and accelerating the consenting process through increasing funding to relevant planning offices across the UK.
6	Gas Act 1986	With no comprehensive hydrogen-specific regulation in place, onshore hydrogen is regulated under the Gas Act 1986 and Planning Act 2008. As hydrogen is defined as “gas” under the Gas Act, most transportation, storage, and supply regulatory requirements of natural gas applies to hydrogen as well.
7	Control of Major Accident Hazard (COMAH) regulation	Control of Major Accident Hazard (COMAH) applies to hydrogen and most of its derivatives, such as ammonia, methylcyclohexane and toluene. Magnesium hydride, however, is not considered a dangerous substance under COMAH. In Scotland, COMAH regulations are enforced by the COMAH Competent Authority.

Table 18: Policy gaps in the UK

International Hydrogen Policy Log

Region	Policy name	Description
European Union	Net Zero Target	The European Union aims to meet net zero emissions by 2050.
European Union	Hydrogen Strategy	The hydrogen strategy for a climate-neutral Europe was adopted in July 2020.
European Union	RePowerEU	The European Commission implemented the REPowerEU Plan to phase out reliance on Russian fossil fuel imports following the invasion of Ukraine.
European Union	REDIII Targets	Transport: RED III fuel suppliers must achieve a 14.5% reduction in GHG emissions associated with their fuels or achieve at least 29% renewables share in the fuel supply. In addition, at least 5.5% of the fuel mix must be composed of advanced biofuels and RFNBOs (combined binding target). Industry: The EUs CBAM Regulation (10th May 2023) will be transitioned in during the period of 2023-2026 and then full force from 2026 onwards. The EU’s Fit for 55 proposals include a 50% renewable share for hydrogen used in industry. RED III – Industry must procure at least 42% of its hydrogen from renewable fuels of non-biological origin (RFNBOS) by 2030, though countries that can achieve a fossil-free hydrogen mix of at least 77% by 2030 can see that target reduced by 20%.
European Union	H2Global	H2Global is live (1st auction closed 2023) and formed through H2 purchase and sale agreements through a central body. Managed windows for funding applications through 10-year hydrogen purchase agreements, competition-based procurement process. As of 06/23, H2Global and the Hydrogen Investment Bank have been linked. Working on a European auction open to all EU countries.
European Union	Hydrogen Bank	Acts through an auction system, fixed price payment per kg. Fixed premium per kg hydrogen produced for a maximum of 10 years of operation. Auctions launched under the Innovation Fund in the autumn of 2023.
European Union	Innovation Fund	The innovation fund hydrogen focussed from Nov 2022. Acts through a competitive bidding process – max bid 4 Euro per kg* – and via waves of calls for proposals.
European Union	IPCEI	Important Project of Common European Interest (IPCEI) are live and provided in waves of grant funding. A requirement for projects must be for them to show they are financially viable without subsidies.
European Union	AFIR	AFIR passed March 2023, detailing one HRS to be deployed every 200km along Ten-T core.
European Union	Fitfor55	Fit for 55: 2.6% target for renewable fuels of non-biological origin (RFNBO) in transport by 2030
European Union	EU ETS	The EU Emission Trading Scheme is a “cap and trade” system that limits the amount of greenhouse gases which can be emitted within the EU.
European Union	EU MoUs	The EU has signed MoUs with Japan, Egypt, Mauritania (and others) around hydrogen including export/imports.
European Union	RED Low Carbon Hydrogen Standard	3.38 kg CO2-eq/kg hydrogen (28 gCO2e per MJ) (70% lower compared to emissions from fossil fuels). Two delegated acts under Renewable Energy Directive published by the Commision in Feb-23 – (i) principle of additionality, (ii) methodology for calculating GGG emissions. Rules to apply to imports.
United Kingdom	Net Zero Target	Net zero by 2050. 78% emission reduction by 2035. Mandated in law. Net Zero power system by 2030.
United Kingdom	UK Hydrogen Strategy	Production target of 10 GW by 2030, with at least 6 GW of this coming from electrolytic production.
United Kingdom	HPBM	Hydrogen Production Business Model – a CFD funding mechanism bridging the difference between producing low-carbon hydrogen gas and the price of natural gas. Funding provided through allocation rounds.
United Kingdom	LCHS	The UK Low Carbon Hydrogen Standard sets a carbon intensity threshold for hydrogen production of 20 gCO2e/MJ (2.4 kg CO2-eq/kg hydrogen). If the hydrogen produced meets this standard, it can be deemed low-carbon and is eligible for government subsidy.
United Kingdom	UK ETS	The UK’s own ETS scheme since leaving the EU.
United Kingdom	SAF Mandate	The UK has formed a SAF mandate stipulating set targets for percentage shares of SAF, and specific production pathways (such as PtL). Headline figure is that 10% of UK aviation fuel will be SAF by 2030.
United Kingdom	RTFO	The Renewable Transport Fuels Obligation
Germany	Net Zero Target	Net zero by 2045. Emissions shall move to net negative after 2050. Germany has set the preliminary targets of cutting emissions by at least 65 percent by 2030 compared to 1990 levels, and 88 percent by 2040 Mandated in law.
Germany	National Hydrogen Strategy	The German hydrogen national strategy was released in 2020 before being an update was released in 2023.
Germany	H2 Global	H2 Global – value €4 billion. Initial auction of 900mn euros launched in Dec 2022 for H2 derivatives. Government plans to make a further 3.5 billion euros available for new bidding rounds with durations up to 2036.
Germany	Carbon Tax	CO2 tax (introduced in 2023) for Avgas and Jet A-1.
Germany	Hydrogen Mobility Targets	Targets include fuel cell trucks, 20 HRS’s and passenger cars, fuel cell buses for public transportation, and the operation of the first inland ship operating on hydrogen by 2025.
Germany	National MOUs	Several MoUs signed surrounding imports of hydrogen and ammonia into the country – Mauritania MoU could equate to 8 million tonnes/year.
The Netherlands	Net Zero Target	Net zero by 2050. 55% CO2 reduction by 2030. In law.
The Netherlands	National Hydrogen Strategy	The Netherlands hydrogen strategy was released in 2020.
The Netherlands	National Climate Agreement	The national climate agreement contains set targets for fuel cell HDVs, passenger cars and hydrogen refuelling stations.
The Netherlands	Carbon Levy	In 2021, introduced carbon levy for industry – complementary to EU ETS – road mapped to 2030 currently.
The Netherlands	Guarantees of Origin Scheme	Green hydrogen Guarantees of Origin operational from Oct-22, following a Bill (May-22) and trial (summer-22).
The Netherlands	H2Global	300mn euro specific funding from H2Global, including funding for ammonia.
The Netherlands	National MoUs	In 2020, the US and the Netherlands signed a statement of intent to collaborate on hydrogen. The Minister of Energy of Chile and the State Secretary for Economic Affairs and Climate Policy signed a joint statement on collaboration in the field of green hydrogen import and export (July 2021). The UAE Ministry of Energy and Infrastructure and the Dutch Ministry for Foreign Trade and Development Cooperation have signed a Memorandum of Understanding on hydrogen energy. As part of their Joint Economic Committee, the UAE and the Netherlands have been in discussions to identify common interests and create a partnership for decarbonisation of the energy sector and increasing the use of clean hydrogen (March 2022).
Belgium	Net Zero Target	Net Zero by 2050, 55% emissions reductions target in place for 2030.
Belgium	National Hydrogen Strategy	Hydrogen strategy enacted firstly in 2021, with an update in 2022. Both strategies focussed on positioning Belgium as an import and transit location for low-carbon molecules into Europe. The country will remain dependent on energy imports in various forms to cover its domestic demand, estimating between 2 and 6 TWh of renewable hydrogen (or derivatives) in 2030 and between 100 and 165 TWh in 2050
Belgium	Energy Transition Fund	The Energy Transition Fund will fund until 2025, providing 20-30 million euros in support. The federal government has also earmarked 60 million euros (including 50 million euros from the national recovery and resilience plan) to invest and support projects to scale up innovative, low-carbon technologies.
Belgium	Hydrogen Act	The Hydrogen Act establishes a regulatory framework for the transport of hydrogen via pipelines. The act intends to foster the growth of the Belgian hydrogen market and the required hydrogen transport infrastructure.

Table 19: International Hydrogen Policy Log

Demand mapping methodology

Overview of Approach

The demand mapping analysis is carried out for five regions and six sectors for the years 2030 and 2045. The analysis only considers low-carbon hydrogen and derivate demand, and not hydrogen demand that does not meet sustainability criteria in the region. The regions covered are chosen based on the regional mapping carried out earlier in this project and include:

The EU
Germany
Belgium
The Netherlands
Scotland, England and Wales

The sectors covered are the ones in which hydrogen may play a role, with a focus on sectors where the role of derivatives and products could be greatest. These include:

Industry
Power Generation
Road Transport
Aviation (with a focus on power to liquid fuels)
International Maritime (with a focus on ammonia and methanol)
Heat

The analysis has taken a high-level approach to develop three scenarios (low, central and high) for each region and sector. In general, the approach taken for the EU and EU national geographies aligns due to similar overarching policy and data sources. While the approach for England and Wales often differs due to different policy and assumptions.

The EU and EU National Geographies (Germany, Belgium and The Netherlands) Sectoral Approach

Industry

The demand mapping for industry utilises data from Eurostat Simplified Energy Balances [171] which gives total demand for energy by industrial sector in the EU and the three EU nation states considered. The change in energy demand and suitability for hydrogen in each sector is based three scenarios developed in N-ZIP model produced for the Climate Change Committee (CCC) [172]. While this source does not give data based on EU suitability, it does give broad indications of sectoral suitability for hydrogen compared to alternatives and is therefore used to produce a low, central and high range of suitability.

An alternative approach has been used for sectors that currently use hydrogen (predominantly the chemicals sector and the refining sector). This is partially due to the EU’s target to ensuring 42% of hydrogen use meets RFNBO criteria in 2030 [54], however it is worth noting that refining is excluded from this target. The approach for the chemicals sector is to use a combination of current estimates of hydrogen demand [173], and calculating the proportion of low-carbon hydrogen that is required to meet the RFNBO target, while assuming the CCC’s reduction in energy demand for the sector by 2030.

While the 42% target does not apply to refineries, it is expected that refining will be an early user of low-carbon hydrogen due to current demand, experience in handling hydrogen and RFNBOs used in refining contributing to RFNBO targets in the transport sector. Hydrogen Europe estimate that there are 1.2 Mt/year of clean hydrogen projects announced in the refining sector by 2030, representing 26% of current hydrogen demand [174]. Furthermore, current hydrogen demand makes up approximately 40% of total energy demand in the sector. For this reason, estimates of total energy demand that is clean hydrogen in 2030 of 5, 10 and 15% have been selected for 2030. All scenarios assume refineries operate on clean hydrogen by 2045.

Industrial Sector (*Different source / approach used for starred sectors)	Reduction in energy use 2022-2030	Proportion of total energy that is clean hydrogen in 2030	Reduction in energy use 2022-2045	Proportion of total energy that is clean hydrogen in 2045
Chemicals*	5-9%	8-9%	4-7%	24-29%
Construction	28-29%	0%	28%	71-80%
Food, beverages & tobacco	17-19%	0-7%	29-32%	15-25%
Iron and steel	0-6%	14-18%	29-36%	29-59%
Other industries	21-25%	0-4%	29-36%	18-37%
Mineral products	18-31%	3-7%	22-40%	25-28%
Non-ferrous metals	32-36%	0%	36-40%	26-28%
Oil and gas extraction	46-49%	4-10%	61-70%	47-50%
Paper, printing & publishing	21-26%	1-5%	44-49%	10-14%
Petroleum refineries*	20-22%	5-15%	29-35%	40%
Vehicles	27-30%	2-8%	29-35%	18-41%

Table 20: Trajectory of proportion of clean hydrogen used energy for the years 2030 and 2045

Industrial demand is broken down by product in 2030 based on applying RED III mandates to historic ammonia and methanol demand by region, developing scenarios based on historic high and low demand levels. Demand for 2045 is estimated, by assuming that all hydrogen demand for these products is low-carbon.

Power Generation

Hydrogen’s role in the power sector is uncertain and depends on policy incentives, infrastructure and technology readiness of turbines. This analysis assumes that total electricity generation in 2030 for the EU, Germany, Belgium and The Netherlands follows the estimates of generation in the MIX-CP scenario developed for European Green Deal Analysis [175]. This scenario was selected as it most closely aligns with policy measures that were agreed upon.

The analysis assumes that total electricity generation in 2045 follows the midpoint of the of the 2040 and 2050 values for the two scenario estimates in a recent European Commission report considering energy infrastructure configurations in Europe [176]. This estimate is used to develop a compound annual growth rate assumption of 4.2% for electricity generation in the EU between the 2030 estimate and 2045 assumption. This compound annual growth rate is applied to regional estimates in the MIX-CP scenario for Germany, Belgium and The Netherlands to estimate annual electricity generation in 2045.

It is broadly accepted that an electricity grid that is dominated by intermittent renewables will require low-carbon dispatchable generation to meet demand at times of low renewable generation. The CCC estimate that in the Balanced Pathway, 13% of electricity demand is met by low-carbon dispatchable power generation in 2045 [177]. However, the split between hydrogen and other options such as gas with CCUS or BECCS is unknown at this stage.

For the purposes of this analysis, the following proportions of electricity generation that are met with hydrogen are assumed. These include no hydrogen to power in 2030 due to the requirement for large scale hydrogen storage to be in place to operate hydrogen power at low load factors, which is its optimal role in the power system [178]. It is unlikely that there will be access to sufficient volumes of hydrogen storage in the 2030 timeframe due to the long lead times for large scale geological hydrogen storage [179]. Hydrogen power generation is assumed to have an efficiency of 48% [180].

Proportion of Total Power Demand that is met by Hydrogen	2030	2045
Low Scenario	0.0%	2.5%
Central Scenario	0.0%	5.0%
High Scenario	0.0%	7.5%

Table 21: Proportion of hydrogen in total power demand

Road Transport

The road transport analysis focuses on vans, buses and HGVs given that heavier vehicles are more suited to hydrogen and lighter vehicles are more suited to battery electric drivetrains. The low and the high scenario are based on the proportion of road transport energy consumption that is hydrogen in 2030 and 2045 in FES 2024 in the highest and lowest hydrogen deployment scenarios. The central scenario is estimated as the midpoint between these upper and lower bounds. The estimated demand for transport by these vehicle segments in 2030 is taken from the MIX-CP Scenario [175], for the EU, Germany, Belgium and The Netherlands.

Scenario	Proportion H2 2030	Reduction in Energy Demand 2030 – 2045	Proportion H2 2045
Low	0.4%	-66%	7.7%
Central	0.5%	-66%	17.7%
High	0.6%	-66%	27.8%

Table 22: Hydrogen Proportions of Energy Demand for Bus and Coach Transport

Scenario	Proportion H2 2030	Reduction in Energy Demand 2030 – 2045	Proportion H2 2045
Low	0.1%	-58%	0.7%
Central	0.1%	-53%	17.3%
High	0.2%	-49%	34.0%

Table 23: Hydrogen Proportions of Energy Demand for Heavy Goods and Light Commercial Vehicles

Aviation

The analysis on aviation focuses on e-fuels which are based on hydrogen combined with captured carbon. The analysis utilises estimates of future aviation fuel demand for the EU and the PtL sub mandate to estimate e-fuel demand in 2030 and 2045, based on a report from the European Union Aviation Safety Agency [181]. The value for total fuel demand in 2045 is estimated by taking the midpoint of the 2040 and 2050 values. This is used to estimate the central demand estimate.

EU Aviation	2030	2040	2045	2050
SAF Mandate (%)	5%	32%	38%	63%
PtL Sub-Mandate (%)	0.70%	8%	11%	28%
Total Fuel Demand (Mt)	46	46	45	44
SAF Supply (Mt)	2.3	14.8		27.7
PtL Supply (Mt)	0.3	3.7	5.0	12.3

Table 24: Projections for supply of SAF

The energy content of these e-fuels is then estimated using the value of 43 MJ/kg [182] to develop estimates in TWh. Both low and high scenarios assume the same mandate for PtL, but varying levels of fuel demand based on the EASA’s low and high aviation scenarios [181].

	2030	2045
Low Scenario Multiplier on Base Case	90%	84%
High Scenario Multiplier on Base Case	115%	124%

Table 25: Multipliers on base case, by scenario

The national estimates for Germany, Belgium and The Netherlands are estimated based on national airport traffic data in 2023 [183]. This assumes that the current mix of air traffic data remains constant over time.

International Maritime

The analysis focuses on international maritime due to its greater suitability for hydrogen, derivatives and products than domestic maritime. This is due to the longer distances travelled in larger ships for international maritime which is less suitable for electrification. The decarbonisation route for ships is uncertain and could be met with biofuels or synthetic fuels. Transport & Environment (T&E) have estimated different routes to decarbonisation that comply with the EU’s FuelEU policy [184]. Note that the analysis carried out for T&E was designed for containerships and different shipping segments may select different decarbonisation routes. However, the authors of the report deemed it to be a good enough proxy to provide a high-level estimate of the entire international shipping sector.

These T&E scenarios are used to estimate the upper and lower bounds of e-fuel deployment in 2030 and 2045. The central scenario is derived as the midpoint of these bounds. The EU’s policy ensures that there is a minimum of 2% RFBNOs from 2034 onwards.

Proportion of International Shipping Demand that is e-fuels	2030	2045
Proportion e-ammonia high (%)	1%	42%
Proportion e-methanol high (%)	4%	4%
Proportion e-ammonia central (%)	0%	21%
Proportion e-methanol central (%)	2%	2%
Proportion e-ammonia low (%)	0%	2%
Proportion e-methanol low (%)	0%	0%

Table 26: Proportion of international shipping demand that is e-fuels

These fuel proportions are applied to the estimated energy demand for international shipping. This is calculated using the CP-MIX scenario as this complies with the fit-for-55 regulation and most closely follows the current policy structure of the energy scenarios produced by the EU Commission [175]. As this scenario only produces estimates to 2030, the growth rate for international shipping energy demand for each region between 2025 and 2030 is applied to the period 2030 to 2045 to estimate international shipping energy demand in 2045. This is deemed appropriate as applying this carbon reduction trajectory from 2025-2030 to the emissions metric results in gross emissions of approximately 14% for the EU in 2050, which should be compatible with achieving net zero provided sufficient greenhouse gas removals are in place.

Heat

The demand for hydrogen in residential heating is highly uncertain and could be significant, or non-existent in 2045. For this reason, and a lack of policy certainty, high level assumptions have been made for hydrogen deployment for heat. It is likely that due to the high efficiency of heat pumps, hydrogen heat would, at most, play a supplementary role in the heating mix. As with other sectors, the residential energy demand is estimated using the MIX-CP scenario and applying the 2025-2030 (negative) growth rate forward to 2045.

Proportion of Residential Energy Demand that is Heat	2030	2045
Low	0.0%	0.0%
Central	0.0%	10.0%
High	0.0%	20.0%

Table 27: Proportion of residential energy demand that is heat

Approach for England and Wales

Industry, Power Generation, Road Transport and Heat

The approach for the industrial, power generation, road transport and heating sectors for England and Wales utilises Future Energy Scenarios (FES) 2024 [185]. This contains three net zero compliant pathways for a decarbonised Great British energy system. In general, Electric Engagement is used for the low scenario, Holistic Transition forms the central scenario and Hydrogen Evolution is used to estimate the high scenario. However, the approach for the power generation sector is different, and the pathway mapping to our scenarios is inverted for Electric Engagement and Holistic Transition to provide consistent results.

The CCC’s Sixth Carbon Budget [177] is used to estimate the proportion of hydrogen demand that occurs in England and Wales for each sector as the FES results estimate demand for Great Britain as a whole. This process is carried out for both 2030 and 2045 periods for the low, central and high scenarios.

Hydrogen Regional Demand Split	Units	2030	2045
Industry England & Wales % of GB	%	88%	89%
Electricity supply England & Wales % of GB	%	97%	94%
Surface transport England & Wales % of GB	%	94%	92%
Non-residential buildings England & Wales % of GB	%	87%	87%
Residential buildings England & Wales % of GB	%	93%	93%

Table 28: Hydrogen regional demand split between England and Wales

The only sector that does not map directly between the Sixth Carbon Budget and FES 2024 is surface transport which includes rail in the Sixth Carbon Budget. The regional split for surface transport is assumed to apply to road transport for this analysis.

To estimate the hydrogen demand reduction from the announcement of the closure of Grangemouth refinery, in September 2024, Gemserv interpreted data and forecasts in NESO’s Future Energy Scenario’s databook [194]. The total demand provided by Grangemouth in each forecast were extracted and multiplied by an assumption on what proportion of this demand was forecasted as being served by hydrogen. This proportion was assumed to follow the forecasted mix between fuels of oil, hydrogen and gas for total Industry and Commercial sector.

Scenario		2030			2045
Scenario		Input Grange-mouth Demand (Twh)	Hydrogen proportion of Industrial fuel mix %	Adjustment (Twh)		Input Grange-mouth Demand (Twh)	Hydrogen proportion of Industrial fuel mix %	Adjustment (Twh)
Low	Electric Engagement	0.19	12%	0.02		0.41	49%	0.20
Mid	Holistic Transition	0.18	33%	0.06		0.33	74%	0.25
High	Hydrogen Evolution	0.19	39%	0.08		0.35	82%	0.28

Table 33: Grangemouth refinery hydrogen demand adjustment.

Aviation

The UK has announced its intentions for a SAF mandate which increases the proportion of SAF in the aviation fuel mix, this policy also includes a PtL sub mandate [186]. For this obligation to be met, PtL derived fuels must meet 0.5% of aviation fuel consumption in 2030, rising to 3.5% by 2040. The PtL sub mandate increases by 0.4% points for the five years between 2036 and 2040 [187]. For the purposes of this analysis, it is assumed that this trajectory continues and the PtL sub mandate increases to 5.5% by 2045.

Total aviation demand for the UK in the years 2030 and 2045 is based on the CCC’s Sixth Carbon Budget, utilising the Widespread Innovation and Tailwinds scenarios as these are the highest and lowest demand scenarios for aviation fuel. The central scenario is estimated as the midpoint between these. To estimate SAF demand in England and Wales, the regional split from the Balanced Pathway annual SAF demand is applied. England and Wales are estimated to be responsible for 94% and 93% of UK demand respectively for the years 2030 and 2045.

International Maritime

The UK generally does not report on energy consumption in the international maritime sector; however, T&E have developed analysis that estimates over 7 million tonnes of fossil marine fuel oils are used in the total maritime sector [184]. For the purposes of this analysis this is assumed to be exactly 7 million tonnes. The energy content of this fuel is estimated using EU Commission assumption of 40.5 MJ/kg for Marine Gas Oil (MGO) [188]. It is assumed that international maritime makes up 80% of fuel consumption based on the emissions estimates produced by T&E. Major port freight activity is used to estimate the proportion that occurs in England and Wales, estimated to be 81% of the UK total [189]. The proportional change in total energy demand for shipping is assumed to be the same for England and Wales and the assumptions made for the EU as a whole.

Once estimates of fuel demand in 2030 and 2045 are estimated, the proportion of this that is met with hydrogen derivates is applied to estimate derivative demand in the two time periods. The analysis assumes that the UK achieves less in terms of e-fuel deployment than the EU by 2030 due to its less ambitious policy in the sector. However, the UK Government has recognised a requirement to have at least 1% low-carbon shipping fuels by 2030. The analysis assumes that this is entirely met by e-fuels for the high scenario, half met by e-fuels for the central scenario and entirely met by other options such as biofuels for the low scenario. Due to the low technology readiness of ammonia as a shipping fuel, it is assumed that the 2030 demand is met with e-methanol. This is also in line with DNV data on fuel choices for ships on order, where 8% are methanol powered on gross tonnage basis [190]. For 2045 the assumptions for England and Wales follow that of the rest of the EU reflecting the international nature of shipping refuelling requirements.

Additional Tables and Graphs for Projected Demand

Figure 17: Mix of different sectors and derivatives in all three scenarios for the years 2030 and 2045

Note: Industrial demand figure is an aggregate of hydrogen, ammonia and methanol demand, with road transport figure showing 100% hydrogen demand. Heat notes domestic heating demand only.

Figure 18: Demand scenarios for the EU for all three scenarios

Figure 19: Hydrogen demand scenarios for 2030 for all the regions

Figure 20: Hydrogen demand scenarios for 2045 for all the regions

High Hydrogen Demand Scenario (TWh)	EU		Germany		Belgium		Netherlands		England and Wales
High Hydrogen Demand Scenario (TWh)	2030	2045	2030	2045	2030	2045	2030	2045	2030	2045
Industry: Hydrogen	153.6	525.4	37.2	132.2	5.5	18.9	7.5	28.0	14.1	50.6
Industry: e-Ammonia	48.9	116.4	9.1	21.7	4.2	10.1	6.7	15.8	3.0	7.2
Industry: e-Methanol	4.6	11.0	2.9	6.8	0.0	0.0	0.4	0.9	0.0	0.0
Power: Hydrogen	0.0	441.2	0.0	86.4	0.0	13.3	0.0	23.2	3.6	73.1
Road: Hydrogen	0.8	129.0	0.3	21.0	0.1	6.5	0.1	3.9	1.3	35.7
Aviation: e-fuels	4.4	73.4	0.6	10.4	0.1	1.9	0.2	3.3	0.7	6.8
Maritime: Ammonia	3.5	209.2	0.2	13.9	0.6	30.8	1.0	59.5	0.3	20.8
Maritime: Methanol	20.8	18.5	1.2	1.2	3.5	2.7	5.8	5.2	0.3	1.8
Heat: Hydrogen	0.0	327.9	0.0	67.0	0.0	9.8	0.0	13.3	0.5	70.5
Total	236.6	1851.9	51.6	360.7	14.0	93.9	21.5	153.1	23.8	266.5

Central Hydrogen Demand Scenario (TWh)	EU		Germany		Belgium		Netherlands		England and Wales
Central Hydrogen Demand Scenario (TWh)	2030	2045	2030	2045	2030	2045	2030	2045	2030	2045
Industry: Hydrogen	129.0	484.6	32.2	122.9	5.1	18.0	7.0	26.0	10.0	31.7
Industry: Ammonia	40.3	96.0	7.5	17.9	3.5	8.3	5.5	13.1	2.5	5.9
Industry: Methanol	4.3	10.3	2.7	6.4	0.0	0.0	0.4	0.9	0.0	0.0
Power: Hydrogen	0.0	294.1	0.0	57.6	0.0	8.8	0.0	15.5	0.9	29.7
Road: Hydrogen	0.6	62.1	0.2	10.1	0.1	3.1	0.0	1.8	1.2	18.9
Aviation: e-fuels	3.8	59.3	0.5	8.4	0.1	1.6	0.2	2.6	0.6	5.4
Maritime: Ammonia	1.7	109.6	0.1	7.3	0.3	16.1	0.5	31.1	0.1	10.9
Maritime: Methanol	10.4	9.2	0.6	0.6	1.8	1.4	2.9	2.6	0.1	0.9
Heat: Hydrogen	0.0	163.9	0.0	33.5	0.0	4.9	0.0	6.6	0.5	13.1
Total	190.2	1289.2	43.9	264.6	10.8	62.2	16.4	100.3	15.9	116.6

Low Hydrogen Demand Scenario (TWh)	EU		Germany		Belgium		Netherlands		England and Wales
Low Hydrogen Demand Scenario (TWh)	2030	2045	2030	2045	2030	2045	2030	2045	2030	2045
Industry: Hydrogen	68.8	436.8	19.0	106.8	3.3	16.6	4.5	26.1	1.6	7.5
Industry: Ammonia	31.8	75.7	5.9	14.1	2.8	6.6	4.3	10.3	2.0	4.7
Industry: Methanol	4.0	9.6	2.5	5.9	0.0	0.0	0.3	0.8	0.0	0.0
Power: Hydrogen	0.0	147.1	0.0	28.8	0.0	4.4	0.0	7.7	0.0	9.4
Road: Hydrogen	0.4	4.7	0.1	0.7	0.0	0.2	0.0	0.1	1.0	2.1
Aviation: e-fuels	3.5	49.6	0.5	7.0	0.1	1.3	0.2	2.2	0.6	4.1
Maritime: Ammonia	0.0	9.9	0.0	0.7	0.0	1.5	0.0	1.5	0.0	1.0
Maritime: Methanol	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Heat: Hydrogen	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Total	108.5	733.4	28.0	164.0	6.1	30.6	9.4	48.7	5.2	28.7

Summary: Hydrogen Delivery Method

	H2 pipeline	Liquid H2	Ammonia	LOHC	Metal hydride
Method of usage	High volume gaseous hydrogen delivery.	High volume liquified hydrogen delivery, reconverted back to gaseous form upon delivery.	NH3 delivery, used directly (as a fuel; for chemicals production), or reconverted back to hydrogen.	Reconverted back to hydrogen upon delivery.	Reconverted back to hydrogen upon delivery.
Advantages	High efficiency. Low cost over long duration Continuous supply ability.	High volumetric energy density. Increased efficiency compared to gaseous hydrogen transportation. Flexibility in transport destination.	High volumetric energy density Established market. High efficiency over long distances. Ambient conditions.	Heat recovery during hydrogenation reaction. Ambient conditions.	Ambient conditions No leakage. Enhanced safety
Disadvantages	High investment cost. Low flexibility.	Very low temperatures required, leading to high costs. Reconversion to gaseous hydrogen is also energy intensive. High boil-off rate reduces efficiency.	High energy requirement of conversion and reconversion. Safety concerns around the handling of ammonia.	Purification and dehydrogenation are energy intensive. The LOHC must be returned in a dehydrogenated state to be reused, adding to transportation costs.	High temperatures required for dehydrogenation. Storage tanks are heavy due to a low mass-specific storage density.

Summary: Industrial Feedstock

	Ammonia	Methanol	Refining	Green Steel
Method of usage	H2 required for NH3 production. End uses involve fertiliser, plastic or synthetic fibre production.	H2 required for synthetic and conventional methanol production. The methanol is then used within chemicals production for polymers and hydrocarbons.	H2 is needed for hydrocracking and hydrotreating within oil refining, both crucial steps within the refinery process. End uses include fossil fuels and biofuels.	Hydrogen can be used to produce steel, acting as a reducing agent for iron ore, via the hydrogen-based direct reduced iron (DRI) method. End uses include current uses for steel.
Advantages	Mature market. Well-established technology. Currently transported in large volumes. Existing infrastructure available. Increases efficiency when NH3 is used for chemicals production compared to reconversion back to hydrogen.	Mature market. High demand for low-carbon methanol, and bio-methanol production alone will be unlikely to fulfil demand.	Large current market via fossil fuel production. Growing market of biofuels will require hydrogen for refining. Existing infrastructure available.	A method of reducing emission from the carbon-intensive steel industry. Mature market with high demand.
Disadvantages	No current ammonia production facilities in Scotland. The use of low-carbon hydrogen can increase costs.	Infrastructure development required. The use of low-carbon hydrogen can increase costs. Bio-based methanol likely to be more cost competitive than synthetic methanol. Scottish methanol production capabilities currently are lacking, although there are plans for a renewable methanol plant underway.	Fossil fuel refining demand expected to decline. The use of low-carbon hydrogen can increase costs.	New infrastructure required. Production route is higher cost than current steel production. No current steel production facilities in Scotland.

Summary: High-Temperature Heat

	Hydrogen	CCUS-enabled Gas	Bio-based Products
Method of usage	Existing heat equipment can be retrofit to use hydrogen, supplying direct and indirect heat up to 1000°C.	Current industrial heat equipment is fitted with carbon capture technology, and the carbon is stored to reduce emitted emissions.	Biofuels such as biomass or biomethane can be used for high temperature heat, usually up to temperatures of 200°C although higher temperatures could be used, depending on the biomass form.
Advantages	Current gas systems can be retrofit for hydrogen use. High energy density of hydrogen. Very high temperatures reached. Can be low or zero carbon depending on the hydrogen production route.	Current gas systems and feedstocks can be used. Scotland is geographically favoured for CCUS storage facilities.	Widely available, scalable and can be cost-competitive. Can be stored under ambient conditions. Scottish production abilities are promising.
Disadvantages	Retrofitting can be complicated due to the difference in combustion properties between H2 and natural gas. The cost of low-carbon hydrogen is much larger than current sources of high temperature heat fuels. Storage requirements of high pressures or low temperatures due to low volumetric density. Technology not fully mature.	Cost of CCUS integration can be high due to high investment costs. Cannot capture 100% of carbon emissions.	Feedstocks are limited, slowing further adoption.

Summary: Transport

	Hydrogen (fuel cell)	SAF	Methanol (maritime)	Ammonia (maritime)
Method of usage	Hydrogen can be used in a fuel cell vehicle, for example in road and rail transport. Heavy good vehicles have been shown to suit fuel cells economically, but lighter vehicles show some uncertainty.	SAFs are a type of liquid biofuel for aviation, produced via feedstocks of synthetically via a process that captures carbon from the air. They are equivalent to Jet A1 aviation fuel and are compatible with modern aircraft.	H2 required for synthetic and conventional methanol production. This methanol can then be used directly as a fuel for maritime application.	H2 required for NH3 production. This ammonia can then be used directly as a fuel for maritime application.
Advantages	Zero emissions Hydrogen refuelling is similar to current petrol refuelling. Faster refuelling times and longer ranges than battery counterparts. Fuel cell buses have been used in Scotland since 2015.	Easily integrated into current operations. Little alternatives for aviation decarbonisation currently, leading to growing market. Can reduce carbon emissions by over 80% compared to jet fuel.	Not many alternatives other than ammonia for longer distance maritime travel, leading to a growing market. Existing infrastructure can be retrofit to run on methanol.	Not many alternatives other than methanol for longer distance maritime travel, leading to a growing market. Lower cost of ammonia production, compared to synthetic methanol. Existing infrastructure can be retrofit to run on ammonia.
Disadvantages	High costs of operation due to the high cost of low-carbon hydrogen and expensive equipment required.	When produced from feedstock, can compete with other uses of the feedstock e.g. crops and water supplies. Not fully mature market. Higher cost than conventional jet fuels. Release carbon when burned.	High cost of synthetic methanol.	Relatively high transport and storage cost, due to cooling and compliance. Efficiency losses due to extensive energy transfer chain.

Summary: Power Generation

	Hydrogen	CCUS-enabled Gas	Biomass	Ammonia
Method of usage	Hydrogen can be used in turbines to meet electricity demand when electricity generation via renewable is not sufficient.	Natural gas turbines, coupled with CCUS, is a method of providing energy using existing infrastructure and fuel feedstock, while reducing carbon emissions.	Biomass can be used in turbines to meet electricity demand when electricity generation via renewable is not sufficient.	Ammonia can be used in turbines to meet electricity demand when electricity generation via renewable is not sufficient.
Advantages	Suitable for low-load factors. Hydrogen/gas blends possible. Retrofit of gas infrastructure available.	Retrofitting extends the life of the power plant, reducing capital costs. Suitable for high-load factors. Plans for a CCUS-coupled power plant in Scotland.	Widely supplied and highly mature technology. Suitable for high-load factors.	Ammonia production is a mature technology.
Disadvantages	High operating costs. Retrofit to 100% hydrogen requires more significant modifications due to differences in volumetric density. Limited experience with hydrogen power generation in Scotland.	CO₂ leakage from underground storage is a concern.	Can depend on feedstocks which could be required for other purposes, e.g. food and water. Relatively high cost of power generation.	Least mature power generation technology. Low efficiency and incompatibility with larger gas-turbines. High toxicity.

Stakeholder Engagement Approach

We interviewed stakeholders for one hour, following a semi-structured format. Interviews began by presenting the scope of the project and gathering high level thoughts on the storage technologies considered as well as identifying any potential gaps in scope. Questions were structured around the seven evaluation criteria in the scope of the project. The topics focused on in interviews are shown with the list of stakeholders below.

List of stakeholders

Enquest
Net Zero Technology Centre
Centrica
Hydrogen Europe
Air Products
DNV
Johnson Matthey
INEOS
Scottish Futures Trust

Broad topics

Which hydrogen derivates are likely to dominate the market?
Which industries/ sectors are likely to be the main offtakers for HDPs?
Which countries or regions would you consider main import/ demand hubs?
What are some of the policy gaps and bottlenecks for hydrogen projects?
What are the most likely end users for hydrogen products?

Key findings

Most stakeholders suggest ammonia to dominate the European market. Some stakeholders also mentioned SAF (in addition to ammonia), green methanol and green diesels.
There are several concerns about policy gaps and bottleneck too. Concerns include but are not limited to: concerns about subsidising export, absence of trade policies with other EU nations, lack of uniform approach to global carbon pricing, planning and permitting issues causing complexity.
Stakeholders also mentioned some security concerns associated with ammonia like toxicity and difficulty in detecting leaks.
Stakeholders expect Southern and Northern Europe to be the new major hubs for hydrogen demand.
The most likely end-use sectors for hydrogen are fertilisers, shipping and aviation.
Finally, the stakeholders also identified some Scotland specific challenges. Scotland will have to compete with both nearby regions like the EU and faraway regions like the middle east, north America and even Australia.

Table of units

Abbreviation	Unit	Quantity
MJ/kg	Megajoules per kilogram	Energy content per unit of mass
MJ/m³	Megajoules per cubic meter	Energy content per unit volume
MW	Megawatt	Power output
GW	Gigawatt	Power output
MWh	Megawatt hour	Energy
TWh	Terawatt hour	Energy
Wh/kg	Watt-hours per kg	Energy stored in one kg
Wh/l	Watt-hour per litre	Energy stored in one litre
gCO_2e	Grams of carbon dioxide equivalent	Amount of GHG equivalent to CO₂ emitted (in grams)
kgCO_2e	Kilograms of carbon dioxide equivalent	Amount of GHG equivalent to CO₂ emitted (in kilograms)
gCO2e/MJ	Grams of carbon dioxide equivalent per megajoule	Carbon intensity

References

[1]	Scottish Government, “Draft Energy Strategy and Just Transition Plan,” 10 January 2023. [Online]. Available: https://www.gov.scot/publications/draft-energy-strategy-transition-plan/.
[2]	Scottish Government, “Scottish hydrogen: assessment report,” 2020. [Online]. Available: https://www.gov.scot/publications/scottish-hydrogen-assessment-report/.
[3]	Scottish Government, “Hydrogen Action Plan,” 2022. [Online]. Available: https://www.gov.scot/publications/hydrogen-action-plan/.
[4]	NZTC, “Enabling Green Hydrogen Exports: Matching Scottish Production to German Demand,” 2023. [Online]. Available: https://www.netzerotc.com/reports/enabling-green-hydrogen-exports-matching-scottish-production-to-german-demand-2/.
[5]	European Commission, “eur-lex.europa.eu,” 2022. [Online]. Available: https://eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=CELEX:52022DC0230.
[6]	F. Kerle, M. Herborn, S. Prickett, O. Arup and P. Ltd, “climatexchange.org.uk,” 2023. [Online]. Available: https://www.climatexchange.org.uk/wp-content/uploads/2024/01/CXC-Cost-reduction-pathways-of-green-hydrogen-production-in-Scotland-%E2%80%93-total-costs-and-international-comparisons-Jan-2024.pdf.
[7]	Hydrogen UK, “Recommendations for the Acceleration of Hydrogen Networks,” 2023.
[8]	European Hydrogen Observatory, “Hydrogen Demand,” 2023. [Online]. Available: https://observatory.clean-hydrogen.europa.eu/hydrogen-landscape/end-use/hydrogen-demand.
[9]	IEA, “Renewables 2023,” January 2024. [Online]. Available: https://www.iea.org/reports/renewables-2023.
[10]	Hy4Heat, “Conversion of Industrial Heating,” Department for Buisness, Energy & Industrial stratgey , 2019.
[11]	IEA, “The Future of Hydrogen,” IEA, 2019.
[12]	E. B. F. B. Marco Scomazzon, “Alternative sustainable routes to methanol production: Techno-economic and environmental assessment,” Journal of Environmental Chemical Engineering, 2024.
[13]	IRENA, “Innovation Outlook: Renewable Methanol,” 2021. [Online]. Available: https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2021/Jan/IRENA_Innovation_Renewable_Methanol_2021.pdf.
[14]	IEA, “Net Zero Roadmap: A Global Pathway to Keep the 1.5 °C Goal in Reach,” September 2023. [Online]. Available: https://www.iea.org/reports/net-zero-roadmap-a-global-pathway-to-keep-the-15-0c-goal-in-reach.
[15]	G. P. T. &. A. K. Stark, “To decarbonize industry, we must decarbonize heat,” Joule, 2021.
[16]	Yanfei Li and F. Taghizadeh-Hesary;, “The economic feasibility of green hydrogen and fuel cell electric vehicles for road transport in China,” Elsevier, 2022.
[17]	T. C. C. D. Ainalis D, “Technoeconomic comparison of an electric road system and hydrogen for decarbonising the UK’s long-haul road freight,” 2023. [Online]. Available: https://www.sciencedirect.com/science/article/pii/S2210539522001353.
[18]	L. H. D. V. W. Z. Rout C, “A comparative total cost of ownership analysis of heavy duty on-road and off-road vehicles powered by hydrogen, electricity, and diesel,” 2022. [Online]. Available: https://www.ncbi.nlm.nih.gov/pmc/articles/PMC9803793/.
[19]	A. S. Marta Yugo, “A look into the role of e-fuels in the transport system in europe (2030-2050),” Concawe Reviwe, 2019.
[20]	EASA, 2022. [Online]. Available: https://www.easa.europa.eu/eco/eaer/topics/sustainable-aviation-fuels/current-landscape-future-saf-industry#production-capacity-and-demand-2020-to-2030.
[21]	B. A. H.-R. R. Kistner L, “Potentials and limitations of battery-electric container ship propulsion systems,” 2024. [Online]. Available: https://www.sciencedirect.com/science/article/pii/S2590174523001630.
[22]	A. Bajic, “Linde to supply liquid hydrogen for Norled’s ferry,” Offshore Energy, 8 March 2021.
[23]	CCC, “Delivering a reliable decarbonised power system,” March 2023. [Online]. Available: https://www.theccc.org.uk/publication/delivering-a-reliable-decarbonised-power-system/.
[24]	BEIS, “Capacity Market 2023: strengthening security of supply and alignment with net zero – Consultation Description,” 9 January 2023. [Online]. Available: https://www.gov.uk/government/consultations/capacity-market-consultation-strengthening-security-of-supply-and-alignment-with-net-zero.
[25]	International Energy Agency, “Global Hydrogen Review 2022,” 2022. [Online]. Available: https://www.iea.org/reports/global-hydrogen-review-2022.
[26]	IEA, “Global Hydrogen Review 2022,” 2022.
[27]	DESNZ, “Joint Declaration of Intent on establishing a United Kingdom – Germany hydrogen partnership,” Gov.uk, 2023.
[28]	NZTC, “Hydrogen Backbone Link: Connecting Scotland to Europe,” 2023. [Online]. Available: https://www.netzerotc.com/reports/hydrogen-backbone-link-report/.
[29]	The CCC, “Delivering a reliable decarbonised power system,” 9 March 2023. [Online]. Available: https://www.theccc.org.uk/publication/delivering-a-reliable-decarbonised-power-system/.
[30]	Gas for Climate, “Facilitating hydrogen imports from non-EU countries,” 2022. [Online]. Available: https://gasforclimate2050.eu/wp-content/uploads/2022/10/2022_Facilitating_hydrogen_imports_from_non-EU_countries.pdf.
[31]	Port of Rotterdam, “Rotterdam to supply Europe with 4.6 megatons of hydrogen by 2030,” mAY 2022. [Online]. Available: https://www.portofrotterdam.com/sites/default/files/2022-05/Rotterdam%204.6%20Mton%20hydrogen%20in%202030%20proposition.pdf.
[32]	Port of Rotterdam, “Import of hydrogen,” 2024. [Online]. Available: https://www.portofrotterdam.com/en/port-future/energy-transition/ongoing-projects/hydrogen-rotterdam/import-of-hydrogen.
[33]	WITS, “Hydrogen Imports by Country 2023,” 19 July 2024. [Online]. Available: https://wits.worldbank.org/trade/comtrade/en/country/ALL/year/2023/tradeflow/Imports/partner/WLD/product/280410.
[34]	DBT, “Hydrogen,” 19 July 2024. [Online]. Available: https://www.great.gov.uk/international/content/investment/sectors/hydrogen/.
[35]	DESNZ, “Renewable Energy Planning Database January 2023,” January 31 2023. [Online]. Available: https://www.gov.uk/government/publications/renewable-energy-planning-database-monthly-extract.
[36]	EHO, “Beglium,” 19 July 2024. [Online]. Available: https://observatory.clean-hydrogen.europa.eu/index.php/node/2169.
[37]	B. Schroot, “The Netherlands: a Blue Hydrogen economy now will ease a transition to Green,” Energypost.eu, 26 April 2021.
[38]	DESNZ, “Low Carbon Hydrogen Agreement,” 2022. [Online].
[39]	DESNZ, “assets.publishing.service.gov.uk,” 2023. [Online]. Available: https://assets.publishing.service.gov.uk/media/64d380559865ab000dc8fad6/low-carbon-hydrogen-agreement-standard-terms-and-conditions.pdf.
[40]	DESNZ, “Hydrogen projects: planning barriers and solutions,” December 2023. [Online]. Available: https://www.gov.uk/government/publications/hydrogen-projects-planning-barriers-and-solutions.
[41]	European Commission, “2050 long-term strategy,” 2020. [Online]. Available: https://climate.ec.europa.eu/eu-action/climate-strategies-targets/2050-long-term-strategy_en.
[42]	European Commission, “Hydrogen,” 2020. [Online]. Available: https://energy.ec.europa.eu/topics/energy-systems-integration/hydrogen_en.
[43]	RePowerEU, “COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE EUROPEAN COUNCIL, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS,” European Comission , Brussels, 2022.
[44]	H2Global, “H2Global,” 2021. [Online]. Available: https://www.h2-global.org/.
[45]	Hydrogen TCP-Task 42, “Underground Hydrogen Storage: Technology Monitor Report,” 2023. [Online]. Available: https://www.ieahydrogen.org/task/task-42-underground-hydrogen-storage/.
[46]	Bundesregierung, 2021. [Online]. Available: https://www.bundesregierung.de/breg-de/schwerpunkte/klimaschutz/climate-change-act-2021-1936846.
[47]	German Federal Government, “National Hydrogen Strategy Update,” Federal Ministry for Economic Affairs and Climate Action, 2023.
[48]	The British Geological Survey, “Written Evidence Submitted by The British Geological Survey (BGS),” January 2021. [Online]. Available: https://committees.parliament.uk/writtenevidence/19568/html/.
[49]	Belgium Federal Government, “Belgium’s Roadmap for the Net-Zero Government Initiative,” 2021. [Online]. Available: https://www.sustainability.gov/pdfs/belgium-nzgi-roadmap.pdf.
[50]	Westwood Global Energy Group, “The Netherlands vs Belgium: Who will win the battle as Northwest Europe’s leading hydrogen import hub?,” 16 November 2023. [Online]. Available: https://www.westwoodenergy.com/news/westwood-insight/westwood-insight-the-netherlands-vs-belgium-who-will-win-the-battle-as-northwest-europes-leading-hydrogen-import-hub.
[51]	Government.nl, “Government Strategy on Hydrogen,” Government of the Netherlands , 2020.
[52]	FGov.Be, “Vision and Strategy Hydrogen Update,” belgium gov, 2022.
[53]	International Energy Agency, “Towards hydrogen definitions based on their emissions intensity,” April 2023. [Online]. Available: https://www.iea.org/reports/towards-hydrogen-definitions-based-on-their-emissions-intensity.
[54]	European Commission, “Renewable Energy Directive,” 2023. [Online]. Available: https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:32023L2413.
[55]	E. Commission, “The role of hydrogen in energy decarbonisation scenarios,” 2022.
[56]	E. H. Backbone, “Analysing Future Demand, Supply and Transport of Hydrogen,” 2021.
[57]	DESNZ, “Hydrogen Projects: planning barriers and solutions: research findings,” 2023. [Online]. Available: https://assets.publishing.service.gov.uk/media/657a2a92095987000d95e086/hydrogen-projects-planning-barriers-and-solutions-report.pdf.
[58]	Scottish Government, “Boosting Scotland’s planning system,” 10 September 2024. [Online]. Available: https://www.gov.scot/news/boosting-scotlands-planning-system/.
[59]	Q. V. Dinh, P. H. Pereira, V. Nguyen, A. J. Nagle and P. G. Leahy, “Levelised cost of transmission comparison for green hydrogen and ammonia in new-build offshore energy infrastructure: Pipelines, tankers, and HVDC,” International Journal of Hydrogen Energy, vol. 62, pp. 684-698, 2024.
[60]	Arup, “The potential for exporting hydrogen,” May 2024. [Online]. Available: https://www.arup.com/insights/the-potential-for-exporting-hydrogen-from-the-uk-to-continental-europe/.
[61]	M. Iliffe and K. Gilmore, “Can green hydrogen produced in the UK be competitive in the emerging global market?,” 6 July 2023. [Online]. Available: https://www.baringa.com/en/insights/low-carbon-futures/can-green-hydrogen-produced-be-competitive/.
[62]	C. Chu, K. Wu, B. Luo, Q. Cao and H. Zhang, “Hydrogen storage by liquid organic hydrogen carriers: Catalyst, renewable carrier, and technology – A review,” Carbon Resources Conversion, vol. 6, no. 4, pp. Pages 334-351, 2023.
[63]	M. Aziz, “Liquid Hydrogen: A Review on Liquefaction, Storage, Transportation, and Safety,” Institute of Industrial Science, The University of Tokyo, 2021.
[64]	DESNZ, “Digest of UK Energy Statistics (DUKES): electricity,” 2024. [Online]. Available: https://www.gov.uk/government/statistics/electricity-chapter-5-digest-of-united-kingdom-energy-statistics-dukes.
[65]	A. Patonia, V. Lenivova, R. Poud and C. Nolden, “Hydrogen pipelines vs. HVDC lines: Should we transfer green molecules or electrons?,” Oxford Institute for Energy Studies, Oxford, 2023.
[66]	National Gas, “FutureGrid,” 2024. [Online]. Available: https://www.nationalgas.com/future-energy/futuregrid.
[67]	Scottish Government, “Scotland’s electricity and gas networks: vision to 2030,” 12 March 2019. [Online]. Available: https://www.gov.scot/publications/vision-scotlands-electricity-gas-networks-2030/pages/4/.
[68]	NZTC, “netzerotc.com,” 2023. [Online]. Available: https://www.netzerotc.com/reports/hydrogen-backbone-link-report/.
[69]	U. Schmidtchen, “FUELS – SAFETY \| Hydrogen: Overview,” in Encyclopedia of Electrochemical Power Sources, Elsevier, 2009, pp. 519-527.
[70]	J. Incer-Valverde, J. Mörsdorf, T. Morosuk and G. Tsatsaronis, “Power-to-liquid hydrogen: Exergy-based evaluation of a large-scale system,” International Journal of Hydrogen Energy, vol. 48, no. 31, pp. 11612-11627, 2023.
[71]	Scottish Government, “Offshore wind to green hydrogen: opportunity assessment,” 21 December 2020. [Online]. Available: https://www.gov.scot/publications/scottish-offshore-wind-green-hydrogen-opportunity-assessment/.
[72]	M. El-Shafie, S. Kambara, S. P. Katikaneni, S. N. Paglieri and K. Lee, “Techno-economic study and process simulation for a small-scale hydrogen production plant based on ammonia decomposition,” International Journal of Hydrogen Energy, vol. 65, pp. 126-141, 2024.
[73]	HyDus, “hydus.org,” HyDus, 2024. [Online]. Available: https://hydus.org/technology/why-hydrogen-storage/.
[74]	DESNZ, “Longer Duration Energy Storage Demonstration Programme, Stream 2 Phase 1: details of successful projects,” 12 April 2023. [Online]. Available: https://www.gov.uk/government/publications/longer-duration-energy-storage-demonstration-programme-successful-projects/longer-duration-energy-storage-demonstration-programme-stream-2-phase-1-details-of-successful-projects.
[75]	HydroStar, “hydrostar-eu.com,” HydroStar, 2024. [Online]. Available: https://www.hydrostar-eu.com/projects.
[76]	E4Tech, “Expansion of hydrogen production pathways analysis – import chains,” April 2022. [Online]. Available: https://assets.publishing.service.gov.uk/media/62d6f00bd3bf7f2863092502/expansion-hydrogen-production-pathways-analysis-import-chains.pdf.
[77]	S. Csernik-Tihn, J. Mitchell and K. Edlmann, “www.climatexchange.org.uk,” 08 2023. [Online]. Available: https://www.climatexchange.org.uk/wp-content/uploads/2023/08/CXC-Hydrogen-as-storage-medium-August-2023_.pdf.
[78]	R. e. a. Bañares-Alcántara, “Analysis of islanded ammonia-based energy storage systems,” University of Oxford, Oxford , 2015.
[79]	M. Capdevila-Cortada, “Electrifying the Haber–Bosch,” Nature Catalysis, vol. 2, p. 1055, 2019.
[80]	Aurora Energy Research, “Renewable Hydrogen Imports could compete with EU production by 2030,” 25 January 2023. [Online]. Available: https://auroraer.com/media/renewable-hydrogen-imports-could-compete-with-eu-production-by-2030/.
[81]	McKinsey & Company, “Decarbonization challenge for steel,” 2020.
[82]	P. R. Narayanan, “Methanol from CO2: a technology and outlook overview,” PTQ Magazine, 2023.
[83]	IEA, “Iron and Steel Technology Roadmap,” 2020.
[84]	D. K. W. C.-G. M. v. d. B. Annika Boldrini, “The impact of decarbonising the iron and steel industry on European power and hydrogen systems,,” Applied Energy, 2024.
[85]	Agora Industry, “Global Steel Transformation Tracker,” 25 oct 23. [Online]. Available: https://www.agora-industry.org/data-tools/global-steel-transformation-tracker.
[86]	WMG, “Scottish steel industry needs to be revived to thrive,” 19 july 2024. [Online]. Available: https://warwick.ac.uk/newsandevents/pressreleases/scottish_steel_industry/.
[87]	RWE, “rwe.com,” 2024. [Online]. Available: https://uk.rwe.com/press-and-news/2024-05-14-rwe-announces-large-scale-green-hydrogen-plant-in-grangemouth/.
[88]	GEG, “News,” 19 July 2024. [Online]. Available: https://gegroup.com/latest/global-energy-group-and-proman-to-develop-a-renewable-power-to-methanol-plant-at-the-nigg-oil-terminal.
[89]	M. F. A. M. S. M. E. H. A. Mohammad Alhuyi Nazari, “Utilization of hydrogren in gas turbines: a comprehensive review,” International Journal of Low-Carbon Technology , pp. 513-519, 2022.
[90]	Z. G. H. U. R. Mohammed Yussoff Ibrahim, “The Feasibility of Carbon Capturing, Storage and Utilization,” EJ EconJournals , 2015.
[91]	Element Energy, “Hy4Heat WP6 Understanding industrial appliances Industry Workshop,” 10 April 2019. [Online]. Available: https://static1.squarespace.com/static/5b8eae345cfd799896a803f4/t/5caf309a652dea64b686e278/1554985118652/BEIS+Hy4Heat+WP6+-+industry+workshop+handout+F.pdf. [Accessed 30 August 2024].
[92]	British Ceramic Confederation, “Hydrogen for the Ceramics Sector,” 2023.
[93]	B. Oyenekan, “Application of Post Combustion CO2 Capture to Natural Gas Liquefaction Plants,” Elsevier, 2010.
[94]	WSP, Crondall Energy, GEOEnergy Durham, “Deep Geological Storage of CO2 on the UK Continental Shelf,” 2023.
[95]	D. f. E. S. &. N. Zero, “Carbon Capture, Usage and Storage: a vision to establish a competitive market,” 19 july 24. [Online]. Available: https://www.gov.uk/government/publications/carbon-capture-usage-and-storage-a-vision-to-establish-a-competitive-market/carbon-capture-usage-and-storage-a-vision-to-establish-a-competitive-market.
[96]	Element Energy, “Industrial Fuel Switching Market Engagement Study,” December 2018. [Online]. Available: https://assets.publishing.service.gov.uk/media/5d51400bed915d718d63b558/industrial-fuel-switching.pdf.
[97]	Element Energy, “Conversion of Industrial Heating Equipment to Hydrogen,” November 2019. [Online]. Available: https://static1.squarespace.com/static/5b8eae345cfd799896a803f4/t/5e287d78dc5c561cf1609b3d/1579711903964/WP6+Industrial+Heating+Equipment.pdf.
[98]	A. E. P. A. A. A. A. N. L. F. M. Hesamedin Hekmatmehr, “Carbon capture technologies: A review on technology readiness level,” Elsevier Fuel, 2024.
[99]	BEIS, “Industrial fuel switching,” 2018.
[100]	DUKES, “Chapter 6: Renewable sources of energy,” 2024.
[101]	T. B. U. V. B. Fumey, “Ultra-low NOx emissions from catalytic hydrogen combustion,” 2018.
[102]	U. DOE, “Does the use of hydrogen produce air pollutants such as nitrogen oxides?,” 2024. [Online]. Available: https://www.energy.gov/eere/fuelcells/does-use-hydrogen-produce-air-pollutants-such-nitrogen-oxides#:~:text=Because%20hydrogen%20burns%20at%20higher,to%20fuel%20can%20be%20used.. [Accessed 30 08 2024].
[103]	A. Burke, “Projections of the costs of light-duty battery-electric and fuel cell vehicles (2020–2040) and related economic issues,” 2024. [Online]. Available: https://www.sciencedirect.com/science/article/abs/pii/S0739885924000350 .
[104]	APC, “Battery and Fuel Cell Cost Comparison,” 2023. [Online]. Available: https://www.apcuk.co.uk/wp-content/uploads/2023/02/Battery-and-Fuel-Cell-Cost-Comparison-report.pdf .
[105]	B. C. Fasihi M, “Global production potential of green methanol based on variable renewable electricity,” 2024. [Online]. Available: https://pubs.rsc.org/en/content/articlehtml/2024/ee/d3ee02951d.
[106]	IEA, “Global Hydrogen Review 2023,” 2023. [Online]. Available: https://iea.blob.core.windows.net/assets/ecdfc3bb-d212-4a4c-9ff7-6ce5b1e19cef/GlobalHydrogenReview2023.pdf.
[107]	IEA, “The Role of E-fuels in Decarbonising Transport,” 2023. [Online]. Available: https://www.iea.org/reports/the-role-of-e-fuels-in-decarbonising-transport.
[108]	Globalair, “Could SAF Be a Cost-Effective Solution to Rising Aviation Fuel Prices?,” 19 July 2024. [Online]. Available: https://www.flyingmag.com/could-saf-be-a-cost-effective-solution-to-rising-aviation-fuel-prices/.
[109]	S. D. International, “Hydrogen: how it’s decarbonising heavy duty transport,” 19 July 2024. [Online]. Available: https://www.sdi.co.uk/news/hydrogen-how-its-decarbonising-heavy-duty-transport#:~:text=In%20Scotland%2C%20hydrogen%20is%20already,also%20been%20running%20on%20hydrogen.
[110]	ATI, “Fuel-Cells-UK-Capabilities-Overseas-Landscape.pdf,” 2022. [Online]. Available: https://www.ati.org.uk/wp-content/uploads/2022/03/FZO-PPN-CAP-0071-Fuel-Cells-UK-Capabilities-Overseas-Landscape.pdf.
[111]	J. Atchison, “Maritime ammonia: vessel conversions and new engines by 2023,” Ammonia Energy Association , 19 July 2024.
[112]	J. K. Z. M. A. M. M. S. M. S. M. C. K. Machaj, “Ammonia as a potential marine fuel: A review,” Elsevier, 2022.
[113]	IEA, 2022. [Online]. Available: https://www.iea.org/energy-system/transport/international-shipping.
[114]	A. bp, “What is sustainable aviation fuel (SAF),” 19 July 2024. [Online]. Available: https://www.bp.com/en/global/air-bp/news-and-views/views/what-is-sustainable-aviation-fuel-saf-and-why-is-it-important.html.
[115]	DNV, 2022. [Online]. Available: https://www.dnv.com/expert-story/maritime-impact/Harnessing-ammonia-as-ship-fuel/.
[116]	USDOE, [Online]. Available: https://afdc.energy.gov/fuels/hydrogen-benefits#:~:text=Emissions%20from%20gasoline%20and%20diesel,2O)%20and%20warm%20air..
[117]	Element Energy, “Hy-Impact Series Study 3: Hydrogen for Power Generation,” November 2019. [Online]. Available: https://www.element-energy.co.uk/wordpress/wp-content/uploads/2019/11/Element-Energy-Hy-Impact-Series-Study-3-Hydrogen-for-Power-Generation.pdf.
[118]	Aurora Energy Research, “Out of Gas?,” 2021. [Online]. Available: https://auroraer.com/wp-content/uploads/2021/08/Out_of_gas_Public-1.pdf.
[119]	Z. H. X. t. H. Z. Tingting Wei, “Performance evaluation of a hydrogen-fired combined cycle with water recovery,” Eslevier, 2023.
[120]	AFRY, “Net Zero Power and Hydrogen: Capacity Requirements for Flexibility,” The Climate Change Committee, 2023.
[121]	Energy Technologies Institute, “Written evidence submitted to the Parliament by the Energy Technologies Institute (CCU0244),” July 2018. [Online]. Available: http://data.parliament.uk/writtenevidence/committeeevidence.svc/evidencedocument/business-energy-and-industrial-strategy-committee/carbon-capture-usage-and-storage/written/87155.html.
[122]	D. Roddy, “Advanced Power Plant Materials,” Woodhead Publisher, 2010.
[123]	IEA, “The Role of Low-Carbon Fuels in the Clean Energy Transitions of the Power Sector,” October 2021. [Online]. Available: https://www.iea.org/reports/the-role-of-low-carbon-fuels-in-the-clean-energy-transitions-of-the-power-sector.
[124]	A. Valera-Medina, H. Xiao, O.-J. M, W. David and P. Bowen, “Ammonia for power,” Progress in Energy and Combustion Science, vol. 69, pp. 63-102, 2018.
[125]	DUKES, “Table 6.1. Renewable electricity capacity and generation,” 2024. [Online]. Available: https://www.gov.uk/government/statistics/renewable-sources-of-energy-chapter-6-digest-of-united-kingdom-energy-statistics-dukes. [Accessed July].
[126]	Regen, “Distribution Future Energy Scenarios 2022,” April 2023. [Online]. Available: https://regensw.wpenginepowered.com/wp-content/uploads/SSEN-DFES-2022-North-of-Scotland-report.pdf.
[127]	Climate Change Committe, “Biomass in a low-carbon economy,” November 2018. [Online]. Available: https://www.theccc.org.uk/publication/biomass-in-a-low-carbon-economy/.
[128]	A. Raj, I. S. Larsson, A.-L. Ljung, T. Forslund, R. Andersson, J. Sundstrom and T. Lundstrom, “Evaluating hydrogen gas transport in pipelines: Current state of numerical and experimental methodologies,” International Journal of Hydrogen Energy, vol. 67, pp. 136-149, 2024.
[129]	S.Giddet, S. Badwal, C.Munnings and M. Dolan, “Ammonia as a Renewable Energy Transportation Media,” ACS Sustainable Chemistry & Engineering, vol. 5, no. 11, pp. 10231-10239, 2017.
[130]	H. Crolius, “Nh3 vs. MCH: Energy Efficiency of Hydrogen Carriers Compared,” 2019.
[131]	N. Meng, “An Overview of Hydrogen Storage Technologies,” Energy Exploration and Exploitation, vol. 24, no. 3, pp. 197-209, 2006.
[132]	The Oxford Institute for Energy Studies, “Hydrogen storage for a net-zero carbon future,” 04 2023. [Online]. Available: https://www.oxfordenergy.org/wpcms/wp-content/uploads/2023/04/ET23-Hydrogen-storage-for-a-net-zero-carbon-future.pdf.
[133]	S. Chatterjee, R. K. Parsapur and K.-W. Huang, “Limitations of Ammonia as a Hydrogen Energy Carrier for the Transportation Sector,” ACS Energy Letters, vol. 6, no. 12, pp. 4390-4394, 2021.
[134]	Element Energy, “scottish-enterprise.com,” Aoril 2023. [Online]. Available: https://www.scottish-enterprise.com/media/0hwayqis/industrial-report.pdf.
[135]	J. Guarco, B. Langstine and M. Turner, “cea.org.uk,” [Online]. Available: https://cea.org.uk/wp-content/uploads/2021/06/Zeeco-Hydrogen-Article.pdf.
[136]	Royal Society, “Ammonia: zero-carbon fertiliser, fuel and energy store,” February 2020. [Online]. Available: https://royalsociety.org/-/media/policy/projects/green-ammonia/green-ammonia-policy-briefing.pdf.
[137]	c. e. g. d. wsp, “Deep Geological Storage of CO2 on the UK Continental Shelf,” Open Government Licence, 2023.
[138]	I. Dutta, “The Role of Fugitive Hydrogen Emissions in Selecting Hydrogen Carriers,” 2023.
[139]	Frazer-Nash, “Fugitive Hydrogen Emissions in a Future Hydrogen Economy,” March 2022. [Online]. Available: https://www.gov.uk/government/publications/fugitive-hydrogen-emissions-in-a-future-hydrogen-economy.
[140]	Methanol Institute, “carbon footprint of methanol,” 2020.
[141]	IRENA, “INNOVATION OUTLOOK RENEWABLE METHANOL,” 2021.
[142]	Sustainable Aviation, 2020.
[143]	European Environment Agency, 2022.
[144]	E. Nadimi, “Effects of ammonia on combustion, emissions, and performance of the ammonia/diesel dual-fuel compression ignition engine,” 2023.
[145]	ICF, “Fueling net zero: How the aviation industry can deploy sufficient sustainable aviation fuel to meet climate ambitions,” 2021.
[146]	M. Braun, “Pathway to net zero: Reviewing sustainable aviation fuels, environmental impacts and pricing,” Journal of Air Transport Management, 2024.
[147]	C. Voight, “Cleaner burning aviation fuels can reduce contrail cloudiness,” 2021.
[148]	Chatterjee, “Limitations of Ammonia as a Hydrogen Energy Carrier for the Transportation Sector,” 2021.
[149]	S. Ghavam, “Sustainable Ammonia Production Processes,” 2021.
[150]	Searchinger and Heimlich, “Avoiding Bioenergy Competition for Food Crops and Land,” 2015.
[151]	European Aviation Agency, “European Aviation Environmental Report 2022,” 2022.
[152]	Rand Europe, “The impact of ammonia emissions from agriculture on biodiversity,” 2018.
[153]	American Methanol Institute, “EVALUATION OF THE FATE AND TRANSPORT OF METHANOL IN THE ENVIRONMENT,” 1999.
[154]	IBA, “Sustainable Aviation Fuel: How Sustainable Is It Really?,” 2023.
[155]	Public Health England, “Ammonia: general information,” August 2019. [Online]. Available: https://www.gov.uk/government/publications/ammonia-properties-incident-management-and-toxicology/ammonia-general-information.
[156]	Public Health England, “Methanol Toxicological Overview,” 2015.
[157]	A. Lewis, “Future aviation fuels Work Package C3: Interactions Between Mitigation Measures and the Atmosphere,” 2022.
[158]	J. I. Markus Hurskainen, “Techno-economic feasibility of road transport of hydrogen using liquid organic hydrogen carriers,” International Journal of Hydrogen Energy, 2020.
[159]	NREL, “On the Road to Increased Transmission: High-Voltage Direct Current,” 12 June 2024. [Online]. Available: https://www.nrel.gov/news/program/2024/on-the-road-to-increased-transmission-high-voltage-direct-current.html. [Accessed 05 September 2024].
[160]	J. U. Y. H. L. X. S. G. Y. D. Tongtong Zhang, “Hydrogen liquefaction and storage: Recent progress and perspectives,” Renewable and Sustainable Energy Reviews, 2023.
[161]	A. R. I. M. A. Firman Bagja Juangsa, “Production of ammonia as potential hydrogen carrier: Review on thermochemical and electrochemical processes,” International Journal of Hydrogen Energy, 2021.
[162]	R. H. S. B. B. S. B. W. Miao Yang, “ A review of hydrogen storage and transport technologies,” Clean Energy, 2023.
[163]	S. S. T. L. E. R. S. S. G. N. A. T. S. S. P. K. S. Lavanya Mulky, “An overview of hydrogen storage technologies – Key challenges and opportunities,” Materials Chemistry and Physics, 2024.
[164]	IEA, “ETP Clean Energy Technology Guide,” 2023.
[165]	W. Liu, C. Liu, P. Gogoi and Y. Deng, “Overview of Biomass Conversion to Electricity and Hydrogen and Recent Developments in Low-Temperature Electrochemical Approaches,” Engineering, vol. 6, no. 12, pp. 1351-1363, 2020.
[166]	BEIS, “Electricity Generation Costs 2020,” 2020.
[167]	M. Bui, M. Fajardy and N. M. Dowell, “Bio-Energy with CCS (BECCS) performance evaluation: Efficiency enhancement and emissions reduction,” Applied Energy, vol. 195, pp. 289-302, 2017.
[168]	B. Yang, Y. Wei, L. Liu, Y. Hiu, K. Zhang, L. Yang and Y. Feng, “Life cycle cost assessment of biomass co-firing power plants with CO2 capture and storage considering multiple incentives, Energy Economics,” 2021.
[169]	Z. I. M. N.-L. R. M. M. &. B.-A. R. Cesaro, “Ammonia to power: Forecasting the levelized cost of electricity from green ammonia in large-scale power plants,” Applied Energy, vol. 282, p. 116009, 2021.
[170]	DESNZ, “Proposals for offshore hydrogen regulation,” September 2023. [Online]. Available: https://www.gov.uk/government/consultations/proposals-for-offshore-hydrogen-regulation.
[171]	Eurostat, “Simplified Energy Balances,” 2024. [Online]. Available: https://ec.europa.eu/eurostat/databrowser/view/nrg_bal_s__custom_12534402/default/table.
[172]	C. C. Committee, “Deep-Decarbonisation Pathways for UK Industry (Element Energy),” 2020. [Online]. Available: https://www.theccc.org.uk/publication/deep-decarbonisation-pathways-for-uk-industry-element-energy/.
[173]	E. H. Observatory, “Hydrogen Demand,” 2023. [Online]. Available: https://observatory.clean-hydrogen.europa.eu/hydrogen-landscape/end-use/hydrogen-demand.
[174]	H. Europe, “Clean Hydrogen Monitor,” 2023.
[175]	E. Commission, “Policy scenarios for delivering the European Green Deal,” 2021. [Online]. Available: https://energy.ec.europa.eu/data-and-analysis/energy-modelling/policy-scenarios-delivering-european-green-deal_en.
[176]	E. Commission, “Europe’s energy infrastructure configurations : a 2030-2050 outlook,” 2024.
[177]	C. C. Committee, the 6th Carbon Budget Dataset, 2020.
[178]	AFRY, “Net Zero Power and Hydrogen: Capacity Requirements for Flexibility,” 2023.
[179]	ClimateXChange, “Hydrogen as a storage medium in Scotland,” 2023.
[180]	DESNZ, “Electricity generation costs 2023,” 4 August 2023. [Online]. Available: https://www.gov.uk/government/publications/electricity-generation-costs-2023.
[181]	EASA, “European Aviation Environmental Report,” 2022.
[182]	U. D. o. Energy, “Sustainable Aviation Fuel: Review of Technical Pathways,” 2020.
[183]	EuroControl, Airport Traffic Data, 2024.
[184]	T. a. Environment, “The Impact of FuelEU Maritime on EU Shipping,” 2023.
[185]	N. Grid, “Future Energy Scenarios 2024,” 2024.
[186]	DfT, “Sustainable aviation fuel initiatives,” 2024. [Online]. Available: https://www.gov.uk/government/speeches/sustainable-aviation-fuel-initiatives.
[187]	DfT, SAF Mandate Consultation-Stage Cost Benefit Analysis – Dataset, 2023.
[188]	European Commission, “ANNEXES to the Proposal for a Regulation of the European Parliament and of the Council on the use of renewable and low-carbon fuels in maritime transport and amending Directive 2009/16/EC,” 2021.
[189]	DfT, UK major port freight traffic, by port and year, 2024.
[190]	DNV, “Maritime Forecast to 2050,” 2023.
[191]	“Grangemouth Oil Refinery,” The Editors of the Gazetteer for Scotland, 2021.
[192]	P. K. Dhar, V. G, P. V. Rao and G. Sri Ganesh, “Reducing hydrogen consumption in diesel hydrotreating,” Hindustan Petroleum Green R&D Centre, 2018.

Acknowledgements

The delivery team extends thanks to Dr Jamie Speirs, Reader and Deputy Director in the Centre for Energy Policy at Strathclyde University, and Dr Edward Brightman, Lecturer at the University of Strathclyde, for their thorough review and helpful and constructive comments throughout the project. Special thanks go to Dr Nicola Dunn, Project Manager at ClimateXChange, for her continuous support and valuable guidance. We also express our appreciation to the Steering Group for their insightful input and feedback and to the industry stakeholders who contributed to our research, providing essential perspectives.

We would also like to recognise the dedication and hard work of the Gemserv team, including analysts and graphic designers Rachael Quintin-Baxendale, Sandile Mtetwa, Dhairya Nagpal, Isaac Guy, and Thomas Gayton, whose efforts were key in bringing this report to its final form.

How to cite this publication:

Csernik-Tihn, S., Mitchell, J., Wilson, J., Morton, H. (2025) Review of demand for hydrogen derivatives and products’, ClimateXChange. DOI http://dx.doi.org/10.7488/era/5798

While every effort is made to ensure the information in this report is accurate as at the date of research completion, no legal responsibility is accepted for any errors, omissions or misleading statements. The views expressed represent those of the author(s), and do not necessarily represent those of the host institutions or funders.

This work was supported by the Rural and Environment Science and Analytical Services Division of the Scottish Government (CoE – CXC).

ClimateXChange

Edinburgh Climate Change Institute

High School Yards

Edinburgh EH1 1LZ

+44 (0) 131 651 4783

info@climatexchange.org.uk

www.climatexchange.org.uk

If you require the report in an alternative format such as a Word document, please contact info@climatexchange.org.uk or 0131 651 4783.

Distance of less than 2,000 kilometres. ↑
Distance of more than 2,000 kilometres. ↑
Industry includes chemicals and petrochemicals, construction, food, beverages and tobacco, iron and steel, machinery, textile and leather, non-metallic minerals, non-ferrous metals, oil and natural gas extraction, paper, pulp and printing, refineries, and transport equipment. ↑
These demand projections have been revised down to account for the closure of the Grangemouth refinery, announced in September 2024. The demand for the refinery as per NESO’s FES scenarios [194] was reversed, with assumptions according to data availability. The exact methodology used is discussed in Appendix E. ↑

Related projects

Review of demand for hydrogen derivatives and products

		H₂	H₂	NH₃	C₂₁H₂₀	MgH₂
	High voltage inter-connectors	Gaseous H₂ pipelines	Liquid hydrogen	Ammonia	LOHC	Metal hydrides
Economic case (short distance^[1])	AMBER	GREEN	GREEN	AMBER	AMBER	AMBER
Economic case (long distance^[2])	RED	RED	RED	GREEN	AMBER	AMBER
Technical feasibility	GREEN	GREEN	GREEN	AMBER	AMBER	AMBER
Scottish capabilities	GREEN	AMBER	AMBER	RED	RED	RED
Sustainability	GREEN	GREEN	AMBER	AMBER	AMBER	GREEN

	NH₃	CH₃OH
	Ammonia	Methanol	Refining	Green steel
Economic case	N/A	AMBER	N/A	GREEN/AMBER*
Technical feasibility	GREEN	GREEN	GREEN	AMBER
Scottish capabilities	RED	RED	GREEN	AMBER
Sustainability	AMBER	GREEN	GREEN	GREEN
Low-carbon alternative	GREEN	GREEN	GREEN	AMBER

	H₂
	Hydrogen	CCUS-enabled gas	Bio-based products
Economic case	AMBER	AMBER	GREEN
Technical feasibility	GREEN	AMBER	GREEN
Scottish capabilities	AMBER	AMBER	GREEN
Sustainability	GREEN	AMBER	GREEN
Low-carbon alternative	AMBER	N/A	N/A

			CH₃OH	NH₃
	Hydrogen (fuel cell)	SAF	Methanol (maritime)	Ammonia (maritime)
Economic case	AMBER	AMBER	AMBER	GREEN
Technical feasibility	GREEN	AMBER	GREEN	RED
Scottish capabilities	AMBER	AMBER	RED	RED
Sustainability	GREEN	GREEN	AMBER	AMBER
Low-carbon alternative	RED	GREEN	AMBER	AMBER


	SCOTLAND	REST OF THE UK	GERMANY	NETHERLANDS	BELGIUM	WIDER EU
DISTANCE	GREEN	GREEN	AMBER	AMBER	AMBER	AMBER
INFRASTRUCTURE	GREEN	GREEN	AMBER	GREEN	AMBER	GREEN
EXISTING DEMAND	AMBER	AMBER	GREEN	GREEN	AMBER	GREEN
PROJECTED DEMAND	AMBER	GREEN	GREEN	GREEN	AMBER	GREEN
POLICY LANDSCAPE	GREEN	GREEN	GREEN	GREEN	AMBER	GREEN