Charting a Low-Carbon Future Energy System: The Rationale for Hydrogen and other Emerging Energy
Carriers
To my wife, Narges — your unwavering support made this work possible. And to my children, Ariwan and Adrian — you give meaning to my life every single day.
COLOPHON:
This publication is issued by MNEXT, Centre of Expertise for the Materials and Energy Transition of Avans University of Applied Sciences and HZ University of Applied Sciences, on the occasion of the inauguration of Saleh Mohammadi as Professor of Renewable Energy Carriers, delivered on May 23, 2025.
ISBN: 9789465260853
Editing and coordination: MNEXT
Printing and design: De Bondt Grafimedia Communicatie
CONTACT
MNEXT
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Website: www.mnext.nl
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Foreword
In May 2025, I delivered my inaugural speech as Professor of Renewable Energy Carriers, highlighting the urgent need for hydrogen and other emerging energy carriers to achieve our climate ambitions. That occasion reaffirmed my conviction that these technologies must play a central role in the Dutch and EU energy transition.
The Netherlands and Europe are charting an ambitious course toward a low-carbon future. Hydrogen, along with carriers like ammonia and methanol, is poised to support this transition by storing renewable energy and decarbonizing sectors that are hard to electrify. Embracing these energy carriers will not only help meet climate targets but also strengthen energy security and foster innovation.
This book, Charting a Low-Carbon Future Energy System: The Rationale for Hydrogen and Other Emerging Energy Carriers, serves a dual purpose: it is both a scientific resource and a practical guide for strategic decision-making. Through research findings and real-world case studies, it offers evidence-based insights for policymakers and industry leaders on integrating hydrogen and related carriers into energy policy and investments. This dual approach bridges theory and practice, supporting informed decisions in both public and private sectors.
The Renewable Energy Carriers (REC) Research Group has played an instrumental role in bringing this volume to life. The REC group’s broader mission—driving the adoption of sustainable energy carriers to accelerate the transition away from fossil fuels—forms the backbone of this work. Our team’s research and collaborations are woven throughout the chapters, and many of the strategies and case studies discussed here originate part from REC(-led) projects.
I invite you to engage with the vision and knowledge that this book offers. Whether you are a researcher, a policymaker, a student, or an industry professional, I hope the chapters that follow will inspire you to join us on the journey toward a sustainable, low-carbon future. Considerable challenges lie ahead, but if we embrace innovation and collaboration, we can chart a course together toward a cleaner energy future.
Saleh Mohammadi Professor Renewable Energy Carriers
TABLE OF CONTENTS
PART I: THE ENERGY TRANSITION AND ROLE OF RENEWABLES CARRIERS
Chapter
PART II: CORE RENEWABLE ENERGY CARRIERS
Chapter
PART III: NOVEL AND ALTERNATIVE ENERGY CARRIERS
Chapter
PART IV: SYSTEM INTEGRATION &
PART V:
Chapter 1
Introduction: The Low-Carbon Imperative
1.1 THE URGENCY OF DECARBONIZATION
Climate change demands an unprecedented and swift transition away from fossil fuels. The scientific consensus is stark: without immediate and deep reductions in greenhouse gas emissions across all sectors, limiting global warming to 1.5 °C will be beyond reach. In practical terms, global emissions must peak by 2025 and then decline roughly 43% by 2030 to stay on a pathway consistent with the Paris Agreement. This low-carbon imperative underpins international accords and is driving ambitious national strategies.
1.2 POLICY RESPONSES IN EUROPE AND THE NETHERLANDS
Policymakers have begun to respond to this urgency with bold climate goals. In the EU, the European Green Deal and related policies chart a course toward drastic emissions cuts.
The EU’s “Fit for 55” package, established by the European Climate Law, legally requires at least a 55% reduction in net greenhouse gas emissions by 2030 and aims for climate neutrality by 2050.
The Netherlands has likewise enshrined stringent targets in its Climate Act. This law initially set a 49% emission reduction by 2030 and 95% by 2050 (against 1990 levels), but the 2030 goal was later raised to 55% in alignment with the EU’s increased ambition. Achieving these targets will require transformational changes in the energy system. The Dutch government is spurring innovation and investment to meet the challenge.
An example is, the GroenvermogenNL program – backed by National Growth Fund – was launched in 2021 to accelerate green hydrogen innovation and scaleup, positioning hydrogen as a driving force of the Dutch energy transition. Such initiatives illustrate the proactive steps being taken to build a low-carbon economy.
1.3 THE ROLE OF ALTERNATIVE ENERGY CARRIERS
A successful energy transition will hinge not only on renewable electricity but also on alternative energy carriers that can store and deliver low-carbon energy where direct electrification is difficult. Solar and wind power are now mainstream but are intermittent and location dependent. Moreover, many sectors – heavy industry, freight transport, shipping, aviation – face technical constraints that make a direct switch to electricity impractical. This is where energy carriers come in: they enable renewable energy to be converted into chemical or material forms that can be transported, stored, and used on demand across a range of applications.
Hydrogen is a prime example of a versatile clean energy carrier. Green hydrogen contains no carbon and can be stored for long periods. When used, whether in a fuel cell or combusted, it releases energy while emitting only water. Crucially, low-carbon hydrogen can help decarbonize sectors that have been hard to abate. It is one of the few options to reduce CO₂ emissions in steelmaking, cement production, and long-distance transport, and it can also buffer the power system by storing excess renewable electricity for later use. Beyond hydrogen itself, hydrogen-based fuels extend its reach. Ammonia (NH₃), made from hydrogen, is attracting interest as a zero-carbon fuel for shipping and a means to transport hydrogen energy over long distances. Studies suggest ammonia could supply a substantial share of marine fuel demand by mid-century. Similarly, renewable methanol is being explored as a carbon-neutral liquid fuel that could replace diesel or jet fuel in existing engines. These fuels are liquid at ambient conditions, enabling use of familiar fuel infrastructure.
Other innovative carriers are also in development. Liquid organic hydrogen carriers (LOHCs) allow hydrogen to be chemically stored in a stable liquid medium at ambient temperature and pressure, making hydrogen safer and easier to transport in bulk. This technology takes advantage of existing petroleum infrastructure by “loading” hydrogen into an organic liquid and releasing it at the point of use. Meanwhile, metal fuels such as iron powder offer a completely different approach to storing renewable energy. Finely ground iron can be oxidized (burned) to produce heat with no CO₂ emissions, generating iron oxide (rust) as the only byproduct. That rust can then be renewably reduced back to iron fuel, making a closed-loop storage system. This concept has been proven in industrial pilots and appeals to high-temperature industries due to iron’s high energy density, low cost, and easy transport.
In brief, these alternative carriers are essential tools for deep decarbonization. They complement direct electrification by addressing the energy needs of sectors that electricity alone cannot easily serve, thereby expanding the scope of a climate-neutral energy system
1.4 SCOPE OF THE BOOK
This book explores hydrogen and emerging RECs to advance global decarbonization in both energy systems and the chemical industry. It combines technical insights, practical use cases, and policy discussions, highlighting pathways in Dutch and EU contexts.
Part I outlines global energy challenges and the shift toward renewable solutions, stressing the strategic importance of RECs.
Part II examines hydrogen as a key carrier, detailing production methods, applications, and integration challenges. It also covers emerging hydrogen derivatives such as liquefied hydrogen, ammonia, green methanol, and LOHCs, emphasizing their roles in energy transport, and security.
Part III introduces novel carriers, particularly iron as an innovative recyclable fuel. It further offers comparative analyses of different carriers, discussing their integration capabilities within energy systems.
Part IV discusses system integration, infrastructure, technological innovations, and policies necessary for implementing multi-carrier energy solutions effectively within industrial and energy networks.
Part V reflects on the REC Research Group’s objectives and research agenda, identifies strategic opportunities, challenges, and policy recommendations, and concludes with a clear roadmap and vision toward a sustainable, low-carbon future.
By the end of the book, readers will understand the essential role of RECs in achieving climate targets, grasp technical and economic considerations, and appreciate the necessity of a diverse energy carriers portfolio. The aim is to support collaboration among researchers, industry, policymakers, and stakeholders to accelerate the global transition toward resilience and sustainability.
ADVANCING GLOBAL DECARBONIZATION IN ENERGY SYSTEMS AND THE CHEMICAL INDUSTRY.
Part I
THE
ENERGY TRANSITION AND ROLE OF RENEWABLES CARRIERS
Chapter 2
Global Energy Challenges and the Path to Decarbonization: Sectoral Realities and the Limits of Electrification
2.1 OVERVIEW OF CURRENT ENERGY AND EMISSIONS TRENDS
Despite international climate efforts, greenhouse gas (GHG) emissions from the energy sector remain on an upward trajectory. In 2023, energy-related CO₂ emissions rose to a record 37.4 Gt (billion tonnes). Coal use in particular saw growth – over 65% of the 2023 emissions increase was due to higher coal combustion. The rebound of economic activity after the COVID-19 pandemic and increased energy demand (especially in emerging economies) have negated many gains from efficiency improvements and renewables adoption. As a result, the world is not yet on track to meet the Paris Agreement goals. Total GHG emissions (including CO₂, CH₄, N₂O, etc.) reached about 59 GtCO₂-equivalent in 2019 – far above the level required to limit warming to 1.5°C. The Intergovernmental Panel on Climate Change warns that emissions must peak and decline rapidly within this decade to achieve net-zero by 2050 [1];[2]. This context stresses the global energy challenge: how to rapidly transition to low-carbon energy sources while meeting growing energy demand.
A sectoral view of emissions provides insight into key transition focus areas. In 2019, electricity and heat production were the largest contributor to GHG emissions at ~34% of the global total. Industry (manufacturing and refining) was the next-largest source, at ~24%, followed by agriculture, forestry and other land use (~22%). The transport sector contributed ~15%, and buildings (direct emissions from heating/cooking) about 6% [2]. These figures illustrate that roughly three-quarters of GHG emissions come from energy production and use in the electricity, industry, transport, and buildings sectors, with the remainder largely from land use and agriculture (AFOLU) [1].
The following breakdown discusses each major sector, recent trends, and the progress and limitations in reducing emissions.
Figure 1 Global primary energy consumption by source, 1800–2023. Fossil fuels have dominated the energy mix, comprising about 80–85% of primary energy in recent decades. Low-carbon sources account for the remainder, and their share has been gradually rising in the 21st century. Global energy demand reached an all-time high of 620 exajoules in 2023, and this growth in consumption has outpaced the deployment of renewables, leading to continued increases in carbon emissions [3].
Figure 2 Global greenhouse gas emissions by sector (2019) [2]
2.2 SECTORAL BREAKDOWN
Electricity (Power Generation)
The electricity sector accounts for the largest share of energy-related CO₂ emissions (34%), primarily due to coal and gas-fired power plants [2]. Globally, coal remains the dominant fuel for power generation, especially in Asia, and coal combustion alone contributes around 40% of CO₂ emissions from the energy sector [4]. However, the power sector is also where the most significant progress in renewable energy (RE) adoption is underway. In 2022, renewables (solar, wind, hydro, biomass) constituted 83% of new electricity generation capacity additions. By 2023, about 30% of global electricity was generated from renewable sources – a record high share [4]. Solar photovoltaics and wind power have seen exponential growth and cost reductions, leading the expansion of clean electricity. This influx of renewables has begun to bend the emissions curve of the power sector. Despite these gains, fossil fuels still produce the majority (around 60–70%) of the world’s electricity, and many countries continue to invest in new coal capacity. Key challenges for the electricity transition include integrating variable RE sources reliably into grids, phasing out existing coal infrastructure, and extending modern electricity access to underserved populations without boosting emissions.
Industry
The industrial sector (encompassing manufacturing, heavy industry, and mining) is responsible for roughly one-fifth to one-quarter of global GHG emissions [2]. These emissions arise from two main sources: the on-site burning of fossil fuels for heat and power, and process emissions from chemical reactions. Industries such as iron and steel, cement, chemicals, and refining are often termed “hard-to-abate” because they require extremely high-temperature heat or involve chemistry that currently relies on carbonintensive inputs. Coal remains a key energy source for industry (e.g. as coke in steelmaking and in cement kilns), and switching away from coal has proven difficult without alternative technologies that provide the same heat intensity and reducing conditions. Direct electrification options exist for some industrial processes and can improve efficiency and reduce emissions if the electricity is carbon-free. For instance, electric arc furnaces have been widely adopted in secondary steel, and electric boilers or heat pumps can provide low-temperature heat in industries like food processing. However, many core industrial operations cannot be easily electrified with today’s technologies. For primary steel production from iron ore, innovative processes using hydrogen are being pioneered as a replacement for coal-based blast furnaces.
A notable example is the HYBRIT initiative in Sweden, which uses green hydrogen to directly reduce iron ore into iron, releasing water vapor instead of CO₂ [8].
Overall, industry faces a dual challenge: energy efficiency and electrification must improve dramatically, and for processes where direct electrification is infeasible, alternate solutions like hydrogen, and carbon capture will be needed.
Transport
The transport sector (including road, rail, aviation, and shipping) produces about 15% of global GHG emissions and roughly 23% of energy-related CO₂ emissions [3]. Unlike power and industry, transport emissions are almost entirely due to the combustion of petroleumbased fuels (gasoline, diesel, jet fuel) in millions of vehicles and engines worldwide [2]. Road transport is the largest component, and here the transition to low-carbon alternatives is gaining momentum via electrification of vehicles. There are now over 10 million EVs sold annually, and many countries have set targets to phase out internal combustion engine (ICE) cars in favour of EVs in the coming decades. EVs produce zero tailpipe emissions and can dramatically cut transport emissions if the electricity they use is from renewables. For shorterdistance and light-duty transport, battery electric vehicles (BEVs) have proven effective and are scaling up rapidly. However, direct electrification is much more difficult for long-distance and heavy transport modes such as aviation, long-haul trucking, and marine shipping. Batteries today have relatively low energy density compared to liquid fuels. For example, advanced lithium-ion batteries store on the order of 0.2–0.3 kWh per kg, whereas gasoline contains about 12 kWh/kg and hydrogen about 33 kWh/kg [5]. This 50–100× lower specific energy of batteries makes them too heavy for aircraft or ships [6]. Whilst research into nextgeneration batteries and ultra-light materials continues, most studies conclude that aviation and shipping will need energy-dense fuel alternatives rather than battery-electric propulsion for the foreseeable future. Options under development include sustainable biofuels, synthetic electro-fuels (e-fuels) made from green hydrogen and CO₂, and hydrogen-derived fuels like ammonia. For heavy trucking and rail, hydrogen fuel cell systems are also being explored to complement direct electrification. Overall, the transport sector is diverging: electrification is well underway for light vehicles, but hard-to-abate transport segments will likely rely on lowcarbon fuels and hydrogen-based carriers to achieve deep decarbonization.
Buildings
Buildings directly emit about 6% of global GHGs, mainly from burning fossil fuels for heating, hot water, and cooking. When including indirect emissions from electricity and heat use, their true footprint rises to around 20%. Decarbonizing buildings focuses on two strategies: cutting energy demand through better insulation and efficient appliances, and switching to lowcarbon energy. Mature solutions like heat pumps, electric stoves, and solar thermal systems can make operations nearly zero-carbon if powered by renewables. New buildings are moving away from fossil fuels, but retrofitting older ones remains a major challenge—especially in cold climates—requiring investment and policy support. Still, buildings are seen as easier to decarbonize than industry or transport, thanks to ready-to-deploy solutions with long-term benefits.
2.3 LIMITATIONS OF DIRECT ELECTRIFICATION IN HARD-TO-ABATE SECTORS
While electrification is a cornerstone of the energy transition, there are significant limitations to direct electrification in certain sectors often labelled “hard-to-abate.” These are segments of industry and transport for which electricity cannot easily substitute fossil fuels given current technologies. The reasons include technical feasibility, cost, and the physics of energy density. Heavy industries like steel, cement, and chemicals rely on extremely high temperatures (over 1000 °C) and often use carbon as part of the chemical process. Electrifying these processes is difficult and expensive, both in terms of equipment and operating costs. In some cases, such as cement production, CO₂ is released as part of the chemical reaction itself—so even using green electricity will not fully eliminate emissions without carbon capture [7].
Take steelmaking as an example: traditional blast furnaces use coke not just for heat, but also to remove oxygen from iron ore. Electric arc furnaces can not do this without a reducing agent. Green hydrogen offers a solution here, acting as a clean reducing agent to replace coke. But producing enough hydrogen requires a major increase in renewable electricity supply [8].
In the transport domain, the limitation of batteries in terms of energy density and weight is a fundamental barrier for certain applications. As noted, today’s best batteries carry only a few hundred Wh per kg, whereas liquid hydrocarbon fuels carry tens of thousands of Wh per kg [5]. This means that for long-range aircraft or ships, a battery sufficient to match the energy of fuel would be excessively heavy and making the vehicle uneconomical. Additionally, recharging large batteries for, say, an airplane would require enormous power throughput in a short time, which is not feasible with current grid infrastructure.
Infrastructure constraints are another limitation to full electrification: delivering enough power to fast-charge thousands of heavy trucks or to electrify industrial heat at scale could strain electrical grids without significant upgrades. For instance, industrial sites may need completely new high-voltage lines and substations to supply electric furnaces, and airports would need transformative changes to recharge electric aircraft between flights. These practical constraints mean that certain sectors will likely continue to rely on energy-dense fuels and chemical energy carriers rather than electrons.
Because of these challenges, energy scholars emphasize a “fit-for-purpose” approach: use direct electrification wherever possible, and reserve alternative fuels and carriers for the applications where electrification fails to deliver [7]. In other words, to achieve deep decarbonization, society must electrify what can be electrified – e.g. passenger transport, many building uses, and some industrial processes – but simultaneously develop solutions for the hard-to-abate remainder. These complementary solutions include green hydrogen, as discussed, which can be used either directly as a fuel or feedstock or converted into ammonia or into synthetic hydrocarbons.
2.4 CONCLUSION: THE NEED FOR COMPLEMENTARY SOLUTIONS
In conclusion, the global energy system urgently needs to reduce emissions while meeting rising energy demands. While electrification is advancing rapidly, particularly in power generation, transportation, heating, and some industrial sectors, it cannot address every aspect of the energy-climate challenge. Hard-to-abate sectors, including heavy industry, long-distance transport, and certain building applications, face practical constraints that limit direct electrification with existing technologies. Consequently, complementary solutions are essential.
Foremost among these solutions is green hydrogen, produced using RE. Hydrogen can substitute fossil fuels directly in industrial processes, fuel-cell vehicles, or serve as a feedstock for synthetic aviation fuels. Other RECs such as ammonia—simpler to store and transport—and sustainable biofuels will also play vital, albeit niche, roles in sectors like shipping and aviation. Developing robust supply chains for these fuels is critical to complement renewable electricity expansion.
An integrated approach combining energy efficiency, electrification, alternative fuels, CCS, and advanced materials is crucial. Each sector requires targeted strategies, from modernizing grids and enhancing energy storage to scaling hydrogen projects and redesigning urban infrastructure. Ultimately, diversifying our decarbonization toolkit by leveraging RE strengths and supplementing them with hydrogen and other sustainable carriers is essential for creating a resilient, low-carbon global energy system.
2.5 REFERENCES
1. Intergovernmental Panel on Climate Change (IPCC). (2022). Climate change 2022: Mitigation of climate change. Contribution of Working Group III to the Sixth Assessment Report of the IPCC (Chap. 2 and SPM). Cambridge University Press.
2. United States Environmental Protection Agency (EPA). (2023). Global greenhouse gas emissions data. Retrieved from [https://www.epa.gov/ghgemissions/global-greenhouse-gas-overview]
3. Our World in Data. (2023). Global primary energy consumption by source, 1800–2023 [Image]. Retrieved from [https://ourworldindata.org/energy-mix]
4. International Energy Agency (IEA). (2024). CO₂ emissions in 2023 – Executive summary. Retrieved from [https://www.iea.org/reports/co2-emissions-in-2023]
5. Wishart, J. (n.d.). Fuel cells vs batteries. Intertek Transportation Technologies. Retrieved from [https://studylib.net/doc/18064609/fuel-cells-vs-batteries]
6. Barzkar, A., & Ghassemi, M. (2020). Electric power systems in more and all electric aircraft: A review. IEEE Access, 8, 169314–169332. [https://doi.org/10.1109/ACCESS.2020.3024168]
7. International Renewable Energy Agency (IRENA). (2018). Renewable energy statistics 2018. Retrieved from [https://www.irena.org/publications/2018/Jul/Renewable-Energy-Statistics-2018]
8. European Commission. (2023, June 20). The HYBRIT story: Unlocking the secret of green steel production. EU Climate Action News. Retrieved from [https://climate.ec.europa.eu]
9. Weiss, T., & Blank, T. (2022). Hydrogen reality check: We need hydrogen—but not for everything. RMI. Retrieved from [https://rmi.org/we-need-hydrogen-but-not-for-everything]
Chapter 3
The Case for Renewable Energy Carriers
As indicated in the previous chapter, decarbonizing “hard-to-electrify” sectors is essential for achieving climate targets. While direct electrification and energy efficiency can eliminate a large share of emissions, certain applications cannot easily switch to electricity due to technical and economic constraints [1]. In these domains, renewable energy carriers (RECs) like hydrogen, ammonia, methanol, and other synthetic fuels play a pivotal role in transferring clean energy from renewable electricity into forms usable by these challenging sectors [1];[2].
Hydrogen in particular is emerging as a central vector: it can be produced from water using renewable power and then either used directly as a carbon-free fuel or converted into hydrogen-based fuels for broader use. This chapter examines five key roles of RECs in bridging the gap between abundant renewable electricity and hard-to-abate end-uses: (1) energy storage, (2) long-distance transport of energy, (3) drop-in or retrofit compatibility with existing infrastructure, (4) high-temperature and niche industrial applications, and (5) decarbonization of chemical feedstocks. Throughout, we highlight hydrogen’s primary importance and the complementary contributions of carriers in a low-carbon energy system.
Hydrogen’s flexibility enables it to connect the power sector with these hard-to-electrify sectors in ways that electrons alone cannot. It can be produced in regions rich in solar and wind, stored when supply exceeds demand, transported as a gas or liquid fuel, and ultimately used to generate heat, electricity or motion in end-use applications. In doing so, renewable hydrogen and its derivatives provide pathways to cut emissions in sectors that still rely on fossil fuels [3]. Importantly, hydrogen is not only an energy carrier itself but the feedstock for producing other carbon-neutral fuels: ammonia (NH₃) is made from hydrogen and nitrogen, and synthetic hydrocarbons are made from hydrogen and CO₂. This interdependence means scaling up hydrogen supply will also enable the deployment of these other fuels.
Figure 3 Illustration of hydrogen as a versatile carrier linking renewable electricity production to multiple end-use sectors. Green hydrogen production via electrolysis (left) can be used directly as H2 or transformed into derivative fuels for easier transport (middle). These carriers are then distributed via pipelines, ships, or storage facilities and utilized across diverse end uses [1].
The sections below detail how these RECs function in the energy transition, each focusing on a particular role, followed by a concluding outlook on their collective impact.
3.1 ENERGY STORAGE
One critical role for hydrogen and related carriers is as a medium for energy storage, especially to buffer the variability of renewable electricity. Renewable sources like solar and wind are intermittent and often produce excess power when demand is low. Converting surplus electricity into chemical form allows that energy to be stored for later use on timescales of days, weeks, or even seasons. Hydrogen is one of the leading options for storing renewable energy and is projected to be among the lowest-cost solutions for long-duration storage as renewable penetration grows. For instance, stored hydrogen can be used to generate electricity during prolonged cloudy or windless periods, effectively acting as a seasonal storage buffer that balances energy supply and demand across months. The IEA notes that hydrogen provides a means to bank renewable energy and “looks promising to be a lowest-cost option for storing electricity over days, weeks or even months” [2].
Figure 4 Energy density and specific energy of various fuels and energy storage systems [1]
Hydrogen-based storage can scale to very large capacities. In practical terms, this might involve producing hydrogen in summer when solar generation is high, storing it in geological formations (like salt caverns), and then using it in winter when renewable output is lower. Such seasonal storage capability far exceeds the discharge duration of lithium batteries or other conventional storage technologies [4]. The IPCC’s Sixth Assessment Report underscores hydrogen’s value for grid balancing: in the long term, “hydrogen can provide electricity storage to support high penetration of intermittent renewables” [5]. In addition, stored hydrogen enhances grid flexibility by serving as “clean firm” capacity – it can be reconverted to electricity via fuel cells or turbines when needed, providing dispatchable power without carbon emissions.
3.2 ENABLING LONG-DISTANCE TRANSPORT OF RENEWABLE ENERGY
RECs also enable long-distance transport of energy, allowing regions rich in renewable resources to export clean energy to demand centres far away. Shipping electricity over thousands of kilometres is inefficient or impossible with current grids, but shipping hydrogen or hydrogen-derived fuels offers a viable alternative. The IEA observes that hydrogen and its compounds can “transport energy from renewables over long distances –from regions with abundant solar and wind resources, such as Australia or Latin America, to energy-hungry cities thousands of kilometres away” [2]. In this way, green hydrogen serves as a geographical bridge, capturing renewable power in one location and releasing it as usable energy in another. For example, a country with vast deserts and high solar irradiance could produce hydrogen or ammonia using solar electricity and then export these fuels via ship to countries with less renewable potential [6]. This concept mirrors the role of liquefied natural gas (LNG) in today’s energy system, but with a carbon-free commodity.
There are several pathways for transporting hydrogen energy over long distances: as compressed or liquefied hydrogen gas, as ammonia, as methanol or other LOHCs, or even as synthetic methane. Each carrier has advantages. Gaseous hydrogen can be moved through pipelines. For transoceanic distances, liquefied hydrogen (LH₂) shipping is technically possible but faces challenges due to hydrogen’s extremely low boiling point and low volumetric density. Instead, chemical carriers like ammonia are increasingly seen as more practical for intercontinental transport. Ammonia is already traded globally as a commodity, with established infrastructure for liquefaction, storage, and shipping [6]. Similarly, methanol is a liquid at ambient conditions; it offers an energy-dense liquid fuel that can be shipped in standard chemical tankers and used at the destination for power or as transportation fuel.
3.3 DROP-IN FUEL AND INFRASTRUCTURE COMPATIBILITY
Another important role of RECs is serving as “drop-in” fuels or retrofit solutions that are compatible with existing infrastructure. One of the major barriers to transitioning away from fossil fuels is the capital already invested in fuel distribution networks, engines, and industrial equipment designed for coal, oil, or natural gas. RECs offer a way to utilize these legacy systems with minimal modifications, accelerating decarbonization without waiting for complete infrastructure turnover. For example, hydrogen can be blended into existing natural gas pipelines and used in conventional gas appliances, effectively lowering the carbon intensity of building heating and cooking without changing out millions of stoves or furnaces [2]. Even relatively small hydrogen blending (e.g. 5–20% by volume) in natural gas networks can cut CO₂ emissions from end-use combustion proportionally, and many gas utilities are piloting blends in municipal grids.
In the long run, entire pipeline systems may be repurposed for 100% hydrogen, but blending is a near-term drop-in strategy to start integrating hydrogen into the built environment
In the power sector, ammonia and hydrogen can be used in existing thermal power plants to reduce emissions. Ammonia contains no carbon and can burn in boilers or turbines to produce power with zero CO₂. For instance, ammonia can be co-fired in coal-fired power plants as a drop-in fuel replacement for coal, immediately cutting CO₂ output from those plants [2]. Gas-fired power plants can likewise be retrofitted: modern gas turbines are increasingly capable of firing hydrogen-rich fuel. Several turbine manufacturers have announced that their latest models can tolerate 30–50% hydrogen mixed with natural gas today, with a roadmap to 100% hydrogen firing by 2030 [5]. Indeed, commercial turbines exist that can already operate on up to 20–50% hydrogen in natural gas, and companies are developing turbines for pure hydrogen combustion. This means many existing power generators can be incrementally decarbonized by injecting hydrogen into their fuel supply—a drop-in approach that avoids stranding assets.
In transportation, synthetic fuels produced from green hydrogen and captured CO₂ act as direct drop-in replacements for gasoline, diesel, and jet fuel. These e-fuels—such as e-diesel, e-kerosene (jet), and e-methanol—have nearly identical properties to their fossil counterparts and can be used in today’s engines, vehicles, and aircraft with little or no modification. For example, sustainable aviation fuel (SAF) made from captured CO₂ and hydrogen can be blended into jet fuel and used in existing aircraft. The key advantage of such drop-in fuels is that they “minimize operational changes while enabling substantial emissions reductions” [7].
The shipping industry is already exploring green ammonia & green methanol as drop-in fuels for maritime vessels. Notably, multiple commercial shipping companies have ordered dual-fuel ships capable of running on methanol or ammonia, indicating the viability of these fuels in retrofitting or replacing oil-fuelled engines. Likewise, heavy trucking can potentially use synthetic diesel or hydrogen fuel cell retrofits. By providing compatibility with current engines and infrastructure, RECs accelerate the adoption of clean energy in transport and industry. These drop-in solutions buy time and cut emissions in the near term, even as fully optimized next-generation systems continue to develop.
3.4 HIGH-TEMPERATURE AND NICHE INDUSTRIAL APPLICATIONS
Decarbonizing heavy industries poses a formidable challenge because many industrial processes require extremely HT or involve chemical reactions that today rely on fossil fuels. REC, especially hydrogen, offer a solution for these HT and niche industrial applications that are hard to electrify. One prominent example is steel production. The IPCC reports that existing gas-based DRI processes (which use syngas of H₂/CO) can already replace up to 30% of the natural gas with hydrogen without major modifications, and future process designs will allow using 100% hydrogen [5].
Similarly, the cement industry requires kiln temperatures above 1400°C to form clinker. While direct electrification of such kilns is challenging, hydrogen or ammonia combustion could provide the necessary heat with zero carbon emissions. Some cement plants are testing hydrogen as part of the fuel mix to reduce their reliance on coal. The chemical industry also has niche processes (like HT reactors for glass, ceramics, or high-pressure steam generation) where hydrogen can substitute for natural gas. Hydrogen combustion produces a high flame temperature and a clean heat source suitable for these applications, with water as the only combustion product.
3,5 DECARBONIZING CHEMICAL FEEDSTOCKS
The fifth role of RECs lies in decarbonizing chemical feedstocks and industrial inputs. A significant portion of global hydrogen production today (about 75 Mtpa) is not used as fuel at all, but as a feedstock for making other chemicals – primarily ammonia and in oil refining and methanol production [2]. These existing industrial uses of hydrogen are currently served almost entirely by “grey” hydrogen produced from natural gas or coal, a carbon-intensive practice. In fact, the CO₂ emissions from today’s hydrogen production are on the order of 800–900 million tonnes per year, comparable to the combined emissions of Indonesia and the United Kingdom. Decarbonizing these chemical processes by switching to green or blue hydrogen is thus a major opportunity for emissions reduction [2]. Renewable hydrogen can directly replace fossil-derived hydrogen in ammonia synthesis, methanol synthesis, and refinery hydro-processing, thereby virtually eliminating CO₂ emissions from the production of these chemicals. The IPCC highlights this feedstock switching as a key mitigation route [5].
Green methanol is not only a useful fuel but also a feedstock for plastics and other chemicals; green methanol thus offers a route to embed renewable energy into the chemical supply chain for materials. Additionally, the oil refining sector, which uses hydrogen to desulfurize fuels and upgrade crude oil, can eliminate a source of emissions by purchasing or producing green hydrogen instead of generating hydrogen from natural gas. While demand for refinery hydrogen may decline in a deep decarbonization scenario, in the interim it remains a large hydrogen consumer that must be cleaned up. Replacing all fossil-based hydrogen with renewable hydrogen in these industries would directly avoid hundreds of millions of tonnes of CO₂ per year [2].
3.6 CONCLUSION AND OUTLOOK
Renewable-energy carriers (RECs) built around hydrogen will anchor tomorrow’s lowcarbon system by linking surplus renewables to hard-to-abate sectors. Hydrogen stores and moves clean energy, back-fills existing pipelines and tanks, and enables fossil-free high-temperature processes; its derivatives—ammonia, methanol, e-fuels—mainly serve as vectors that deliver hydrogen’s energy and chemistry where pure H₂ is impractical. Global studies (e.g., IRENA) suggest hydrogen could supply ~12 % of final energy in a 1.5 °C world.
Derivatives broaden that reach: green ammonia, for example, doubles as a carbon-free fuel for ships and turbines while carrying hydrogen safely across oceans. Rather than rivals, these molecules extend the hydrogen supply chain, each chosen for its logistical or technical edge.
Advancing this portfolio demands cheaper electrolysis, large-scale ammonia and syn-fuel production, higher conversion efficiencies, and rigorous safety and sustainability standards. With national strategies, industrial hubs, and shipping-and-aviation pilots accelerating, the next decade will shift RECs from demonstrations to mainstream—provided research, investment, and inclusive policy keep pace.
The rest of this book explores how each carrier tackles specific decarbonisation hurdles, charting a path toward a globally equitable, net-zero energy future.
3.7 REFERENCES
1. International Renewable Energy Agency. (n.d.). Hydrogen. Retrieved from [https://www.irena.org/ Energy-Transition/Technology/Hydrogen]
2. International Energy Agency. (2019). The future of hydrogen: Seizing today's opportunities. Retrieved from [https://www.iea.org/reports/the-future-of-hydrogen]
3. International Energy Agency. (2019). The future of hydrogen: Various uses for hydrogen (Industry, Transport, Buildings, Power). Retrieved from [https://www.iea.org/reports/the-future-of-hydrogen]
4. Oğuz, S. (2024, April 9). All commercially available long duration energy storage technologies, in one chart. Decarbonization Channel. Retrieved from [https://decarbonization.visualcapitalist.com/ all-commercially-available-long-duration-energy-storage-technologies-in-one-chart/]
5. Han, H. (2022, November 11). What the latest IPCC report says about zero-carbon fuels: Summary of IPCC AR6 WG III findings. Clean Air Task Force. Retrieved from [https://www.catf.us/2022/11/ what-the-latest-ipcc-report-says-about-zero-carbon-fuels/]
6. Aluko, L. (2025, March 16). Chemical tankers: The future of hydrogen transport. illuminem. Retrieved from [https://illuminem.com/illuminemvoices/chemical-tankers-the-future-of-hydrogentransport]
7. Albaladejo, M., Matus Elgueta, A., & Amador, G. (2024, December). Sustainable fuels: A key player in decarbonizing hard-to-abate sectors. Industrial Analytics Platform. Retrieved from [https://iap. unido.org/articles/sustainable-fuels-key-player-decarbonizing-hard-abate-sectors]
8. Topsoe. (n.d.). G2L™ eFuels technology. Retrieved from [https://www.topsoe.com/our-resources/ knowledge/our-products/process-licensing/g2ltm-efuels-technology]
Part II
Chapter 4
Hydrogen as a Central Renewable Energy Carrier
Hydrogen has emerged as a pivotal energy carrier in the transition to a low-carbon future, especially within Europe’s policy frameworks. As an energy carrier, hydrogen can store and deliver usable energy derived from various primary sources. When used, it emits only water vapor, making it an attractive option for decarbonizing sectors that are hard to electrify.
The European Union (EU) and countries like the Netherlands view hydrogen as essential to achieving climate goals; for example, the EU’s “Fit for 55” package introduced binding targets for renewable hydrogen uptake in industry and transport [1];[2], and the Netherlands’ Climate Agreement (2019) similarly elevated hydrogen in its national strategy [3].
In 2022, hydrogen accounted for less than 2% of Europe’s energy consumption (mostly in refining and fertilizer production), and 96% of that hydrogen was produced from natural gas [2]. Both the EU and the Netherlands are striving to change this by accelerating renewable and low-carbon hydrogen. The EU’s REPowerEU plan set a goal of producing 10 million tons of renewable hydrogen domestically and importing another 10 million tons by 2030 [2], and the Netherlands’ National Hydrogen Strategy (2020) set targets of 500 MW electrolyser capacity by 2025 and 3–4 GW by 2030 [4]. This policy momentum, alongside initiatives like Hydrogen Valleys in Groningen and Rotterdam, underscores hydrogen’s envisioned role as a central energy carrier in Europe’s sustainable energy future.
4.1 PROPERTIES AND ADVANTAGES OF HYDROGEN
Hydrogen’s unique properties underlie both its strengths and challenges as an carrier. In terms of energy content, hydrogen has the highest gravimetric energy density of any common fuel – about 120 MJ per kilogram (LHV), nearly three times the energy per mass of gasoline [5]. This means a small mass of H₂ contains a large amount of energy, a crucial advantage for applications like heavy transport. However, hydrogen’s volumetric energy density is extremely low under ambient conditions because it is a light gas (0.0899 kg/m³ at NTP). Even in liquid form at –253 °C, hydrogen’s energy per litter is only around 8 MJ/L, compared to ~32 MJ/L for gasoline. Compressed gaseous H₂ at 700 bar achieves ~5.6 MJ/L [6]. Figure 4 illustrates how hydrogen occupies the extreme of high energy per mass but low energy per volume among fuels. This disparity means hydrogen storage and transport require high-pressure tanks or cryogenic liquids to pack sufficient energy into a given volume [5].
Despite storage challenges, hydrogen is storable over long periods and can be transported [7];[8]. Unlike electricity, which is difficult to store at scale long-term, hydrogen can stockpile large energy quantities to provide seasonal balancing for grids rich in intermittent renewables [8]. Hydrogen’s combustion emits only water vapor, with zero CO₂ or pollutant emissions at the point of use [9]. This makes it very attractive for improving air quality and decarbonizing end-uses.
Hydrogen can also be chemically converted into synthetic fuels, such as methanol or Fischer-Tropsch liquids, or carriers like ammonia, further enhancing its versatility.
Together, hydrogen’s high gravimetric energy density, carbon-free operation, and adaptability across multiple sectors position it as an essential fuel for applications that cannot easily be electrified directly [7].
4.2 HYDROGEN PRODUCTION PATHWAYS: GREY, BLUE, AND GREEN
Hydrogen does not exist freely in large quantities on Earth and must be produced from hydrogen-containing compounds. The production pathway determines hydrogen’s environmental footprint. Grey hydrogen refers to hydrogen produced from fossil fuels (typically natural gas via Steam Methane Reforming - SMR, or coal gasification) without carbon capture. This is currently the dominant form of production globally and in Europe [2]. Grey hydrogen production is carbon-intensive, emitting roughly 9-12 kg CO₂ per kilogram of H₂ produced in SMR processes. For decades, industries (like oil refining and ammonia fertilizer production) have used grey hydrogen as a feedstock, resulting in significant CO₂ emissions. In the Netherlands, for example, hydrogen use is high (the second largest in Europe) due to its large refining and chemical sector, and historically this hydrogen has been grey [10]. The challenge now is to transition this production to LC methods.
Blue hydrogen is produced from fossil fuels but with CCS to trap the CO₂ byproduct. In blue hydrogen pathways, the CO₂ from processes like SMR is captured (typically 60–95% of it) and sequestered in geological formations or utilized, instead of being released to the atmosphere [9]. This significantly reduces net CO₂ emissions compared to grey hydrogen, though some residual emissions remain (hence blue hydrogen is often termed “lowcarbon” rather than fully carbon-neutral) [9]. Blue hydrogen is seen as a bridging solution: it can provide large volumes of hydrogen with lower emissions in the near term, leveraging existing natural gas resources and infrastructure, while green hydrogen capacity scales up. In the EU, blue hydrogen projects are being pursued especially in industrial hubs.
For instance, in Rotterdam, the H-Vision project will produce hydrogen from natural gas and refinery off-gases with CCS. The captured CO₂ will be stored in depleted gas fields under the North Sea (via the Porthos project) [11]. The blue hydrogen from H-Vision –with an initial plant of ~750 MW by 2026 – is intended to supply local refineries and power plants, cutting emissions by an estimated 2.2 million tonnes CO₂ in 2026 and 4.3 million tonnes by 2031 [11]. This represents roughly a 16% CO₂ reduction in Rotterdam’s industrial sector. European policy has begun to acknowledge blue hydrogen: the EU’s gas market regulatory framework (2024) uses terms like “low-carbon hydrogen” alongside renewable hydrogen [2], setting lifecycle greenhouse gas limits so that blue hydrogen can qualify under certain sustainable criteria. Ultimately, blue hydrogen’s role may be time-limited in a net-zero 2050 context, but it is anticipated to kick-start the hydrogen economy by supplying large industrial demand this decade with lower emissions than current practice.
Green hydrogen is produced by electrolyzing water using renewable electricity (or via other renewable routes such as reforming biogas). It is often called “renewable hydrogen” or “clean hydrogen” because its production involves no direct CO₂ emissions, and if the electricity source is solar, wind, hydro, etc., the overall process can be near-zero carbon. Electrolysis splits water (H₂O) into hydrogen and oxygen; when powered by renewables, this process yields hydrogen with a minimal carbon footprint. Green hydrogen is thus the ultimate goal for sustainable hydrogen supply [9]. Currently, green hydrogen accounts for only a small fraction of global hydrogen production (~0.1%), primarily due to the high cost of electrolysers and the need for abundant cheap renewable power. But costs are expected to fall as renewable electricity becomes cheaper and electrolyser manufacturing scales up. Europe has set ambitious targets to expand green hydrogen: the EU Hydrogen Strategy (2020) called for installing at least 40 GW of electrolyser capacity in the EU by 2030 and producing 10 million tonnes of renewable H₂ [2].
The Fit for 55 package reinforced this with concrete targets: EU member states must ensure 50% of hydrogen consumed by industry in 2030 is from renewable sources, and a minimum share of 2.6% of transport energy comes from renewable fuels of non-biological origin by 2030 [10]. The Netherlands likewise plans for green hydrogen scale-up – aiming for 4 GW of electrolysers by 2030 [4] – linked to its offshore wind expansion.
Major green hydrogen projects are underway: for example, Shell’s Holland Hydrogen I project in Rotterdam will be one of Europe’s largest green hydrogen plants (200 MW electrolyser) when it comes online mid-decade, supplying hydrogen to the port’s industries and heavy transport. In the northern Netherlands, the HEAVENN Hydrogen Valley is deploying several linked green hydrogen projects to demonstrate a full value chain from renewable production to end-use [12]. Green hydrogen is central to long-term EU climate plans because it offers a fully carbon-free energy carrier if produced with additional renewable capacity.
Figure 6 Illustration of “grey”, “blue”, “turquoise”, and “green” hydrogen production pathways. Only green hydrogen is produced in a climate-neutral way, hence current EU strategies emphasize scaling up green H₂ [9].
In addition to these main categories, other colour codes exist: “Turquoise” hydrogen (methane pyrolysis yielding solid carbon [13], “Brown/Black” hydrogen (from coal gasification without CCS, very high CO₂ emissions), “Purple/Pink” hydrogen (electrolysis powered by nuclear energy), etc. While these have niche relevance, the primary focus in Europe is to replace grey hydrogen with green and, as a transitional step, blue hydrogen. The Dutch Climate Agreement explicitly favours green hydrogen for the long run but acknowledges blue hydrogen’s interim role to achieve 2030 CO₂ targets in industry [13]. The choice of pathway also has infrastructure implications: green hydrogen production can be decentralized or centralized, whereas blue hydrogen tends to be centralized at industrial sites with available CCS.
4.3 SECTORAL APPLICATIONS OF HYDROGEN
Hydrogen’s value as an energy carrier comes to fruition when applied in sectors that are otherwise difficult to decarbonize. Key sectors where hydrogen is poised to play a central role include industry, transportation, and the energy sector. European and national strategies increasingly emphasize these applications.
Industry: Industry is currently the largest consumer of hydrogen, using it as a feedstock for refining crude oil (hydrocracking) and ammonia production (for fertilizers), among other uses. Today this hydrogen is largely grey, but the industrial sector is where low-carbon hydrogen can have an immediate impact by displacing hydrogen produced from fossil fuels. For example, refining and fertilizer plants can switch to blue or green hydrogen, directly reducing CO₂ emissions associated with hydrogen production. Beyond incumbent uses, hydrogen is critical for decarbonizing industrial processes that currently rely on coal or natural gas. renewable capacity.
A prime example is steelmaking: traditional blast furnace-basic oxygen furnace routes use coal and emit large amounts of CO₂. Europe is now moving towards hydrogen-based steel production via Direct Reduced Iron (DRI) processes. In the Netherlands, Tata Steel IJmuiden has announced plans to replace its blast furnaces with electric furnaces using DRI that initially operates on natural gas and later switches to hydrogen as soon as sufficient green hydrogen is available [14].
Similarly, other industrial high-temperature processes (cement kilns, glass furnaces, chemicals production) are piloting hydrogen as a replacement fuel for natural gas or coal. Hydrogen burns at a high flame temperature and can thus provide the necessary heat. TNO and industry partners have demonstrated that many industrial gas burners can be retrofitted to burn hydrogen with minimal modification [13]. Hydrogen’s advantage in industry is especially clear where electrification is infeasible: for producing high-grade heat (>1000°C) or as a chemical reactant. The EU’s Fit for 55 policies directly target industrial hydrogen use: by 2030, 50% of hydrogen used in industry must be from renewable sources, which is driving industrial users to sign contracts with green hydrogen suppliers or invest in on-site electrolysis. Industrial clusters in Europe are becoming focal points for hydrogen hubs – for instance, the Rotterdam port/industry complex aims to both use and trade hydrogen. The H-Vision1 blue hydrogen will supply refineries and power plants, and a Hydrogen Pipeline (“Hydrogen Backbone”) is being developed to distribute hydrogen across the port and to connect to national and international networks. In the northern Netherlands, the HEAVENN project integrates multiple industries (chemicals in Delfzijl, materials in Emmen, etc.) with hydrogen supply [12]. European industry also benefits from hydrogen in producing new products like green ammonia or e-fuels for export. Overall, industry stands to both use hydrogen as a decarbonized feedstock and as a fuel for processes that cannot be easily electrified, making it central to hydrogen demand growth.
Transport: The transport sector, particularly segments that are hard to electrify with batteries, is another major application area for hydrogen. Fuel cell electric vehicles (FCEVs) running on hydrogen can decarbonize heavy-duty road transport, buses, certain rail lines, and potentially shipping and aviation. Within Europe, hydrogen mobility is being actively promoted through both infrastructure deployment and vehicle adoption targets. The EU’s Alternative Fuels Infrastructure Regulation (2023) has mandated that by 2030, hydrogen refuelling stations must be available at least every 200 km along the core Trans-European Transport Network (TEN-T) corridors and in all urban nodes (major cities) [15]. This will create a baseline network enabling hydrogen-powered trucks and coaches to travel across Europe. Several countries, including the Netherlands, Germany, and France, have begun installing these stations. For instance, the Netherlands is part of the “Hydrogen Corridor” project to deploy H₂ fuelling along routes from the ports of Rotterdam and Amsterdam towards Germany. Already, there are hydrogen fuelling stations in Amsterdam, Rotterdam, The Hague, Groningen and other cities, serving a growing fleet of fuel cell buses and cars. The northern Dutch provinces of Groningen and Drenthe operate one of Europe’s largest hydrogen fuel cell bus fleets (30 buses), supported by Shell’s hydrogen refuelling depot, while European manufacturers like Daimler, Volvo, and Iveco develop hydrogen trucks anticipating future market expansion. The maritime sector is exploring hydrogen and ammonia as bunker fuels for ships – the PoR, Europe’s biggest port, is investing in infrastructure to accommodate imports of green hydrogen and ammonia that could also fuel ships in the future.
Demonstration projects, like fuel cell inland shipping vessels and hydrogen-powered port equipment, are underway. On the aviation side, European companies are developing hydrogen fuel cell or hydrogen-combustion aircraft for regional travel in the 2030s, although this is still at R&D stage.
Figure 7 A driver refuels a hydrogen fuel-cell car at a Shell hydrogen filling station in Europe. FCEVs like this emit only water and can refuel in 3–5 minutes, offering long range and quick turnaround for drivers. The EU is mandating a network of hydrogen refuelling stations along major highways to support wider adoption of FCEVs in heavy-duty transport [16]
Energy Systems: Hydrogen can also be utilized in the power sector and for heating, serving as a linkage between the gas grid and the electricity grid. In power generation, hydrogen can be used in fuel cells or combusted in turbines to generate electricity with zero carbon emissions at point of use. This is especially valuable for providing dispatchable power to balance renewable variability. Several European utilities are converting or designing power plants to run on hydrogen. For example, in the Netherlands, one of the units of the Magnum gas-fired power plant (Groningen province) was planned to be converted to burn hydrogen supplied by Equinor (via blue hydrogen from Norway) in a project known as “H2M”2. In Italy and Germany, turbine manufacturers like Siemens and Ansaldo are developing hydrogenready gas turbines capable of co-firing hydrogen today and switching to 100% hydrogen in the future. By 2030, Europe expects dozens of power plants to be hydrogen-enabled, providing peak power and grid stability as coal is phased out.
Beyond centralized power plants, hydrogen fuel cells can provide decentralized power Fuel cell systems are already used for backup power in telecom and data centres, and pilot projects in Europe are deploying large fuel cells (often in combined heat and power mode) for hospitals and commercial buildings, running on hydrogen or methane-hydrogen blends. For energy storage, hydrogen can be produced when there is surplus renewable electricity and stored then converted back to electricity via fuel cells or turbines when needed. This “power-to-hydrogen-to-power” cycle is less efficient than batteries in the short term, but it is more practical for inter-seasonal storage and very large capacities. Countries like Germany, the UK, and the Netherlands with substantial wind generation are interested in this approach to absorb excess generation and provide winter supply.
The Netherlands, with its extensive gas infrastructure and salt caverns, is pioneering large-scale hydrogen storage: the HyStock project by Gasunie is testing the first salt cavern storage of hydrogen in the Netherlands, aiming for a 200 GWh hydrogen storage capacity in a single cavern by 2026 after pilot checks confirm safety [17].
Hydrogen is also being considered for decarbonizing building heating, though this is more contested. Blending hydrogen into the existing natural gas grid is technically feasible up to a certain percentage. Projects across Europe are testing blending levels of 5-20% hydrogen in local gas distribution networks. In the Netherlands, the HyDelta program specifically addresses the safety and compatibility of injecting hydrogen into the gas infrastructure [18]. Early results indicate that low blend fractions cause minimal issues for end-users while reducing the carbon content of the gas. Some Dutch pilots (e.g., in Rozenburg and Stad aan ’t Haringvliet3) are even trailing 100% hydrogen in dedicated new residential neighbourhoods with hydrogen boilers. However, whether hydrogen will be used widely for heating depends on economics and alternative solutions. EU policy remains cautious on hydrogen for general heating, focusing it more on high-temperature industrial heat and backup power.
Crucially, these sectoral uses are interconnected in emerging hydrogen hubs. The concept of “Hydrogen Valleys” is to create a local ecosystem where hydrogen is produced and then distributed to multiple uses: industrial feedstock, fuel for buses/trucks, injection into the gas grid, and power generation. The Northern Netherlands Hydrogen Valley (HEAVENN) exemplifies this integration: with EU support, it links a wind-powered electrolyser, salt cavern storage, pipelines, vehicle refuelling stations, and multiple end-users (bus fleets, data centres, industrial sites) in a coordinated demo [12]. Likewise, Rotterdam’s hydrogen hub vision involves importing green hydrogen through its port, using some for local industry (refineries, chemicals), some for heavy transport fuel, and transporting the rest via pipelines to demand centres in the Netherlands and Germany [18].
4.4 KEY CHALLENGES AND INFRASTRUCTURE NEEDS
While hydrogen offers significant opportunities, realizing a hydrogen-centred energy system involves overcoming challenges and investing in infrastructure. Key hurdles include the high cost of low-carbon hydrogen, efficiency losses, infrastructure build-out, and ensuring safety and public acceptance. European and Dutch policies explicitly target these issues to achieve ambitious 2030 and 2050 goals.
Cost and Scale-up: Green hydrogen today is considerably more expensive than fossilbased hydrogen, primarily due to high electrolyser costs and renewable electricity prices. Although renewable electricity costs have declined, electrolyser capital costs remain high. Blue hydrogen also incurs additional costs for carbon capture and storage (CCS). To address this, the EU and Netherlands employ subsidies and carbon pricing, notably through the EU Emissions Trading System (ETS), which increases the competitiveness of low-carbon hydrogen. The Netherlands established the "GroenvermogenNL" subsidy program to support green hydrogen projects and infrastructure, complementing the EU’s Innovation Fund and IPCEI Hydrogen initiatives. Analysts estimate the Netherlands needs at least 5 GW of renewable power dedicated to green hydrogen to meet its 50% green hydrogen
industry target by 2030. Europe aims to foster a domestic electrolyser industry with a target manufacturing capacity of 60 GW/year by 2025. International trade, such as imports via Rotterdam’s partnerships with countries like Morocco and Oman, is also essential for reducing hydrogen costs [2].
Infrastructure Development: Scaling hydrogen use requires extensive infrastructure, including production facilities, pipelines, storage, and distribution systems. Critical to this is a hydrogen transmission network connecting producers with consumers. Existing natural gas pipelines offer a starting point. In the Netherlands, Gasunie’s HyWay 27 study concluded that repurposing gas pipelines is feasible and cost-effective [4]. At the European level, the European Hydrogen Backbone (EHB) initiative envisions a 39,700 km hydrogen pipeline network by 2040, largely repurposed from natural gas infrastructure [20]. Early projects, such as the Netherlands-Germany hydrogen network connection by 2025 and Gasunie’s pipeline conversion from Grijpskerk to Rotterdam, are underway4
Large-scale hydrogen storage in geological formations, particularly salt caverns, is crucial for seasonal supply security. The Netherlands’ HyStock project in Zuidwending aims for a cavern storing ~6,000 tons H₂ by 2026 [17]. Additionally, local infrastructure such as distribution networks and refuelling stations require adaptation, driven by research programs like the Dutch HyDelta, which addresses gas network modifications for hydrogen compatibility, including improved sensors and leak detection. Safety standards are simultaneously being updated by European organizations such as ISO and CEN [18].
Electricity infrastructure is another critical component. Large-scale electrolysers (100+MW) necessitate grid integration coordination. Grid operators like TenneT collaborate closely with projects such as the 200 MW Holland Hydrogen I in Rotterdam to ensure efficient grid connections [21]. The Dutch Climate Agreement proposes co-locating offshore wind farms with hydrogen production to ease grid congestion, including offshore hydrogen production platforms like the North Sea’s PosHYdon project5
Efficiency and Competing Uses: Hydrogen use involves efficiency losses, particularly when converting electricity to hydrogen and back, with round-trip efficiencies typically around 30-40%. Consequently, Europe’s policy approach is to prioritize hydrogen for applications where direct electrification is impractical. The Dutch Hydrogen Strategy emphasizes limiting green hydrogen use where direct electrification, such as heat pumps for residential heating, is feasible6. Strategic prioritization ensures optimal allocation of limited green hydrogen resources and synchronizes supply with demand.
Regulatory and Market Framework: A functional hydrogen economy requires clear market rules and regulations. The EU’s Hydrogen and Decarbonised Gas Market Package (effective 2024) sets guidelines for hydrogen network access, tariffs, and unbundling, and establishes a guarantee-of-origin certificate system for renewable and low-carbon hydrogen7. The Netherlands aligns its national certification system accordingly. Safety regulations, building codes, and emergency response protocols are updated to reflect hydrogen’s unique characteristics. Public acceptance depends heavily on clear safety assurances, successful demonstrations, and community engagement.
International coordination is essential due to cross-border hydrogen trade and infrastructure. Standardizing hydrogen quality, purity, and pressure ensures seamless interoperability. Initiatives like the European Clean Hydrogen Alliance8 foster stakeholder collaboration, while regional coordination (Benelux and Germany) addresses interconnected pipeline and offshore hydrogen planning. A good example is the North Sea Wind Power Hub
Despite these challenges, progress has accelerated significantly in recent years, driven by extensive public funding and rapid project proliferation. The Netherlands initiated the HyXchange9 platform in Rotterdam to model future hydrogen trading and regulatory needs. Europe’s initial demonstration projects, such as salt cavern storage and hydrogen combustion in gas turbines, inform and optimize future developments.
4.5 CONCLUSION
Hydrogen is set to anchor Europe’s energy transition as a versatile, low-carbon carrier that complements direct electrification. This chapter outlined its key traits, major production routes (grey, blue, green), and the policy push behind green H₂: the EU Fit-for-55 package and Hydrogen Strategy (-55 % CO₂ by 2030, net-zero by 2050) plus Dutch programmes that translate targets into projects in Groningen, Rotterdam, and beyond. Binding renewable-hydrogen quotas now embed H₂ in infrastructure, finance, and industrial plans, while successful pilots—steelmaking with H₂, cavern storage—reinforce policy momentum.
Hydrogen is not a silver bullet; it must advance alongside renewables, efficiency, and other clean fuels. Costs, conversion losses, and vast infrastructure still pose hurdles, yet strong political backing and EU-Dutch funding make them tractable. The coming decade will decide whether hydrogen scales fast enough to secure its place as a cornerstone of Europe’s net-zero energy system.
4.6 REFERENCES
1. European Commission. (2021). 'Fit for 55': Delivering the EU's 2030 climate target on the way to climate neutrality (COM/2021/550 final). Retrieved from [https://eur-lex.europa.eu/legal-content/ EN/TXT/?uri=CELEX%3A52021DC0550]
2. European Commission. (2023). Hydrogen – EU energy system. Retrieved from [https://energy. ec.europa.eu/topics/eus-energy-system/hydrogen_en]
3. Ministry of Economic Affairs and Climate Policy. (2019). National climate agreement – The Netherlands. Retrieved from [https://www.klimaatakkoord.nl/documenten/publicaties/2019/06/28/ national-climate-agreement-the-netherlands]
4. Green Hydrogen Organisation. (2021). Netherlands national hydrogen strategy Retrieved from [https://gh2.org/countries/netherlands]
5. U.S. Department of Energy. (n.d.). Hydrogen storage. Retrieved from [https://www.energy.gov/eere/ fuelcells/hydrogen-storage]
6. Center for Sustainable Systems, University of Michigan. (2024). Hydrogen factsheet (Publication No. CSS23-07). Retrieved from [https://css.umich.edu/publications/factsheets/energy/hydrogenfactsheet]
7. International Energy Agency. (n.d.). Hydrogen. Retrieved from [https://www.iea.org/energy-system/ low-emission-fuels/hydrogen]
8. Han, H. (2022, November 11). What the latest IPCC report says about zero-carbon fuels: Summary of IPCC AR6 WG III findings. Clean Air Task Force. Retrieved from [https://www.catf.us/2022/11/ what-the-latest-ipcc-report-says-about-zero-carbon-fuels/]
9. Marchant, N. (2021, July 27). Grey, blue, green – why are there so many colours of hydrogen? World Economic Forum. Retrieved from [https://www.weforum.org/stories/2021/07/clean-energygreen-hydrogen/]
10. CE Delft. (2022). 50% green hydrogen for Dutch industry: Analysis of consequences draft RED3 Retrieved from [https://cedelft.eu/wp-content/uploads/sites/2/2022/03/CE_Delft_210426_50_ percent_green_hydrogen_for_Dutch_industry_FINAL.pdf]
11. S&P Global Commodity Insights. (2021, May 4). Dutch Port of Rotterdam targets end-2026 for 'blue' hydrogen plant. Retrieved from [https://www.spglobal.com/commodity-insights/en/newsresearch/latest-news/electric-power/050421-dutch-port-of-rotterdam-targets-end-2026-forblue-hydrogen-plant]
12. Clean Hydrogen Partnership. (n.d.). Hydrogen Energy Applications for Valley Environments in Northern Netherlands (HEAVENN). Retrieved from [https://www.clean-hydrogen.europa.eu/ projects-dashboard/projects-repository/heavenn_en]
13. TNO. (n.d.). H-vision: Blue hydrogen to accelerate carbon-low industry. Retrieved from [https:// www.tno.nl/en/sustainable/industry/carbon-neutral-industry/clean-hydrogen-production/storagetransport-hydrogen/vision-blue-hydrogen-accelerate-carbon/]
14. Tata Steel Nederland. (n.d.). Green Steel Plan. Retrieved from [https://www.tatasteelnederland. com/en/sustainability/green-steel-plan]
15. Council of the European Union. (2023, July 25). Alternative fuels infrastructure: Council adopts new law for more recharging and refuelling stations across Europe. Retrieved from [https://www. consilium.europa.eu/en/press/press-releases/2023/07/25/alternative-fuels-infrastructure-counciladopts-new-law-for-more-recharging-and-refuelling-stations-across-europe/]
16. Collins, L. (2023, March 28). EU nations agree to install hydrogen fuelling stations in all major cities and every 200km along core routes. Hydrogen Insight. Retrieved from [https://www. hydrogeninsight.com/policy/eu-nations-agree-to-install-hydrogen-fuelling-stations-in-all-majorcities-and-every-200km-along-core-routes/2-1-1426859]
20. Gasunie. (2021, April 13). European Hydrogen Backbone grows to 40,000 km, covering 11 new countries. Retrieved from [https://www.gasunie.nl/en/news/european-hydrogen-backbone-growsto-40000-km-covering-11-new-countries]
21. Port of Rotterdam. (2024, September 24). First large-scale hydrogen plant on the high-voltage grid. Retrieved from [https://www.portofrotterdam.com/en/news-and-press-releases/first-largescale-hydrogen-plant-high-voltage-grid]
Chapter 5
Emerging Hydrogen-Based Carriers
In the Netherlands and across Europe, hydrogen is increasingly recognized as a versatile carrier essential for decarbonizing hard-to-abate sectors [1]. However, harnessing hydrogen’s full potential involves addressing significant practical challenges, as highlighted in previous chapter. To overcome these, hydrogen can be converted into derivative molecules with higher energy density, making them easier to store and transport [2] and suitable for specific applications. This chapter explores four hydrogen derivatives— liquid hydrogen, ammonia, methanol, and Liquid Organic Hydrogen Carriers (LOHCs)— each offering distinct advantages in storage, transport, and end-use.
The subsequent sections delve into each of these carriers in detail, assessing their roles in achieving decarbonization targets and examining inherent trade-offs.
5.1 LIQUEFIED HYDROGEN (LH₂)
Liquefied hydrogen (LH₂)—hydrogen cooled to −253°C at atmospheric pressure—offers significantly greater volumetric energy density compared to compressed hydrogen gas. This high energy density makes LH₂ especially suitable for transporting and storing renewable energy over long distances, a key requirement for countries aiming to import green hydrogen to achieve climate targets [4]. This section introduces LH₂ by detailing its production methods, storage characteristics, safety considerations, transportation infrastructure, and primary use cases.
Production and Liquefaction of LH₂
Producing LH₂ involves an energy-intensive cryogenic process, first requiring hydrogen gas production, followed by liquefaction. Hydrogen must be cooled to about 20 K ( 253 °C) at near-atmospheric pressure. Industrial liquefaction plants typically employ a modified Linde–Hampson cycle, in which hydrogen gas is compressed and precooled (often using liquid nitrogen) below 80 K due to hydrogen’s unusual Joule-Thomson inversion temperature (~195 K at 1 bar). After precooling, hydrogen expands through turbines or throttling valves, creating Joule-Thomson cooling that partially liquefies the gas. The un-liquefied portion circulates back through heat exchangers until most hydrogen is condensed. Additionally, catalysts facilitate the conversion of hydrogen's spin isomers from ortho to para, preventing heat release during storage [5].
Hydrogen liquefaction requires significant energy, typically consuming around 10–13 kWh electricity per kilogram of H₂ about 30–40% of hydrogen’s lower heating value (33.3 kWh/kg), well above the theoretical minimum (~3–4 kWh/ kg) [5]. Research aims to reduce liquefaction energy use; EU-funded projects target efficiencies around 8–10 kWh/kg through advanced cycle designs and heat exchangers. Despite the substantial energy penalty, LH₂’s high volumetric energy density justifies liquefaction for certain applications.
Currently, large-scale LH₂ plants are limited, historically serving niche markets such as rocket fuels. In Europe, liquefaction capacity is growing; Air Products operates an LH₂ facility in Rotterdam (Botlek) and plans a second plant by 2025, doubling Europe's total capacity [6]. With expanding green hydrogen production, strategic siting of large-scale liquefaction facilities at export hubs or import terminals will become essential.
Energy Density
and Storage Properties of LH₂
LH₂ offers high energy density compared to hydrogen gas, storing about 120 MJ/kg (33.3 kWh/kg), nearly three times gasoline’s gravimetric energy density (44 MJ/kg) and significantly more than advanced battery technologies (0.5–1 MJ/kg) [7];[8]. However, hydrogen's volumetric density is relatively low. LH₂ has a density around 70–71 kg/m³, translating to roughly 8–9 MJ/L, approximately one-quarter of gasoline's volumetric energy density (~32 MJ/L). Despite this, LH₂ is significantly denser than gaseous hydrogen at 700 bar (~5.6 MJ/L), making it a more efficient choice for volume-constrained applications compared to compressed gas and even lighter per energy unit than ammonia or LOHCs [9];[8].
LH₂ requires storage at cryogenic temperatures (~−253 °C) in specialized vacuuminsulated vessels (similar to large thermos flasks) made from stainless steel or aluminium alloys to minimize heat ingress and embrittlement. Despite insulation efforts, boil-off is unavoidable; larger storage tanks typically experience low boil-off rates of about 0.1–0.2% per day, while smaller, mobile tanks may experience higher rates. To manage pressure and avoid hazards, tanks include relief valves to safely vent evaporated hydrogen. In certain systems, boil-off hydrogen is recovered by reliquefication or utilized directly in fuel cells or burners [10].
Another specific challenge is the exothermic conversion of residual ortho-hydrogen to parahydrogen during storage, which further contributes to boil-off. Modern liquefaction plants thus employ catalysts to ensure complete ortho-para conversion prior to storage, enhancing LH₂ stability [5].
Though challenging for seasonal storage due to continuous boil-off, LH₂ remains a viable solution for medium-term storage. Advances in insulation and boil-off management technologies, including zero-boil-off approaches involving refrigeration cycles, could expand LH₂’s feasibility for longer-term energy storage [11].
Figure 8 Comparing the energy density of hydrogen in various forms and other fuels. Bars show energy content in kWh per 0.1 kg (grey icon) and per litter (green icon). Liquid hydrogen contains about 33 kWh/kg (3.3 kWh per 0.1 kg) and approximately 2.4 kWh/L (≈8.6 MJ/L). LH₂ has significantly higher density than gaseous hydrogen, although lower volumetric energy than ammonia or liquid methane, but offers lower weight per energy unit due to hydrogen’s low molecular weight [8].
Safety Considerations
Although hydrogen is non-toxic and disperses quickly, LH₂ poses several unique hazards [10]:
• Physical hazards: LH₂’s cryogenic temperature causes embrittlement of materials and can lead to frostbite on contact. Overpressure can result if boil-off gas is not vented; in 1974, ice formed on a vent stack and blocked hydrogen release, causing a tank explosion [12].
• Physiological hazards: Extremely cold vapor can injure lungs or lead to hypothermia. If LH₂ leaks in an enclosed area, it may displace oxygen and cause asphyxiation until it warms and becomes buoyant [12]. Outdoors, hydrogen generally disperses upward, reducing these risks.
• Chemical (flammability) hazards: Hydrogen has a wide flammability range (4–75% in air) and very low ignition energy, so even minor sparks can ignite it. Hydrogen flames are nearly invisible [13];[14]. In LH₂ spills, cold surfaces can condense or freeze air, creating localized O₂-rich zones that intensify ignition [12].
Despite such risks, decades of industrial and aerospace experience show LH₂ can be handled safely through rigorous engineering, adherence to standards (e.g., from the European Industrial Gases Association), and use of sensors, flame detectors, and venting systems [12]. Nevertheless, no uniform global LH₂ standard exists[5].
Transport and Infrastructure for Liquid Hydrogen (LH₂)
Transporting LH₂ involves specialized cryogenic infrastructure, already standard practice for industrial road transport. Vacuum-insulated tanker trucks typically carry 3–4 tons of LH₂ (~50–60 m³), managing periodic boil-off venting. Rail transport, though possible, is rare. For international trade, maritime LH₂ shipping is rapidly developing. Hydrogen trade will link renewable-rich regions like Australia and the Middle East with markets in Europe and East Asia [15]. The Suiso Frontier, launched in early 2022 by Kawasaki Heavy Industries, marked the first successful international LH₂ shipment from Australia to Japan, carrying about 75–80 tons per voyage in its 1,250 m³ tank [16]. Future larger tankers, similar to LNG carriers, could hold 150,000 m³, transporting up to 15,000 tons of LH₂
Terminals at both export and import points are expanding, equipped with liquefaction units, cryogenic storage, and marine loading/unloading infrastructure. Europe's PoR is developing a corridor from Sines, Portugal, targeting approximately 100 tons/day LH₂ deliveries by 2027 [17]. This pilot aims to establish scalable infrastructure supported by industries like aviation and heavy transport that consider LH₂ crucial for renewable energy imports.
While ammonia or other hydrogen carriers require chemical reconversion, LH₂ avoids these conversion losses but faces energy-intensive liquefaction and boil-off challenges For long-distance transport, initial conversion costs dominate [4]. LH₂ shipping appears increasingly viable if technological advancements reduce costs further, complementing pipeline distribution networks. Overall, global and European stakeholders anticipate significant growth in LH₂ logistics infrastructure by the 2030s.
Figure 9 Susio Frontier, liquefied hydrogen carrier built by Kawasaki Heavy Industries Ltd [16]
Advantages and Challenges of LH₂
LH₂ has both strong advantages and significant challenges as a REC.
Advantages: LH₂’s primary advantage is its high gravimetric energy density (33.3 kWh/kg), ideal for applications like aviation and heavy transport where weight reduction is essential. This advantage surpasses both battery and compressed gas storage, making LH₂ suitable for longrange aircraft and trucks [18]. Additionally, LH₂ facilitates long-distance RE trade by efficiently shipping hydrogen across oceans, connecting renewable-rich regions with demand centres. Rotterdam port studies suggest transport distance minimally impacts total cost once hydrogen is liquefied [4].
LH₂ provides high purity hydrogen, suitable for sensitive applications like fuel cells, and avoids carbon-containing byproducts. Its versatility enables use in transport, industry, and power generation without additional conversion. LH₂ also allows fast refuelling compared to compressed gas, attractive for heavy-duty vehicles seeking ranges over 1,000 km [17]. Furthermore, the cryogenic properties of LH₂ create synergy opportunities such as cooling superconducting power cables, improving overall system efficiency.
Challenges: Despite these advantages, LH₂’s low volumetric energy density necessitates bulky storage tanks, posing design constraints in vehicles and aircraft, reducing available space for passengers or cargo [19]. The liquefaction process itself is energy-intensive, consuming over 30% of hydrogen’s energy, significantly affecting overall system efficiency and cost competitiveness.
LH₂’s cryogenic storage requires continuous management of boil-off gases, presenting operational complexities during storage and transport. Handling boil-off necessitates additional systems, such as onboard reliquefication or gas utilization, increasing infrastructure costs. Additionally, LH₂ infrastructure—including specialized cryogenic tanks, pumps, and vacuum-insulated pipelines—is costly and limited, complicating widespread deployment.
Safety considerations also affect LH₂ adoption. While manageable, safety hazards involving cryogenic temperatures and invisible flames demand robust engineering and public education to mitigate risks. Public perception depends heavily on maintaining exemplary safety standards. Finally, LH₂’s high cost compared to fossil fuels requires policy incentives, carbon pricing, and technology improvements to become economically viable. EU policies like the Green Deal are already moving towards internalizing these carbon costs, supporting infrastructure, and enhancing LH₂’s economic prospects [20].
To conclude, LH₂ offers significant potential as REC but requires addressing technical, logistical, and economic challenges through innovation, infrastructure scaling, and supportive policies.
Developments in the Netherlands and the EU Policy Context
The Netherlands and the EU have placed LH₂ at the core of their climate-neutral strategies by 2050. The EU Hydrogen Strategy (2020) and REPowerEU (2022) aim for 10 million tons each of renewable hydrogen production and imports by 2030, targeting decarbonization of heavy industry and transport [22]. EU policy, though carrier-neutral, actively supports LH₂, particularly
for long-distance imports from regions like Australia and Chile. Investments include R&D through the Clean Hydrogen Partnership and infrastructure via TEN-E regulation updates. Efforts also focus on maritime LH₂ safety, certification, and trade corridors, exemplified by projects like the Portugal–Netherlands hydrogen route supported by platforms such as H2Global and IPCEI [17].
The Netherlands positions itself as Northwest Europe’s hydrogen hub, leveraging Rotterdam’s extensive infrastructure. By 2030, Rotterdam expects to handle 4.6 million tons of hydrogen—15% of the EU’s target [15]. Rotterdam has agreements with over 25 countries for hydrogen imports and is preparing terminals capable of managing LH₂, ammonia, and LOHC. Major investments include the Air Products–Gunvor green hydrogen terminal at Maasvlakte, initially handling ammonia with future LH₂ capacity, and Air Products’ second LH₂ liquefaction plant in Rotterdam, significantly increasing Europe’s production capacity [22].
Dutch policy integration includes revising the national Energy Act and investing in a hydrogen backbone pipeline network, linking industrial clusters domestically and internationally. Pilot projects such as Rotterdam The Hague Airport’s LH₂ for ground equipment and aircraft, and Dutch shipbuilders’ hydrogen vessels, feature emerging domestic uses. Innovation initiatives like Missie H₂ further highlight LH₂’s growing significance.
Regionally, Germany and France also focus on LH₂ imports and technology development. The EU’s Alternative Fuels Infrastructure Regulation and carbon contracts for difference (CCfD) are designed to support hydrogen market competitiveness and standardization. Ultimately, policy support, international collaboration, and significant infrastructure investment are essential for LH₂ to meaningfully contribute to Europe’s energy transition [15].
5.2 AMMONIA
Ammonia (NH₃) is emerging as a versatile zero-carbon energy carrier, producing no CO₂ upon combustion as nitrogen converts into harmless N₂ gas. Currently, 170–180 million tonnes of ammonia are produced annually, mainly for fertilisers, causing about 1–2% of global greenhouse emissions. Decarbonising this "brown" ammonia production and shifting to renewable ammonia can significantly support climate targets. Due to its high volumetric energy density (~3.5 kWh/L), established global infrastructure, and suitability for energy storage and carbon-free fuel applications in power generation and shipping, ammonia is key for renewable energy distribution. This section explores ammonia’s properties, production methods, usage scenarios, and key challenges. It also discusses ammonia’s strategic role in EU and Dutch climate policies and infrastructure development.
Thermophysical Properties and Storage Advantages
Ammonia is a pungent, colourless gas under standard conditions, easily liquefied at moderate pressure (~10 bar) or refrigeration (–33 °C). This makes ammonia simpler and less energyintensive to store than hydrogen, which requires extreme cryogenic conditions (–253 °C) or high pressures. Liquid ammonia has a volumetric energy density of about 3.5 kWh per litter (LHV ≈ 11 MJ/L), notably higher than liquid hydrogen (~2 kWh/L) and compressed hydrogen at 700 bar (~1.3 kWh/L), though lower than gasoline or diesel [23];[24]. Gravimetrically, ammonia holds about 18.6 MJ/kg, around 15% of hydrogen’s energy content (120 MJ/kg), due to nitrogen’s heavier mass. However, ammonia’s relatively mild storage conditions significantly reduce energy inputs and costs compared to hydrogen [25].
Practically, ammonia can be stored conveniently in pressure vessels similar to LPG tanks at ambient temperatures, or in refrigerated atmospheric-pressure tanks, unlike hydrogen, which demands specialized high-pressure cylinders or advanced cryogenic insulation. Figure 10 shows ammonia’s favourable volumetric energy density compared to hydrogen and conventional fuels, indicating its suitability for large-scale energy storage.
Another advantage is ammonia’s existing global infrastructure, developed from decades of agricultural and industrial usage. Approximately 10% (18–20 Mt/year) of global ammonia production is already transported internationally by sea, supported by well-established terminals, storage facilities, and ammonia-compatible pipelines worldwide [26]. For instance, the PoR, experienced in handling ammonia primarily for fertilisers, is preparing to scale imports of "green" ammonia as an energy carrier. Standard refrigerated ammonia storage tanks (around 50,000 tonnes capacity) exist at major hubs [23].
Additionally, extensive overland distribution networks—tank trucks, rail tankers, barges, and pipelines (e.g., the U.S. Gulf Coast–Midwest ammonia pipeline)—highlight ammonia’s logistical readiness compared to LH2, which lacks comparable infrastructure [24]. Thus, ammonia’s favourable physical properties and established logistics offer significant advantages for scalable RE storage and distribution.
Figure 10 Volumetric energy density of various fuels (LHV, kWh/L). Liquid ammonia (~3.5 kWh/L at –35°C or 10 bar) surpasses liquid and compressed hydrogen but is roughly one-third that of diesel [23].
Production Pathways: Brown, Blue and Green Ammonia
Conventional ammonia production (brown/grey ammonia) relies on fossil fuels, typically using steam methane reforming (SMR) of natural gas followed by the Haber–Bosch synthesis with nitrogen from air. This energy-intensive method emits around 1.9 tons CO₂ per ton NH₃, contributing about 0.5 Gt CO₂ annually—approximately 2% of global energy consumption and emissions [27].
To address these emissions, two low-carbon pathways have emerged:
• Blue ammonia uses fossil fuels with CCS. The hydrogen is still derived from natural gas or coal, but CO₂ emissions are captured and stored underground. For example, Yara’s Sluiskil plant in the Netherlands plans to capture 0.8 Mt CO₂ annually from 2025, significantly reducing its emissions [28]. Globally, multiple blue ammonia projects, especially in Gulf countries, aim to reduce lifecycle emissions by about 90% compared to conventional methods. However, residual emissions and methane leaks mean blue ammonia is low-carbon rather than zero-carbon, and scalability depends on available CO₂ storage capacity.
• Green ammonia is produced using renewable hydrogen generated via water electrolysis, powered by renewable electricity. This method yields ammonia as a RE storage medium without carbon emissions at the production point [23]. Though demonstrated a century ago at Norway’s hydro-powered plant in Rjukan, green ammonia accounts for less than 1% of global production today. Numerous new green ammonia projects have recently been announced globally. Notably, the proposed “Zeeland Hub” in the Netherlands would use offshore wind energy to run a 100 MW electrolyser, producing about 75,000 tons of green ammonia annually [29]. Countries with abundant renewable resources, like Australia and Chile, also plan large-scale green ammonia production for export.
Efficiency remains critical: current electrolyser efficiencies range around 65–70%, and Haber–Bosch processes around 80%, resulting in an overall power-to-ammonia efficiency of approximately 55–60% [23]. Although blue ammonia production can achieve slightly higher hydrogen production efficiencies (~75%), additional energy for CCS is required. Despite inherent energy losses, ammonia’s capability for energy storage and transportation justifies these conversion inefficiencies.
Emerging technologies like electrocatalytic synthesis or modular Haber–Bosch units aim to improve renewable integration but remain in early stages with low efficiencies [24]. Currently, enhancing conventional methods and integrating flexible operation with renewable hydrogen are immediate priorities. The EU’s hydrogen policies explicitly support ammonia as a REC, promoting both green and blue pathways [30].
Applications of Ammonia as a Fuel and Energy Vector Stationary Power Generation and Energy Storage
Ammonia is a promising fuel for decarbonizing electricity generation, either through direct combustion in turbines or boilers or indirectly via hydrogen production from ammonia cracking. Direct combustion allows existing power plants to reduce emissions by cofiring ammonia with fossil fuels. Japan has demonstrated this at utility scale, with JERA’s Hekinan coal plant co-firing 20% ammonia since 2021, targeting over 50% by 2030 [31]. Gas turbine manufacturers like Mitsubishi Heavy Industries have developed prototypes capable of 100% ammonia combustion, aiming for commercialization by mid-decade [32]. Challenges include ammonia’s low flame speed and high ignition energy, managed by blending with hydrogen or adjusting fuel-air mixtures [24].
Ammonia’s potential as seasonal storage complements intermittent renewables. Surplus renewable electricity can create ammonia for long-term storage, converting it back to electricity during high demand. For example, the Netherlands' Vattenfall explored ammonia storage at the Magnum gas power plant, confirming ammonia’s dual role as storage and import vector [31].
Dutch initiatives include co-firing ammonia in gas turbines and building ammonia crackers at ports to supply hydrogen. Fuel cells offer high-efficiency conversion either by direct ammonia use in SOFCs or by cracking ammonia to hydrogen for PEM cells. SOFCs achieve ~50–60% efficiency but remain costly; ammonia cracking, though simpler, incurs a 10–15% energy penalty. Overall, ammonia-to-hydrogen-to-electricity pathways yield lower round-trip efficiencies (~15–25%) compared to direct hydrogen use (~26–35%) [23].
Maritime Shipping Fuel
Ammonia is emerging as a critical zero-carbon marine fuel to meet the IMO’s goal of halving emissions by 2050. It offers carbon-free combustion and relatively high energy density among clean fuels, leveraging existing ammonia bunkering infrastructure [24]. Marine engine manufacturers like MAN Energy Solutions and Wärtsilä plan commercial ammonia-fuelled engines by 2024–2025 [23]. Initially dual fuel, these engines transition fully to ammonia over time. Classification societies (DNV, Lloyd’s Register) are updating safety and design standards. Demonstrations include the EU-funded ShipFC project retrofitting the Viking Energy offshore vessel with a 2 MW ammonia fuel cell system [33]. Existing ammonia infrastructure at major ports (Rotterdam, Antwerp, New Orleans) facilitates the rapid adaptation of ammonia bunkering networks. Rotterdam aims for a dedicated green ammonia import terminal by 2026, already demonstrating ammonia barge-to-ship bunkering. By 2030, ammonia fuelling should be available at key maritime hubs globally.
Ammonia combustion emits no CO₂ or SOx but requires measures (exhaust gas recirculation, lower combustion temperatures, aftertreatment) to minimize NOx emissions [24]. While ammonia’s volumetric energy density is lower than heavy fuel oil, large vessels can accommodate this difference without significant range reduction. Techno-economic studies by IMO and others highlight ammonia’s long-term maritime potential, especially compared to hydrogen, due to easier handling and storage [34].
In all, ammonia’s versatile applications in stationary power generation, maritime fuel, and niche transportation and industrial sectors make it a critical tool for meeting global decarbonization objectives. Despite technical and efficiency challenges, its strengths solidify its role as a versatile and essential energy carrier.
Environmental Performance and Challenges
Green or blue ammonia is a promising zero-carbon fuel—CO₂-free at the point of use and ideal for exporting renewable energy from wind- and solar-rich regions to where it’s needed most [24]. To unlock its full potential, production must be decarbonized: green ammonia is nearly carbon-neutral, while blue can cut emissions by 50–90%, depending on carbon capture efficiency [35].
A key challenge is NOx emissions during combustion. Though ideal reactions produce only nitrogen and water, real-world use can emit NOx . Solutions include blending in 5–20% hydrogen for cleaner combustion and using SCR systems, as seen in near-zero- NOx Japanese projects [24, 23].
Ammonia’s toxicity and corrosiveness demand strict safety protocols. Its pungent smell allows early leak detection (from 5 ppm), but high levels (>500 ppm) are dangerous. Still, it’s less flammable than hydrogen or LNG and widely handled under strict standards like the Dutch PGS-12 [26].
Environmental risks—like ammonia slip, eutrophication, and particulate matter—can be minimized with proper combustion control and containment [23].
Ammonia’s Role in the Netherlands and EU Energy Strategy
The Netherlands and the EU have positioned ammonia as a critical element in their hydrogen strategies and decarbonization roadmaps. The Dutch Hydrogen Strategy (2020) explicitly identifies ammonia as an essential carrier for imported hydrogen, given limited domestic renewable resources.
Central to this vision is the PoR, Europe's largest energy hub, projected to handle 18 million tons of hydrogen-equivalent imports annually by 2050, predominantly as ammonia [26].
In line with this strategy, Rotterdam initiated a major ammonia import infrastructure expansion. The ACE Terminal consortium plans storage and ammonia cracking facilities operational by the mid-2020s [36]. Similarly, OCI is expanding its ammonia terminal capacity to 1.2 Mt/year, facilitating ammonia imports from global renewable-rich regions10 Concurrently, a Port Authority-led consortium including Shell, BP, and Air Liquide is developing a large-scale ammonia cracker to convert imported ammonia into approximately one million tons of hydrogen annually for pipeline distribution11. To enhancing regional connectivity, Gasunie supports integrating ammonia cracking hubs within its broader hydrogen transport plans.
Beyond imports, the Netherlands actively promotes ammonia-based decarbonization initiatives. Vattenfall’s Magnum project in Groningen studied converting a gas-fired plant to green ammonia combustion [31]. In Zeeland, Yara's Sluiskil facility is deploying CCS to produce blue ammonia [28]. Offshore wind-to-ammonia initiatives, such as the “PosHYdon” project, also demonstrate the nation's commitment to integrating renewable ammonia production with existing infrastructure. The presence of leading chemical companies (OCI, Yara) and research institutions (TNO, TU Delft) has further accelerated ammonia energy system developments.
At the European level, ammonia is integral to the broader hydrogen vision articulated in the EU Hydrogen Strategy and RePowerEU plan, both targeting 10 Mt of imported renewable hydrogen by 2030, with ammonia as a primary carrier [30]. EU policy and trade agreements with countries like Oman, UAE, and Australia increasingly include ammonia as a key commodity. The EU supports ammonia innovation through Horizon Europe and IPCEI12, funding vessels, safety, and ammonia-to-power infrastructure.
Sectoral strategies further embed ammonia in Europe's energy transition. The International Maritime Organization (IMO) and the EU’s FuelEU Maritime regulation highlight ammonia’s role as a compliant maritime fuel, accelerating adoption in shipping13. Heavy industry sectors like steel and cement are exploring ammonia-based solutions, either directly as fuel or as a hydrogen source from ammonia cracking. The updated Dutch Climate Plan explicitly supports importing green ammonia via Rotterdam and Vlissingen for steelmaking and chemicals, emphasizing ammonia’s strategic value14
Ammonia’s role in EU and Dutch strategies highlights its climate potential, though challenges remain around certification, safety, and public acceptance. With updated standards like PGS-12 and ongoing EU research, ammonia is poised to become a key pillar of Europe’s net-zero transition.
5.3 GREEN METHANOL
Green methanol – methanol produced from renewable feedstocks – is gaining attention as a renewable energy carrier. Identical to conventional methanol, it serves both as fuel and as a chemical feedstock, offering a pathway to decarbonize the energy and chemical sectors. It is one of four critical chemicals underpinning the industry. Two-thirds is used for chemicals like formaldehyde and plastics, and one-third is used as fuel in transport and power generation [37]. Transitioning to green methanol, produced via renewable methods, can drastically cut emissions. It stores renewable energy (via hydrogen) and captured CO₂ in liquid form, easing transport and use in difficult to abate sectors.
Production
Pathways for Green Methanol
Green methanol can be produced via two main routes: bio-methanol from biomass or waste and e-methanol from green hydrogen and CO₂. In bio-methanol production, sustainable biomass or waste is gasified or reformed to produce syngas—a mixture of CO, CO₂, and H₂—which is then catalytically converted into methanol [37]. In the electro-fuel route, renewable hydrogen is produced by water electrolysis using renewable electricity, and CO₂ is captured from industrial emissions or directly from the air. These react over a copper-based catalyst according to the reaction: CO₂ + 3H₂ -> CH₃OH + H₂O, yielding green e-methanol as long as the CO₂ source is renewable or biogenic [37].
Numerous projects are underway globally and in Europe. In the Netherlands, the OCI GasifHy project in Delfzijl will gasify local waste and biomass, adding green H₂ to produce green methanol at scale [38]. Other European initiatives plan to synthesize methanol directly from offshore wind-powered hydrogen and captured CO₂. These pathways highlight a key advantage: green methanol recycles carbon, effectively acting as a CCU strategy [39].
Production Efficiency and Costs: Producing e-methanol requires roughly 10–11 MWh of electricity per tonne, achieving an efficiency of about 56–62% [40]. While e-methanol currently costs around $1200–1600 per tonne versus ~$400 for fossil methanol, biomethanol from waste can be cheaper at approximately $700–900 per tonne.
EU policies like RED II and FuelEU Maritime are driving down green methanol costs and encouraging investment [41].
Energy Density and Comparison with Other Carriers
One of methanol’s most important characteristics as an energy carrier is its energy density relative to other fuels. On a mass basis, methanol contains about 20 MJ/kg of LHV [37]. This is less than half the LHV of diesel (≈43 MJ/kg) or gasoline, and much lower than hydrogen’s LHV (120 MJ/kg). However, gravimetric figures can be misleading because hydrogen’s high energy per kilogram is offset by its extremely low density. Volumetric energy density is often more critical for storage and transport. At ambient conditions, methanol is a liquid with a density of approximately 790 kg/m³, yielding an energy content of about 15.8 GJ/m³ (or ~15.8 MJ per litter) [37]. This is roughly half the energy per litter of gasoline or diesel but far exceeds that of hydrogen. For example, one litter of methanol contains three times more energy than a litter of compressed H₂ at 700 bar and about twice the energy of liquid hydrogen (LH₂ at –253 °C). In fact, because of hydrogen’s low molecular weight, one litter of methanol carries more hydrogen atoms than one litter of LH₂. Ammonia, another alternative energy carrier, has a volumetric energy density (~11.5 GJ/m³) slightly lower than methanol [37] and must be stored under pressure or at –33 °C. In contrast, methanol remains liquid at standard temperature and pressure, requiring no cryogenic handling. Figure 11 illustrates these comparisons [42].
Practically, methanol-fuelled vehicles or ships need roughly double the fuel tank volume for the same range as diesel. LNG still offers about 30% higher volumetric energy than methanol [42], but LNG requires deep cryogenic storage (–162 °C). Methanol’s ease of storage and transport in conventional tanks is a key advantage, enabling existing fuel infrastructure to be adapted with minimal modifications [37];[39].
Figure 11 The methanol value chain.15
Transport, Storage, and Handling Requirements
Methanol as a liquid fuel can leverage much of the existing hydrocarbon fuel infrastructure. It is compatible with tanker trucks, rail cars, pipelines, and storage tanks used for gasoline or diesel, with some caveats. Methanol is a polar solvent and can be corrosive to certain metals (like aluminium, zinc, or some steel alloys) and degrading to some rubber seals or coatings [40]. Thus, storage and fuel systems must use methanol-grade materials (e.g. stainless steel or lined tanks, and compatible polymers) to avoid corrosion or leaks. These adaptations are well-known in the chemical industry, which has safely handled methanol at large scale for decades. In fact, methanol is already available at 90 of the world’s 100 largest ports as a commodity chemical or fuel [43]. This widespread availability highlights the logistical advantage of methanol: unlike hydrogen, which would require entirely new infrastructure, methanol can be integrated into existing fuel supply chains [39]. Its liquid nature at ambient pressure also means energy-dense bunkering is much faster and simpler than for cryogenic liquids. For example, ships in Rotterdam have bunkered methanol via modified fuel barges in a procedure similar to conventional fuel oil bunkering [43].
Safety considerations for methanol are well understood. Methanol is flammable (flash point ~11 °C, so it is treated as a flammable liquid similar to gasoline) and burns with a nearly invisible flame. Adequate ventilation and flame detection are required in storage areas. Unlike LNG or hydrogen, there is no risk of overpressure from boil-off gases at ambient conditions, simplifying tank design (no need for pressurization or venting systems for normal storage). Methanol is toxic if ingested or absorbed in large amounts; however, as a fuel it is handled in closed systems, and its toxicity risk is considered manageable with proper procedures. In case of spills, methanol is water-soluble and biodegrades relatively quickly, causing less lasting environmental harm than oil or gasoline spills. Overall, industry experience indicates that methanol can be stored and transported with similar or lower complexity than many petroleum fuels [39]. Notably, pipeline transport of methanol is feasible and in use. These attributes position green methanol as a leading candidate to ferry RE between regions.
Applications and Use Cases
Shipping (Marine Fuel): The maritime sector is ready to become the largest user of green methanol as a fuel. Methanol can be used in modified marine diesel engines or sparkignition engines, and several large shipowners have already embraced it. As of early 2025, over 300 methanol-fuelled ships are on order globally [41], including container ships, tankers, and cruise vessels. Dual-fuel engines, capable of running on methanol or diesel, have been developed by MAN Energy Solutions and Wärtsilä. This interest is driven by increasingly strict emissions regulations and by methanol’s practical advantages: low pollutant emissions and ease of retrofitting. In operation, methanol-fuelled ships can achieve near-zero SOx and particulate emissions and significantly lower NOx [43]. CO₂ emissions are reduced by about 10–15% per unit energy when using fossil methanol, and by up to 95% when using green methanol produced from CO₂ [44]. Notably, the world’s first methanol-ready container ships were launched in 2023 by Maersk. The PoR began regular methanol bunkering operations in 2023 and sold over 1,500 tons of fossil methanol that year [43]. In 2024, the OCI/BioMCN plant in the Netherlands supplied green methanol for the maiden voyage of a Maersk container vessel [38]. European ports are now investing in dedicated storage and bunkering facilities, while initiatives like the Netherlands-based MENENS project are developing retrofit kits to convert diesel engines to methanol [41].
Ground Transportation: Methanol has a long history as a transportation fuel. It can be used in ICEs with minor modifications. In China, thousands of methanol-fuelled taxis, trucks, and buses operate on M100 (100% methanol) or M15 blends (15% methanol in gasoline) [37]. Although the rise of EVs has diminished the prospect of widespread methanol car adoption in the EU, methanol’s role may emerge via fuel cells. In such systems, methanol is reformed to produce hydrogen for fuel cell vehicles— as seen in the Gumpert Nathalie15 sports car, which features a methanol reformer fuel cell used as a range extender. In heavy-duty trucking, methanol’s high-octane rating (RON ~109) and clean combustion offer advantages, although competition from battery-electric and hydrogen fuel cell trucks remains strong.
Aviation: Direct use of methanol in jet engines is challenging due to its lower energy density and materials incompatibility with current aircraft fuel systems. However, methanol is increasingly used as a feedstock for Sustainable Aviation Fuel (SAF) via the Methanol-to-Jet (MTJ) process. In this catalytic conversion, green methanol is transformed into a kerosenelike fuel. This approach is being pursued at the PoR’s e-SAF hub, a project aiming to produce 250,000 tonnes per year of sustainable jet fuel from imported green methanol [45]. Additionally, research is underway on hybrid electric aircraft that use onboard methanol reformers feeding hydrogen fuel cells to power propellers.
Figure 12 A simplified pathway showing how biomass, municipal solid waste, carbon capture, and green hydrogen feed into methanol production. The resulting bio methanol or e-Methanol can then be converted into e-SAF, shipping fuel, and e-Olefins [46].
Focus on the Netherlands and EU
The Netherlands and the broader EU are positioning green methanol as a key component of their clean energy strategies. The PoR is central to this vision, aiming to become a leading green methanol hub—not only by bunkering methanol for ships but also as an import, storage, and distribution centre for Europe. In 2024, Rotterdam granted its first continuous methanol bunkering permit and is expanding its tank storage, anticipating routine fuelling of dozens of methanol ships in the coming years [38]. Rotterdam is also forging international partnerships. For example, Dutch and Spanish companies are developing a supply chain to import green methanol from Spain’s solar-powered hydrogen projects in liquid form [47].
Several high-profile demonstration projects in the Netherlands have proven methanol’s viability. The EU-funded FASTWATER project, with Dutch participation, demonstrated methanol-fuelled harbour vessels and helped develop bunkering guidelines. The Green Maritime Methanol consortium (2018–2020) tested methanol engines on various ship types with input from Dutch shipbuilders and research institutes. Additionally, Dutch technology company Nedstack integrated methanol fuel cell systems on a passenger vessel (the MS Innogy), showcasing a fuel-cell ferry powered by methanol [37]. On the R&D side, TNO is advancing retrofit solutions (MENENS project) to convert existing marine engines to methanol [41].
As a major chemical producer, the Netherlands is also exploring green methanol to decarbonize chemical processes, with companies like DSM and Sabic investigating its use in plastics production. The Chemport Europe initiative in Groningen is studying large-scale production of methanol from waste gasification to supply industry and bunker ships [38].
At the EU level, the FuelEU Maritime regulation is expected to mandate a minimum share of RFNBOs, including e-methanol, in the shipping fuel mix by 2034 [48]. EU support, along with investments from the European Investment Bank and national green funds, is driving projects in Denmark, Spain, and beyond. These integrated supply chains are central to the EU’s strategy to capitalize on green methanol’s versatility for a decarbonized energy future.
5.4 LIQUID ORGANIC HYDROGEN CARRIERS (LOHCS)
Liquid Organic Hydrogen Carriers (LOHCs) are organic liquids that reversibly bind hydrogen via hydrogenation/dehydrogenation reactions, allowing a stable liquid to be “charged” with hydrogen and later “released” on demand [49]. Since LOHCs physically resemble conventional fuels, they can leverage existing fuel infrastructure for handling and transport. Importantly, LOHC dehydrogenation produces only hydrogen, with the carbon remaining in the liquid, thereby avoiding CO₂ emissions. This makes LOHCs a promising alternative for stationary storage and long-distance transport.
LOHC Systems and Chemistry
An LOHC system consists of a pair of chemical states – a hydrogen-lean form and a hydrogen-rich form of an organic compound. Through hydrogenation (a reaction with H₂), the lean form converts to the hydrogen-saturated form, effectively storing hydrogen in chemical bonds. Later, through dehydrogenation, the reaction reverses to release hydrogen and regenerate the lean carrier, enabling repeated cycles of energy storage [49]. In principle, any unsaturated organic molecule (e.g., those with C=C or aromatic bonds) can absorb hydrogen [50], but practical LOHCs must offer high hydrogen capacity, favourable reaction kinetics, cycle stability, low toxicity, and remain liquid under operating conditions.
Two common LOHC systems are extensively studied. The first is Dibenzyltoluene (DBT), an aromatic heat-transfer oil that can absorb up to 6 moles of H₂ per molecule to form perhydro-dibenzyltoluene (H₁₈-DBT), corresponding to approximately 6.2 wt% hydrogen content [51]. DBT-based LOHC, commercially employed by Hydrogenious LOHC Technologies, remains liquid over a broad temperature range (melting point ≈ −70 °C and boiling point ≈ 280 °C) and is chemically stable, not classified as a dangerous good [52]. The second system is the Toluene/Methylcyclohexane (MCH) pair, where toluene (C₇H₈) is hydrogenated to methylcyclohexane (C₇H₁₄) by adding 3H₂ molecules, also yielding about 6.2 wt% hydrogen capacity [51]. Toluene is widely available, with a low boiling point (~111 °C), while MCH, with a boiling point around 101 °C, is stable and easily transported. Other candidates include N-ethylcarbazole (NEC) (~5.8 wt% H₂, m.p. ~69 °C) and diphenylmethane (~6.9 wt% H₂, m.p. ~24 °C); however, high melting points, as seen with NEC, can complicate handling in cold climates.
LOHCs enable repeated hydrogen storage cycles without the need for high-pressure tanks or cryogenic cooling.
Hydrogenation chemistry in LOHC systems typically involves saturating aromatic rings or double bonds. For example, toluene reacts with 3H₂ to form methylcyclohexane, an exothermic reaction releasing significant heat (about 9 kWh per kg H₂ stored) [51].
DBT hydrogenation (DBT + 9 H₂ -> H₁₈-DBT) follows similar principles. These reactions usually occur at 150–200 °C and moderate pressures (30–50 bar H₂) in the presence of catalysts such as supported noble metals (Pd, Pt, Ru) or Ni-based catalysts [53]. Notably, some studies have shown that DBT can even be hydrogenated using H₂-rich industrial off-gas streams.
For dehydrogenation, the loaded LOHC is heated—typically to 250–320 °C to reverse the hydrogenation, releasing H₂ and regenerating the lean carrier [50]. For instance, methylcyclohexane dehydrogenation occurs at around 300–350 °C over a Pt/Al₂O₃ catalyst, yielding toluene and H₂ [53]. The process requires significant energy input due to a high reaction enthalpy (~10 kWh per kg H₂), necessitating efficient heat management. Supported noble metal catalysts are crucial, and research continues to enhance their activity and reduce costs. Importantly, without both heat and catalyst, hydrogen release effectively stops, providing an inherent safety advantage. After dehydrogenation, any LOHC vapor is removed through simple condensation or purification, yielding high-purity hydrogen suitable for fuel cells or industrial use, and the spent LOHC can be recycled, closing the loop.
Energy Density and Efficiency of LOHC Systems
A key metric for any hydrogen carrier is how densely it stores energy by mass and volume. LOHCs typically have gravimetric hydrogen capacity around 5–7 wt% and volumetric hydrogen density on the order of 50–60 kg H₂ per cubic meter of liquid [51].
Tabel 1 Hydrogen storage densities and conditions for LOHCs vs other carriers.
Compressed H₂ (700 bar) 100% (gas) ~40 kg/m³ [49] ~1.3 MWh/m³ High-pressure gas (700 bar, 15°C)
* Volumetric energy based on hydrogen’s lower heating value (33.3 kWh/kg) contained in the stored H₂.
LOHCs have a lower gravimetric energy density than competing carriers—only about 6% of the LOHC mass is hydrogen, compared to ~17.8% in ammonia and 100% in liquid hydrogen. This means that transporting a given mass of hydrogen via LOHC requires moving approximately 15–20 times more mass. However, volumetrically, LOHCs are competitive. A practical rule of thumb is that LOHCs can store about 50 kg of H₂ per cubic meter [51], which is higher than compressed hydrogen at 700 bar (~40 kg H₂/m³; [49] and close to that of liquid hydrogen (~71 kg/m³). In fact, under typical industry conditions, LOHCs operate at ambient pressure, offering higher volumetric density than gaseous hydrogen, and one LOHC tanker truck can transport as much hydrogen as multiple highpressure gas tube trailers.
The energy efficiency of the LOHC cycle involves losses during hydrogenation and dehydrogenation. Hydrogenation is exothermic, releasing heat that can be wasted if not recovered, while dehydrogenation requires heat input. Without effective heat integration, the round-trip efficiency is around 60–70% [50]. With proper thermal integration—using waste heat or external sources—the theoretical efficiency can rise to 80–90%. Pilot projects like the AQUAVentus project and the Kopernikus “Power-to-X” program focus on this heat management, making LOHC shipping energy efficiency roughly equivalent to liquid hydrogen and competitive with ammonia [50].
Infrastructure Compatibility and Safety Aspects
LOHC technology offers significant advantages through its compatibility with existing hydrocarbon infrastructure. Unlike cryogenic or high-pressure hydrogen, LOHC fluids can be handled with the same equipment used for diesel, oils, or chemicals. This means LOHCs can be stored in standard atmospheric tanks without the need for specialized pressure-rated vessels or insulated dewars. For example, the PoR is repurposing its oil terminals for LOHC imports and launched a pilot project in 2023 [38]. LOHCs are pumped using ordinary liquid pumps and transported by tanker trucks, rail tank cars, or barges. Container-scale transport using ISO containers or 1000 L IBC totes, as demonstrated in the HySTOC project, further highlights LOHC’s logistical flexibility [52].
LOHC liquids are also compatible with pipeline transport, similar to conventional liquid fuels. Although pipeline heating or drag-reducing agents might be necessary if LOHC viscosity is high. Many candidates, such as MCH, have viscosities similar to gasoline, which makes it feasible to repurpose existing oil pipelines for their transport.
Integration with existing fuel infrastructure is another advantage. Because LOHCs behave like typical liquids, fuelling stations can adapt infrastructure used for gasoline or diesel. For instance, hydrogen refuelling stations could deliver LOHC fluid and employ on-site dehydrogenation units to produce hydrogen—a concept demonstrated in Finland by the HySTOC project [52]. In terms of safety, LOHCs offer notable benefits. Hydrogen remains chemically bound within the carrier until released by heat and a catalyst, significantly reducing explosion or fire risks. Compounds such as DBT have high flash points (around 130 °C;[51]) and are classified as non-dangerous for transport. Overall, LOHC technology leverages existing liquid fuel logistics and presents a lower hazard profile, making it ideal for densely populated regions and ports [55];[56].
Applications in Stationary Storage, Transport, and Industrial Integration
LOHCs offer a promising pathway for large-scale hydrogen storage. Excess renewable electricity can generate hydrogen via electrolysis, which is then hydrogenated into an LOHC for storage. LOHCs are stored in atmospheric-pressure tanks. This makes them attractive for seasonal storage. A review highlighted LOHCs as a promising option for large-scale stationary storage when high volumetric density is needed [53]. Although the round-trip efficiency (electricity -> H₂ -> LOHC -> H₂ -> electricity) may be low (around 30–40% after fuel cell conversion), the ability to store hydrogen over long periods with minimal self-discharge offers significant value. LOHC units can also stabilize the grid by absorbing sudden hydrogen surges from industrial users or pipelines.
LOHCs are actively being explored for long-distance hydrogen transport. For example, Japan’s global hydrogen supply chain project in 2020 used a toluene/MCH LOHC system to ship hydrogen from Brunei to Kawasaki, Japan [50]. In Europe, the Green Crane project (2019–2024) investigates importing Spanish renewable hydrogen via LOHC through seaports to the Netherlands [49].
Industrial clusters can use LOHC as an effective linking medium. A refinery may produce byproduct hydrogen or generate it on-site, storing it in an LOHC for later use or export. Clusters needing hydrogen for processes like green steelmaking could import hydrogen via LOHC and release it as needed. Waste heat from industrial processes can drive LOHC dehydrogenation, as shown in projects such as AQUAVentus and HECTOR in Germany [49]. In decentralized systems, LOHCs facilitate hydrogen deployment in remote areas without extensive infrastructure. Local solar-generated hydrogen stored in LOHC can power backup generators. Pilot projects like HySTOC (2018–2022) have successfully demonstrated this concept.
Current Industrial Projects and Developments
LOHC technology has swiftly transitioned from laboratory research to real-world pilots, especially in Europe and the Netherlands. Several projects underscore its industrial potential.
Hydrogenious LOHC: Hydrogenious LOHC Technologies in Germany, a pioneer using DBT-based LOHC, has been involved in over 11 pilot projects by 2023 [49]. Notable initiatives include the SmartQuart project, which integrates LOHC storage into local energy grids, and the HECTOR project at Chempark Dormagen (Covestro), employing LOHC hydrogenation in a chemical plant. The Kopernikus P2X program focuses on improving dehydrogenation heat management. Germany’s 2023 hydrogen import strategy includes LOHC alongside ammonia and methanol [55];[56].
HySTOC: The EU-funded HySTOC project successfully demonstrated a full supply chain for LOHC-fuelled hydrogen refuelling stations. By 2020, HySTOC proved that DBT-based LOHC can deliver five times more hydrogen per transport unit than 200 bar cylinders and is “not classified as dangerous goods” and “hardly flammable” [52]. The project also achieved up to an 80% reduction in transport costs compared to conventional highpressure hydrogen delivery.
Green Crane and Blue Danube: The Green Crane project, part of the IPCEI on hydrogen, focuses on LOHC logistics from Spanish solar production to Northern Europe. Pilot-scale hydrogenation units have been built in Spain, with initial shipments to Rotterdam planned by 2024 [49]. Similarly, the Blue Danube project—led by Verbund (AT) aims to ship 3,000 tonnes of hydrogen per year via LOHC along the Danube, testing a complete value chain from electrolysis in Romania to dehydrogenation in Bavaria.
Netherlands & International Initiatives: In the Netherlands, companies such as Vopak and Koole are exploring LOHC handling at the PoR. In 2022, Koole and Chiyoda (Japan) partnered to apply MCH technology for LOHC imports. Additionally, Dutch firm HyGear is advancing on-site hydrogen generation and LOHC solutions. Internationally, Japan is expanding LOHC technology following a successful Brunei–Japan shipment [50], and Hyundai Motor invested in Hydrogenious LOHC in 2020, while Middle Eastern initiatives like Dii Desert Energy propose exporting hydrogen via LOHC16
Challenges and Ongoing R&D: Key challenges include catalyst durability, complete hydrogen release, and reactor design [53]. The EU’s CHP funds projects such as KEROGREEN17, which explores bio-based LOHC molecules. Policymakers are incorporating LOHC into EU hydrogen import strategies to diversify supply. If these initiatives succeed, LOHC could become a standard option in the hydrogen economy.
5.5 CONCLUSION
This chapter explored four key renewable energy carriers—liquid hydrogen (LH₂), ammonia, green methanol, and LOHCs—each addressing specific challenges in the energy transition. LH₂ is gaining traction for high-energy-density applications like aviation, heavy transport, and seasonal storage, supported by EU and Dutch investments in cryogenic infrastructure. Ammonia, with its ease of storage and global infrastructure, is well-suited for shipping and power, though its toxicity and NOx emissions require careful management. Green methanol offers a scalable, drop-in fuel for sectors where hydrogen is less practical, leveraging CO₂ recycling and existing logistics. LOHCs simplify hydrogen handling through ambient-condition storage and use of existing fuel networks, though efficiency gains and catalyst durability are still needed. Together, these carriers form a complementary portfolio critical to achieving Europe’s climate goals and building a flexible, resilient energy system.
5.6 REFERENCES
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Part III
NOVEL AND ALTERNATIVE ENERGY CARRIERS
Chapter 6
Alternative Energy Carriers: The Case of Iron
Iron, one of the most abundant metals on Earth, is emerging as a promising energy carrier for a carbon-neutral energy system. In metallic form, iron can be viewed as a solid fuel that stores energy, which is released upon oxidation (essentially “rusting” or burning) and can be recharged by reducing the oxidized iron back to metal [1]. This concept is inherently circular: the same iron can be used repeatedly, closing the loop by cycling between metal and oxide [2]. Unlike fossil fuels, the combustion of iron produces no CO₂ emissions – the only combustion product is solid iron oxide (rust) that can be collected and recycled [3];[2].
Iron fuel thus offers the prospect of high-temperature heat generation without greenhouse gases, a feature attractive for hard-to-decarbonize sectors such as industry and power generation. Furthermore, iron is plentiful and already produced in massive quantities for metallurgy, meaning an infrastructure basis exists and the material is recyclable using well-established processes [2]. Recent pilot projects in Europe have demonstrated iron’s viability as a fuel at industrial scale, featuring its potential to enable a sustainable, circular energy economy. This chapter explores iron as a REC, emphasizing its use as a recyclable solid fuel and energy storage medium via redox cycles. Both the dry (iron/air) and wet (iron/water) pathways are discussed. We assess energy density, combustion, emissions, production, recycling, and infrastructure, with EU and Dutch case studies demonstrating real-world progress and challenges.
Iron is abundant, non-toxic, and already supported by a global industrial infrastructure.
6.1 IRON OXIDATION-REDUCTION CYCLES FOR ENERGY STORAGE
Iron can store and release energy through reversible oxidation-reduction (redox) reactions, functioning much like a rechargeable battery. During the exothermic reaction, metallic iron (Fe) is oxidized to iron oxides, releasing heat; in the reverse endothermic step, the iron oxide is reduced back to metal using an external energy input, thus “recharging” the iron fuel.
Two main redox cycles have been proposed for iron-based energy storage:
• Dry Cycle (Iron-Air Cycle, Fe -> Fe₂O₃): In the dry cycle, iron metal is burned in air to form iron (III) oxide (hematite, Fe₂O₃). The overall reaction is 4Fe + 3O₂ -> 2Fe₂O₃, which releases heat. This combustion can be harnessed to produce HT heat for power generation or industrial processes [2]. The solid Fe₂O₃ (rust) formed is collected after combustion. To recharge the cycle, Fe₂O₃ is reduced back to iron – typically by reacting it with hydrogen to produce iron and water (Fe₂O₃ + 3H₂ -> 2Fe + 3H₂O) [1]. This reduction consumes energy, essentially storing that energy in metallic iron. The regenerated iron fuel can then be reused for combustion. In this way, the iron/ironoxide dry cycle allows carbon-free heat production, with water as the only by-product of the regeneration step. Alternatively, emerging electrochemical reduction methods (such as HT electrolysis or electrolytic iron production) could directly reduce iron oxides to metal using renewable electricity, bypassing the intermediate hydrogen step [4];[3].
• Wet Cycle (Iron-Water Cycle, Fe -> Fe₃O₄ + H₂): In the wet cycle, iron is oxidized not by oxygen from air but by steam, producing hydrogen gas as the energy output. In a typical reaction, 3Fe + 4H₂O (g) -> Fe₃O₄ + 4H₂. Here iron metal reacts with high-temperature steam, yielding magnetite and H₂ [5]. The hydrogen gas carries the energy released and can be used as a fuel. This iron-steam process is a form of thermochemical water splitting [6]. To close the loop, the resulting iron oxide (Fe₃O₄) must be reduced back to iron. This can be achieved by a subsequent reduction step, for example Fe₃O₄ + 4H₂ -> 3Fe + 4H₂O, using hydrogen (or syngas) in a reactor, or by using a renewable electrochemical process. This approach is being studied in the context of chemical looping hydrogen (CLH) generation systems with iron-based oxygen carriers [7];[8]. The wet cycle yields valuable hydrogen; however it involves more complex multi-step chemistry and material handling and careful control of oxidation states (Fe -> Fe₃O₄ -> FeO, etc.).
Both cycles showcase iron’s versatility: the dry cycle provides carbon-free heat for stationary uses, while the wet cycle enables on-demand hydrogen production. Unlike fossil fuels, both produce solid iron oxide, which can be collected and returned for regeneration [3];[2].
6.2 ENERGY DENSITY OF IRON VS. OTHER ENERGY CARRIERS
A key metric for any energy carrier is its energy density, both gravimetric and volumetric Iron offers moderate gravimetric but exceptional volumetric energy density (Figure 13) When fully oxidized to Fe₂O₃, iron releases ~7.4 MJ/kg of heat [1]. This is much lower than hydrogen (~120–142 MJ/kg), gasoline (~46 MJ/kg), ammonia (~18–22 MJ/kg), or methanol (~20 MJ/kg). Iron’s low specific energy is due to its heavy atomic mass, but its volumetric density is remarkable: packed iron powder (~5–8 g/cm³) stores up to 55 MJ/L, far exceeding liquid hydrogen (~8–9 MJ/L), ammonia (~12 MJ/L), or methanol (~16 MJ/L). One cubic meter of iron can store as much energy as 11 m³ of pressurized hydrogen [9]. Iron is also stable and loss-free, with no self-discharge or boil-off. In short, while iron requires more mass than hydrogen or e-fuels for the same energy, its solid stability, high volumetric energy, and ease of storage and transport (no cryogenics or pressure vessels) make it ideal for stationary or maritime applications, though less suited for mobile use.
Figure 13 Gravimetric and volumetric energy densities of iron compared to selected fuels
6.3 COMBUSTION CHARACTERISTICS AND EMISSIONS OF IRON FUEL
When used as fuel, iron is typically in fine powder form, allowing rapid combustion in air. Suspended iron powder can sustain a flame, resembling hydrocarbon dust flames [2]. Figure 14 illustrates a glowing iron combustor. This heterogeneous combustion (solid fuel with gaseous oxidizer) can reach flame temperatures around 1800°C, though practical systems operate below ~1500–1600°C to prevent melting or sintering of particles [10].
Figure 14 Iron powder burning inside a combustion chamber, creating a bright incandescent glow, emitting heat as it oxidizes to rust [3];[2].
Combustion behaviour: Iron powder only needs a brief pre-heat to ignite. Fine particles (10–50 µm) then burn quickly to Fe₂O₃, while larger grains may drop out of the flame before fully oxidising [10]. To stop the hot particles from fusing into clumps, iron burners - much like pulverised-coal or fluidised-bed units - run with plenty of excess air, cooling heat exchangers, or rapid quenching. These measures keep the flame below 1500 -1600 °C, the melting range of iron and its oxides, leaving a loose, reusable iron-oxide powder [10].
Emissions profile: A key benefit is that iron combustion emits no CO₂, since it contains no carbon [9]. The only by-product is solid Fe₂O₃, which is recyclable and can be collected by gravity or filtration. Fine particulate emissions can be minimized with cyclone separators, baghouse filters, or magnetic filters [10]. Pilot systems show that with proper filtration, particulate matter remains low.
Iron fuel combustion also produces no SOx, no CO, and no unburnt hydrocarbons. While NO x can form due to high combustion temperatures, initial pilots show much lower NO x emissions than coal or gas [9]. This could be because iron flames can be operated in regimes that avoid exceedingly high peak temperatures or because the combustion zone may be more uniformly distributed (preventing hot spots). With existing NOx control systems, retrofitting fossil fuel boilers to iron may be feasible [10].
Combustion efficiency and control: High combustion efficiency is achievable with proper iron-air mixing and residence time. Because iron is solid, maintaining even dispersion (dust cloud or fluidized bed) is critical. Iron combustion doesn’t require a narrow fuel/air ratio, making it resilient under lean burn conditions—as long as oxygen is present, iron will oxidize. However, very cold or dilute air may inhibit ignition [2].
Heat transfer and flame properties: Iron flames emit intense radiant heat from glowing particles and hot gases. The solid iron oxide residue is less sticky than coal ash, reducing fouling on heat exchanger surfaces [10]. This enhances boiler reliability and simplifies maintenance. High flame luminosity also improves heat transfer, especially useful for steam generation.
Overall iron powder combustion can be adapted for HT heat in power and industrial settings using familiar technologies like burners and particulate filters. The process produces no CO₂, minimal NOx, and low PM emissions with proper design [9]. Iron oxide emissions are non-toxic (essentially rust), though fine particles should be controlled. Efficient oxide capture and recycling reduce material loss and environmental impact.
6.4 PRODUCTION AND RECYCLING OF IRON FUEL
Implementing iron as a REC requires efficient methods to produce iron fuel from its oxidized form and to recycle the oxidized residue. In nature, iron is mostly found as iron oxides (ore), so energy must be invested to produce metallic iron – this is essentially the charging step of the iron fuel cycle. Traditional ironmaking uses carbon to reduce iron ore. For iron to serve as a REC, the production process must be decarbonized, using carbon-free energy inputs.
Several production pathways are considered:
• Hydrogen Reduction of Iron Oxides: This method, often called direct reduction, uses hydrogen gas as the reducing agent to convert iron oxides (like Fe₂O₃ or Fe₃O₄) into metallic iron. The chemical reaction is Fe₂O₃ + 3H₂ -> 2Fe + 3H₂O (for hematite), proceeding via intermediate magnetite/wüstite. The energy required for the reduction is significant: producing 1 kg of iron via H₂ reduction requires hydrogen with roughly 7.7–9.8 MJ of energy (in lower heating value) [1]. In practice, due to some inefficiencies, about 9–10 MJ of hydrogen might be consumed per 1 kg Fe (this corresponds to ~0.05–0.085 kg of H₂ per kg Fe, since H₂ has 120 MJ/kg LHV). This energy is what will later be released (7.4 MJ) when the iron is burned, meaning the round-trip efficiency is governed largely by the efficiency of hydrogen production. Current electrolysis operates at ~70–80% efficiency, and the iron reduction itself is highly endothermic. An analysis of the iron cycle shows an overall efficiency around 76–79% from input electricity to output heat [1]. The hydrogen-reduction route is currently the primary method envisioned for near-term iron fuel production.
• Electrochemical Reduction (Electrolysis of Iron Ore): Another route is to reduce iron oxides directly using electrical energy in an electrochemical cell, producing iron metal and oxygen gas. This can be done via high-temperature electrolysis (such as molten oxide electrolysis or solid oxide electrolysis). One example is the use SOECs to reduce steam and iron oxide simultaneously – concepts suggest that coupling hydrogen production and iron oxide reduction in one system could share heat and improve efficiency [4].
There are also companies developing molten oxide electrolysis (e.g. Boston Metal) for steelmaking. The ultimate vision is a direct electrically driven iron cycle, where renewable electricity reduces rust (Fe₂O₃) to iron and oxygen in a single step, eliminating intermediate stages. This approach could significantly increase the round-trip efficiency of the iron cycle—potentially above 80–90%—though the required technologies are still under development18.
Other Reduction Methods: In principle, any method that produces metallic iron from iron oxide could be part of the cycle. This includes chemical looping systems where a fuel like syngas or biogas reduces iron oxide, or thermochemical cycles using concentrated solar heat to drive reduction at high temperatures. For example, carbon could reduce iron oxide in a renewable framework, though CO₂ is emitted so it would require biomass or CO₂ capture to be carbon neutral.
The energy economics of iron fuel depend on the efficiency of the reduction step. Since ~7.4 MJ/kg is released by iron combustion, one must spend somewhat more than this to regenerate that kilogram of iron. The Reden analysis showed about 9.75 MJ input needed per 7.39 MJ output, i.e. ~76% efficient round-trip [1]. If waste heat from the reduction reactor is recovered, the efficiency can improve a few percentages. Iron’s advantage is more pronounced when considering delivery of heat: burning iron for heat is straightforward, whereas using green hydrogen for industrial heat can face 10-15% energy losses due to steam condensation and the need for high flame temperatures [1]. Thus, in delivering high-grade heat, iron fuel can be more efficient than using hydrogen directly (79% vs ~67% in one comparison) [1].
•
After combustion, the iron oxide powder must be collected and transported back to the reduction plant, creating a closed-loop supply chain. Fresh iron powder is delivered to a power plant or factory, oxidized during use, and then the rust is shipped back for “recharging.” Although the oxide is about 30% heavier than the original iron and slightly less dense (Fe₂O₃ at ~5.2 g/cc vs. iron at 7.9 g/cc), it is a granular solid that can be shipped in hoppers or big bags.
6.5 TRANSPORT, HANDLING, AND INFRASTRUCTURE COMPATIBILITY
Iron as an energy carrier requires dedicated logistics, but it can largely leverage existing infrastructure used for solid fuels and industrial materials.
Transport and Distribution: Iron powder can be transported via standard bulk methods— rail, truck, barge, or ship—without the need for pressurized or cryogenic containers. Unlike hydrogen, iron powder travels at ambient conditions, similar to coal or ore. Due to its high density, transport is weight-limited, not volume-limited, offering far higher energy content per shipment than liquid hydrogen or ammonia. Locally, silo trucks like those used for cement can deliver iron powder to end-users. At sites, it can be stored in silos or bins, provided it’s kept dry to prevent oxidation or clumping. Minor oxidation during storage slightly reduces usable energy but can be reversed in the next cycle.
Handling and Safety: Handling iron powder is comparable to other fine powders. It can pose dust explosion risks when airborne, so facilities must ensure ventilation, remove ignition sources, and follow dust safety standards. However, unlike hydrogen, iron powder does not leak or form invisible explosive clouds. It does not ignite spontaneously under normal conditions and is commonly handled in open air in industries like metallurgy.
Storage and Infrastructure Integration: Iron powder offers long-term, loss-free storage in simple containers—no boil-off or degradation. Existing coal infrastructure can often be repurposed. For example, a NASA study showed an 800 MW coal plant could be retrofitted for iron fuel with modifications to feed systems and filters [10]. Industrial boilers and district heating can also adopt iron burners, as shown in Dutch pilot heating 500 homes [9].
Global Integration: Iron powder can be shipped internationally, with the oxidized return load (about 30% heavier) offset by efficient return logistics. The full cycle— renewable reduction, transport, combustion, oxide return—forms a circular, scalable, and infrastructure-compatible energy system.
6.6 CASE STUDIES AND PILOT PROJECTS IN THE NETHERLANDS AND EU
In recent years, iron as a fuel has advanced from lab research to pilot projects—especially in the Netherlands, where academic and industry partners are driving "Iron Power" development. Key developments include:
• TU Eindhoven & Team SOLID: Starting around 2015, a student-driven team (Team SOLID) and researchers at TU/e began working on iron fuel combustion and recycling. They built small burners to burn iron powder and proved that a stable flame and heat generation is possible [2]. By 2018–2019, researchers demonstrated a lab-
scale iron fuel cycle: iron powder was burned to produce steam, and the resulting rust was reduced back to iron using hydrogen. Inspired by earlier work from Jeffrey Bergthorson’s team at McGill University [2], the Eindhoven group brought the metal fuel concept into practical application with iron.
• Swinkels Brewery Pilot (2020): In 2020, the Metal Power Consortium—TU Eindhoven, Team SOLID, and industry partners—installed a 100 kW iron-fuelled boiler at the Royal Swinkels Brewery in the Netherlands [3]. The system supplied all the heat needed to brew 15 million glasses of beer. The resulting rust was collected and later reduced back to iron, demonstrating a closed-loop fuel cycle.
• RIFT (2022–2023): RIFT, in partnership with Ennatuurlijk, is building a 1 MW iron powder boiler in Helmond, to heat around 500 households, replacing natural gas [9]. A rust reduction facility in Arnhem will regenerate the iron powder, completing the first full-scale iron fuel cycle. Backed by Dutch and EU innovation programs, the pilot demonstrates iron fuel’s potential for industrial heat where electrification is difficult [11].
• Metalot: Metalot, a Dutch consortium and community focused on metal energy, has been actively exploring and promoting iron fuel in the energy transition. A 2024 study by Metalot, TNO, and Roland Berger found iron powder to be a strong candidate for high-temperature industry and long-distance energy transport [4]. The study projects that by 2030, iron fuel could offer 80–90% cycle efficiency and competitive costs in specific niches, driven by its high volumetric energy density and favourable safety profile [4].
(Photo: TU Eindhoven/Team
• At the EU level, there is currently no large-scale, dedicated research program for iron fuel, but industrial interest is increasing, with companies in the steel and power sectors exploring how to repurpose existing infrastructure for iron combustion. One notable example is the German-Namibian HyIron20 initiative, which is pioneering the production of green iron using renewable hydrogen. Located in Namibia, the project aims to produce DRI, serving both as a clean input for steelmaking and as a potential energy carrier.
Figure 15 100 kW iron-fuelled steam system at Swinkels Brewery (NL). Iron powder from the conical hopper feeds into the insulated combustor, where it burns to generate brewing heat [3].
SOLID)
Challenges and Outlook: While early case studies are promising, several challenges remain. The cost of producing iron via green hydrogen is currently high, driven by electrolyser and renewable electricity prices—though expected to fall as the hydrogen economy matures. Iron fuel systems also involve capital investment for combustion and regeneration equipment, and their competitiveness versus batteries or hydrogen boilers depends on scale and application. Pilot projects are key to solving practical issues, such as optimizing particle size for combustion and reduction, avoiding inactive buildup over multiple cycles, and managing logistics for a steady supply of reduced iron and oxide collection. Encouragingly, Team SOLID showed that iron oxide from brewery trials could be fully reduced and reused without performance loss [9]. With strong technical expertise and supportive policy, the Netherlands is well-positioned to lead further demonstrations and scale-up efforts for iron fuel systems.
6.7 CONCLUSION
Iron can act as a solid, carbon-free energy carrier: renewable electricity reduces iron oxide to metal; burning the metal later re-oxidises it and releases high-grade heat. This cycle stores energy densely and safely, making iron attractive for industrial furnaces, peak-power units, and long-distance energy transport where batteries or gaseous fuels struggle. Dutch pilots have already proven the concept, and research is now focused on scaling the regeneration step, organising oxide return logistics, and ensuring particles remain durable. Iron will not replace hydrogen, ammonia, or methanol but will complement them by filling its own niche - leveraging one of industry’s most abundant, recyclable materials.
6.8 REFERENCES
1. Reden B.V. (2023). “Power from Powder: Is Iron the new Hydrogen?” Reden Technical Blog, May 2023. [Power from Powder: is Iron the new Hydrogen? | Reden]
2. Bergthorson, J.M., et al. (2015). Direct combustion of recyclable metal fuels for zero-carbon heat and power. Applied Energy, 160, 368–382. [Metal makes for promising, recyclable alternative to fossil fuels - McGill Reporter]
3. New Atlas (2020). “World first: Dutch brewery burns iron as a clean, recyclable fuel.” New Atlas, Oct 30, 2020. [World first: Dutch brewery burns iron as a clean, recyclable fuel]
4. Metalot (2024). “The Potential of Iron Power Technology in the Energy Transition.” Metalot White Paper, 40 pp. [https://www.metalot.nl/pdf/2024thepotentialofironpowermin.pdf]
5. Brainly. (n.d.). Iron reacts with steam to form hydrogen gas and the oxide Fe₃O₄. Brainly. [https:// brainly.com/question/37996914]
6. Hacker, V., Fankhauser, R., Faleschini, G., Fuchs, H., Friedrich, K., Muhr, M., & Kordesch, K. (2000). Hydrogen production by steam–iron process. Journal of Power Sources, 86(1-2), 531–535. [https:// doi.org/10.1016/S0378-7753(99)00458-9]
7. Steiner, T., von Berg, L., Anca-Couce, A., & Schulze, K. (2024) On the applicability of iron-based oxygen carriers and biomass-based syngas for chemical looping hydrogen production. Energy & Fuels, 38(18), 17901–17916. [https://doi.org/10.1021/acs.energyfuels.4c03137]
8. Tang, Q., Ma, Y., & Huang, K. (2021). Fe₃O₄/ZrO₂ composite as a robust chemical looping oxygen carrier: A kinetics study on the reduction process. ACS Applied Energy Materials, 4(7), 7091–7100. [https://doi.org/10.1021/acsaem.1c01152]
9. Brainport Eindhoven (2022). “500 households are warm thanks to ‘rechargeable’ iron powder.” Brainport News, Dec 6, 2022. [500 households are warm thanks to ‘rechargeable’ iron powder]
10. Gaughan, K., Flagg, H., Osurman, E., & Ramoska, M. (2023). Iron powder as a clean aviation fuel source. Boston University. [https://blueskies.nianet.org/wp-content/uploads/2023-Blue-SkiesFinal-Research-Paper-Boston-University-Iron.pdf]
Comparative Analysis of Renewable Energy Carriers in Integrated Low-Carbon Energy Systems
7.1 ENERGY CARRIERS AT A GLANCE
The transition to sustainable energy is accelerating demand for RECs that can store and transport energy from intermittent sources—like wind and solar—to where and when it’s needed. This chapter compares five prominent carriers, evaluating their performance across key criteria: energy density, conversion efficiency, handling, safety, and infrastructure compatibility. To provide a quick overview, Table 1 summarizes the core metrics of each carrier. This is followed by a detailed comparative discussion to help identify which carriers are best suited for specific applications.
Table 2
Carriers
Hydrogen (H₂)
Ammonia (NH₃)
Gas (e.g. 700 bar) or liquid (–253 °C) ~120 MJ/kg
Liquid (20 °C at ~8–10 bar, or –33 °C at 1 bar)
Methanol (CH₃OH)
~4.5 MJ/L (700 bar); 8.5 MJ/L liquid
~30–40% (electricity -> H₂ -> electricity)
18.6 MJ/ kg ~12–13 MJ/L ~20–30%
SAFETY / HAZARDS
Very flammable/explosive (4–75% in air); low ignition energy; invisible flame; embrittles metals
Toxic, caustic; moderate flammability (15–28% in air); combustion can form NOx
Liquid (ambient conditions)
LOHC (e.g. toluene/ MCH)
Liquid (ambient; stored in tanks)
20.1 MJ/ kg 15.8 MJ/L
~7 MJ/kg (as H₂ content) ~5–6 MJ/L (H₂ content)
~20–30% (e to e ; carbonneutral if CO₂ sourced sustainably)
~25–30% (electricity -> H₂ -> electricity via LOHC)
Flammable liquid (flash point 11 °C); toxic if ingested; emits CO₂ when used (needs CO₂ capture for neutrality)
Combustible liquid (high boiling point -> low vapor pressure); minimal fire risk when cool; H₂ release needs 300–400 °C heat; carrier reuse entails minor losses.
Iron (Fe)
Solid powder (ambient; stored in silos)
~7 MJ/ kg (Fe -> Fe₂O₃) ~25 MJ/L
~20% (electricity -> Fe -> electricity; ~80% if used as heat)
Inert when stored; no toxic fumes; fine powder can combust or cause dust explosions if dispersed in air; high temp (~2000 °C) combustion
Energy Density and Storage Characteristics: H₂ has the highest gravimetric energy among these carriers, at around 120 MJ/kg [1]. Despite this, it has very low volumetric density: even at 700 bar, hydrogen only reaches about 4–5 MJ/L, and as a cryogenic liquid (at –253 °C), ~8–9 MJ/L. Ammonia carries roughly 18–20 MJ/kg (LHV) and 12–13 MJ/L in liquid form, making it denser by volume. Methanol can approach 20 MJ/kg and ~16 MJ/L [2], and it remains liquid at ambient temperature. LOHCs, such as methylcyclohexane or dibenzyltoluene, physically bind hydrogen, yielding around 6 wt% hydrogen content about 5–6 MJ/L. Iron powder, though it provides only ~7 MJ/kg when fully oxidized, offers a volumetric density of ~25 MJ/L thanks to iron’s intrinsic density.
These differences in gravimetric versus volumetric energy guide each carrier’s best uses. Hydrogen is prized for mobility applications where weight is pivotal—like fuel cell vehicles—yet storing it compactly is difficult. Ammonia and methanol are liquids at far milder conditions, so they suit large-scale transport (e.g. ocean shipping) or stationary energy storage. LOHCs combine relatively low vapor pressure with safer handling, though their hydrogen content per litter is moderate. Iron is unique as a stable, non-volatile solid
with exceptionally high volumetric density, making it attractive for stationary or industrial contexts that value compact storage over low mass.
Each carrier has trade-offs—hydrogen excels in mobility, liquids in transport and storage, iron in volume-critical applications.
Conversion Efficiency and Energy Losses: Each carrier introduces specific conversion chains and associated losses. Hydrogen produced by electrolysis is ~65–75% efficient, and subsequent fuel cell usage recovers ~50–60% of that, yielding about 30–40% roundtrip electricity [3]. Liquefying hydrogen consumes another 25–30% of its energy, while compression also requires additional input. If hydrogen is burned directly or used in processes like steelmaking feedstock, efficiency can be higher since there is no reconversion penalty. Ammonia synthesis via the Haber–Bosch process can consume 12–26% of hydrogen’s energy, and cracking ammonia back to hydrogen can consume another 13–34% [4]. If ammonia is instead burned in a turbine or engine designed for NH₃, the cracking step is bypassed, raising net efficiency. Methanol faces losses in electrolysis, CO₂ capture, and conversion, plus engine or fuel cell inefficiencies. Nevertheless, methanol can be directly combusted, avoiding a separate reformation stage and enabling overall round-trip electricity of ~20–25%. The added benefit is that methanol production recycles CO₂, which can be carbon-neutral if the CO₂ source is sustainable [2].
LOHCs prioritize convenience of transport—no high-pressure tanks or cryogenics—but hydrogenation and dehydrogenation can each consume significant energy, together costing ~25–30% of the hydrogen’s value. Additional losses occur if the released hydrogen must be recompressed. Iron undergoes a redox loop. Regeneration can theoretically recover ~76–79% of input energy as usable heat, though turning that heat back to electricity is limited by turbine or engine efficiency (~20–30% round-trip). Hence, iron excels where thermal energy is directly.
Storage, Transport, and Infrastructure Compatibility: Each carrier presents distinct logistical considerations. Hydrogen requires high-pressure vessels or cryogenic tanks for transport and storage and can be stored in salt caverns or depleted gas fields. Pipelines are feasible but need materials resistant to hydrogen embrittlement. Ammonia benefits from existing fertilizer infrastructure. It is already shipped globally via tankers and pipelines. It can fuel turbines or engines with modifications to reduce NOx. Methanol is widely used in chemical industries, stored in standard tanks, and transported in chemical tankers. Though its energy density is about half that of gasoline, it integrates well with existing infrastructure and can be used in modified engines or fuel cells. LOHCs use conventional liquid logistics, but require dehydrogenation at the destination, adding complexity but avoiding pressurized transport. Iron is handled like coal—shipped via bulk carriers or trucks and stored in silos. Combustion produces recyclable iron oxide ash. The main infrastructure need is a central regeneration facility, where rust is reduced back to iron using green hydrogen or electricity.
Safety and Handling Considerations: Safety plays a key role in determining the viability of energy carriers. Hydrogen is highly flammable (4–75% in air) with low ignition energy, though its buoyancy helps disperse leaks. It's non-toxic, with fire and explosion as the main risks. Ammonia is toxic and dangerous even at moderate concentrations but has a narrower flammability range (15–28%). Its primary hazard is toxicity, requiring detection systems and strict handling procedures. Methanol is flammable and volatile and burns with near-invisible
flames. It's also toxic if ingested, but environmental impact is lower than petroleum due to its biodegradability. LOHCs have high flash points and low vapor pressure, making them safer in transit. Risks mainly arise during hydrogenation/dehydrogenation, where high temperatures and hydrogen gas are involved. Iron is non-toxic and stable in bulk, but fine iron dust can ignite if airborne. Proper dust control and sealed systems are essential. Iron combustion produces solid oxide, avoiding CO₂ and other pollutants, though some NOx may form if air is used.
No single carrier outperforms all others. Hydrogen delivers top-tier gravimetric energy but can be difficult to store densely. Ammonia and methanol are simpler to keep as liquids, supported by established chemical logistics and the possibility of direct engine use. LOHCs forego pressurization or cryogenics, offering safer transport but losing efficiency in hydrogenation cycles. Iron provides compact thermal energy storage and minimal environmental risk, well suited for HT industrial processes. In Europe—and the Netherlands in particular—these carriers may work in tandem. Hydrogen pipelines can supply urban areas or industrial hubs, while ammonia can be shipped from overseas producers with abundant renewable resources. Methanol might serve maritime or trucking applications, especially if CO₂ is captured to make it carbon neutral. LOHCs may reach remote sites lacking hydrogen pipelines. Iron could enable emission-free furnaces or power plants, integrating neatly with green steel production. Each carrier’s trade-offs—energy density, efficiency, safety, and infrastructure needs—suit different applications. A diverse mix allows Europe to store and use intermittent renewables effectively, decarbonizing various sectors. Ammonia-fuelled ships, methanol trucks, hydrogen buses, LOHC stations, and iron-powered boilers could all coexist in a robust, low-carbon energy system.
7.2 CONCLUSION
Renewable energy carriers (RECs) each offer distinct advantages. Hydrogen is flexible and carbon-free but needs major infrastructure. Ammonia and methanol simplify transport and serve specific sectors—ships, engines, and chemical feedstocks—though with efficiency and CO₂ challenges. LOHCs provide safe, oil-compatible transport, while iron enables longduration thermal storage with low leakage. No single carrier fits all needs; applications dictate use. EU and Dutch strategies already support a multi-carrier approach—hydrogen pipelines, ammonia and methanol for mobility, LOHCs for logistics, and iron for industrial heat—ensuring a resilient, low-carbon system.
7.3 REFERENCES:
1. Aziz, M., Wijayanta, A. T., & Nandiyanto, A. B. D. (2020). Ammonia as effective hydrogen storage: A review on production, storage and utilization. Energies, 13(12), 3062 [Ammonia as Effective Hydrogen Storage: A Review on Production, Storage and Utilization]
2. ICF (2023). E-methanol enables hydrogen economy, adds value to captured carbon. ICF Insights, May 2023 [E-Methanol Enables Hydrogen Economy, Adds Value to Captured Carbon | ICF]
3. Brinkert, J. (2023). Power from powder: is iron the new hydrogen? Reden B.V. (Blog), May 9, 2023 [Power from Powder: is Iron the new Hydrogen? | Reden]
4. Jason Amiri (2024). Hydrogen pipelines vs. ammonia, LOHC, liquid hydrogen – comparison post LinkedIn, July 2024 [ In this post, I compare hydrogen pipelines, ammonia, LOHC and liquid… | Jason Amiri | 50 comments]
5. Hydrogen Tech World (2024). Iron Power: enabling large-scale green energy storage using iron powder (S. van Aken, P. de Goey, & R. Voeten) July 9, 2024 [Iron Power: enabling large-scale green energy storage using iron powder]
Part IV
SYSTEM INTEGRATION AND REFINERY OF THE FUTURE
Chapter 8
Integration of Renewable Energy Carriers in Multi-Carrier Energy Systems
The decarbonization of Europe’s energy supply is driving a paradigm shift towards multicarrier energy systems that integrate various energy carriers across power, industry, and transport. In the Netherlands and the wider EU, ambitious climate targets demand not only large-scale electrification but also the deployment of renewable molecules like hydrogen, ammonia, methanol, LOHCs, and even metal fuels. These carriers can store, transport, and deliver RE in forms suitable for applications that electricity alone cannot easily serve. Integrating multiple energy vectors in a sector-coupled system enables greater flexibility and resiliency: surplus renewable electricity can be converted into chemical fuels, industrial waste heat can be reused, and fuels can be interconverted to meet dynamic demand. This chapter explores the concept of multi-carrier energy systems, with an emphasis on infrastructure integration, sector coupling, and the coordinated use of RECs within a system-of-systems framework. It examines the emerging vision of the “Refinery of the Future” as an integrated energy hub for the production and distribution of a diverse portfolio of green fuels. Additionally, case studies are presented to illustrate practical strategies and pathways toward system-wide decarbonization.
8.1 MULTI-CARRIER ENERGY SYSTEMS AND SECTOR COUPLING
A multi-carrier energy system is an energy network where multiple energy carriers (electricity, gases, liquids, heat, etc.) are interconnected and jointly managed. Unlike traditional siloed energy systems, a multi-carrier system allows sector coupling – the deliberate linking of previously separate sectors like power, transportation, heating, and industry. The European Union’s vision for an integrated energy system emphasizes “interlinkage of various energy carriers – not just electricity and gas but also heat, cold, and solid and liquid fuels – across end-use sectors” [1].
By connecting energy vectors, sector coupling enables renewable energy to flow where it’s needed in the form that is most efficient. For example, renewable electricity can produce hydrogen via electrolysis, which can then fuel industrial processes or transport, effectively extending the reach of renewable power into sectors hard to electrify. Conversely, that hydrogen can be converted back to electricity in a fuel cell or turbine to provide power during periods of low renewable generation.
Figure 16 Comparison of linear (one-directional) energy flows in today’s system versus an integrated energy system of the future that reduces waste and encourages multi-directional resource sharing [1]
Benefits of Multi-Carrier Integration
A well-integrated multi-carrier system can yield several advantages:
• Maximize Renewable Utilization: Variable renewable energy sources (VRES) like wind and solar can be more fully utilized by converting excess power into storable fuels (Power-to-X). This “decouples VRES production from demand” and bolsters energy security.
• Flexibility & Resilience: Different energy carriers provide complementary forms of flexibility. For instance, hydrogen infrastructure adds seasonal storage and backup capacity to a grid dominated by renewables. This reduces reliance on any single energy grid. A multi-modal energy system that combines electricity grids with molecule transport (pipelines, tanks) can be more reliable and cost-effective than an all-electrified system.
• Diversified Infrastructure & Investment: Sector coupling encourages using existing assets in new ways (e.g. repurposing natural gas pipelines for hydrogen) and diversifying investments across energy carriers, thereby “derisking and diversifying investments”. By avoiding an “all eggs in one basket” approach, the energy transition can leverage the most efficient carrier for each application and mitigate bottlenecks in any single network.
• Deep Decarbonization of All Sectors: Crucially, multi-carrier systems enable decarbonization beyond the power sector. Renewable hydrogen or derived fuels can supply HT industrial heat, serve as feedstocks, and fuel long-distance transport – roles that pure electrification struggles with. This system integration means end-use sectors like heavy industry, shipping, and aviation can be linked to clean energy sources, closing the loop on economy-wide emissions.
As discussed in the previous chapter, multiple renewable energy carriers are poised to play complementary roles in a coupled, multi-vector energy system. These carriers differ in terms of energy density, conversion pathways, and end-use applications. Table 3 summarizes their key use cases and roles within the integrated energy system.
Table 3 Renewable Energy Carriers and Their Roles in an Integrated Multi-Carrier Energy System
ENERGY CARRIER
Hydrogen (H₂)
Ammonia (NH₃)
Methanol (CH₃OH)
LOHC
Iron Powder (Fe)
Feedstock for chemicals; Fuel for fuel-cell vehicles; Power generation; Heating
Hydrogen carrier for transport/import; Carbon-free fuel for shipping and power; Fertilizer
Liquid fuel for transport; Chemical feedstock
Long-distance hydrogen transport via tankers or trucks; Storage at distribution hubs (“liquid battery” for H₂)
Thermal heat source for industry or district heating; Long-term energy storage in solid form
Flexible energy vector for transport, industry, and storage; key for sector coupling
Efficient hydrogen carrier for import/ export and maritime fuel; supports hydrogen integration
Carbon-neutral liquid fuel and feedstock; links GH₂ to existing fuel and chemical infrastructure
Bridges hydrogen transport gaps; enables decentralized H₂ delivery where pipelines are unavailable
Stationary, high-density heat carrier; supports long-term storage and integration with industrial systems
In brief, sector coupling with multiple energy carriers supports a more flexible and integrated energy system. Hydrogen plays a central role as a versatile vector connecting supply and demand across sectors. It is seen as a key enabler of cross-sectoral decarbonization, complementing electrification [1].
8.2 INFRASTRUCTURE INTEGRATION ACROSS CARRIERS
Realizing a multi-carrier energy system requires transforming and expanding infrastructure to handle new vectors. In the Netherlands and EU, this means repurposing parts of the existing gas network for hydrogen, building new transport and storage facilities for hydrogen and its derivatives, and integrating these with the power grid and industrial infrastructure. Integrated infrastructure planning is now a focus of policy: the EU’s Strategy for Energy System Integration calls for “system planning [that] tackles how to couple clean electricity and gas… and on the end-use side link them to consumption sectors” [1]. In practice, this translates to projects like hydrogen pipelines connecting windrich regions to industrial clusters, port terminals that can import ammonia or LOHC and distribute hydrogen, and co-location of renewable generation with Power-to-X plants.
One of the flagship initiatives is the development of a European Hydrogen Backbone – a continental network of hydrogen pipelines. Europe’s gas transmission operators have proposed a backbone of about 50,000–53,000 km of pipelines by 2040, largely by repurposing existing natural gas pipes for hydrogen and building new links where needed [2]. Figure 18 shows a map of Europe with envisioned hydrogen corridors. The backbone design connects production centres (e.g. North Sea offshore wind hubs, solar regions in Spain or North Africa via imports) with demand centres in industry-heavy regions (the Ruhr in Germany, ports like Rotterdam and Antwerp, etc.) [2]. The backbone concept promises a “multi-modal energy system” where parallel networks – electricity grids and hydrogen pipelines – work in concert to transport energy efficiently.
18 Europe’s Hydrogen Pipeline Backbone vision for 2040: (The Netherlands is highlighted as planning a hydrogen-ready grid by 2027 and partnering on offshore energy hubs with Germany [7]
Figure
The Netherlands is at the forefront of hydrogen infrastructure planning. State gas grid operator Gasunie has been tasked with developing a national hydrogen network by 2030, connecting the major industrial clusters (the ports of Rotterdam and Amsterdam, the Chemelot site in Limburg, the Groningen northern region, and cross-border links to Germany and Belgium). Construction has already begun in October 2023, the Netherlands launched the first 30 km segment of this hydrogen pipeline network in the Rotterdam port area, aiming to have it operational by 2025 [3]. The full Dutch hydrogen backbone will span ~1,200 km and is projected to consist largely of repurposed natural gas pipelines, keeping costs low and reusing rights-of-way [4]. By 2033, this network is expected to be fully in place [5], effectively making hydrogen available as a nationwide energy carrier. Crucially, the Dutch network will connect to the wider European backbone – with pipelines planned from Rotterdam towards Germany’s Rhineland and from the northern Netherlands towards North Rhine-Westphalia – facilitating an integrated Northwest European hydrogen market. This integration is backed by regulation: the EU’s Hydrogen and Decarbonized Gas Market Regulation mandates open access and interoperability for hydrogen pipelines, with unbundling rules aligned to those of gas networks [6].
The Dutch network will connect with Germany and Belgium, supporting an integrated Northwest European hydrogen market.
In addition to pipelines, port infrastructure is a vital piece of the multi-carrier system. The PoR, as Europe’s largest seaport and energy hub, has declared its ambition to be “Europe’s Hydrogen Hub”, with plans to handle 4.6 million tonnes of hydrogen by 2030 and up to 20 million tonnes by 2050. Because domestic production will not suffice, “90% of future green hydrogen volumes need to be imported” into the Netherlands [8]. Rotterdam is therefore developing multiple import pathways: direct imports of LH₂, and imports of hydrogen carried in other forms. Various terminals in Rotterdam’s Maasvlakte and Europoort areas are being repurposed or built to accommodate these carriers. For example, the ACE Terminal will import green ammonia and crack it to hydrogen, with an announced capacity of 1 million tonnes of H₂ per year in the long term [9];[10]. OCI Global is tripling its ammonia import capacity at Rotterdam to 1.2 million tons per year by 2023 to supply feedstock and future energy needs [11]. For LH2, pilot shipments are being considered, although handling LH₂ at scale is technically challenging. The port is also collaborating internationally – e.g. with locations like Oman, Australia, Namibia – to secure hydrogen supply chains, often in the form of ammonia or LOHC for transport [8].
Storage infrastructure is another consideration. For electricity, short-term storage is done via batteries, but multi-carrier systems enable chemical energy storage on a large scale. In the EU, salt caverns are being repurposed or developed to store hydrogen gas (such as in Groningen, NL, and in Germany and the UK), providing massive buffering capacity for seasonal shifts. Ammonia storage tanks can serve as medium-term storage for energy imports or for domestic green ammonia production. Even underground storage of hydrogen in aquifers or depleted gas fields is being researched [12]. Thus, the future system may have a layered storage approach: batteries and supercapacitors for intra-day grid balancing, hydrogen (in tanks, pipes, caverns) for inter-day and seasonal storage, and solid fuels like iron or other chemical stocks for strategic reserves or niche uses. Integrating the management of these storage assets will be key to optimizing the overall system.
8.3 SECTOR COUPLING APPLICATIONS
Effective integration of renewable carriers means each sector can draw on the energy vector best suited to its needs, while also contributing services back to the system. Below we examine how sector coupling manifests in the power, industry, and transport sectors under a multi-carrier framework.
Power Sector Integration
In a deeply decarbonized grid, power-to-gas and gas-to-power become key complements to renewable generation. When wind and solar exceed demand, converting electricity into chemical carriers like hydrogen prevents curtailment. The Netherlands anticipates large-scale electrolysis capacity, with 3-4 GW planned by 2030 in the North Sea region. These electrolysers serve as flexible loads, stabilizing the grid and producing hydrogen for other sectors. Conversely, during low renewable output or peak demand, stored hydrogen or ammonia can be reconverted to electricity via fuel cells or gas turbines, providing dispatchable power. Hydrogen-capable turbines are under testing, and ammoniafired turbines are being developed in Europe and Japan—relevant for countries like the Netherlands that plan to import ammonia. This forms a renewable energy storage loop: excess power -> hydrogen -> power when needed. It mitigates intermittency and supports the broader view that “hydrogen will provide the flexibility needed to a power system dominated by electrification and variable renewables.”
Industrial Sector Integration
Industry, especially heavy industry (steel, chemicals, cement, refining), is a cornerstone of multi-carrier integration because it can both consume and supply energy carriers. On the consumption side, industries need high-temperature heat and chemical feedstocks, which electricity often cannot provide directly. Renewable hydrogen is poised to replace fossil fuels in several processes: iron and steelmaking can use hydrogen instead of coal for ore reduction. Ammonia itself is a chemical industry product, and moving to green ammonia directly decarbonizes that sector – the EU’s 32 ammonia plants [13] could gradually be fed with green hydrogen or retrofitted with CCS to become low-carbon, turning a previously emissions-intensive sector into part of the clean energy value chain. Hydrogen can also provide high-temperature heat for cement or glass production.
The ‘Refinery of the Future’ will convert renewable inputs—water, air/CO₂, biomass—into fuels like hydrogen, ammonia, methanol, and e-kerosene.
Industrial sites often act as energy hubs in their regions: they might import fuels, generate byproducts, and have co-located power generation. In a multi-carrier system, an industrial cluster (like the Rotterdam port area or Chemelot) could incorporate electrolysis units, hydrogen storage, and even synthesis units to produce fuels like methanol or SAF using captured CO₂. The concept of the “Refinery of the Future” embodies this integration: instead of refining crude oil, future refineries will refine renewable inputs (water, air/ CO₂, biomass) into a spectrum of products – hydrogen, ammonia, e-methanol, synthetic hydrocarbons, and electricity – depending on demand. These e-refineries could also capture and recycle carbon on-site [14]. Realizing such visions will require close coupling of industrial processes with energy supply.
It also requires industries to provide flexibility services: an electrolyser at a chemical plant can ramp down if the power grid is strained, or conversely an industrial gas turbine could ramp up on hydrogen to supply peak power to the grid. Industrial demand response using multi-fuel capability (e.g. a kiln that can switch between gas, hydrogen, or electric heating) is another way coupling can improve overall system balance. Moreover, industries can contribute by utilizing waste streams. Excess oxygen from electrolysis can be used in industrial furnaces or wastewater treatment; waste heat from exothermic reactions (like methanation reactors) can feed district heating networks. In Rotterdam, for instance, the WarmtelinQ19 project is capturing industrial residual heat to heat buildings. In the future, if a “power-to-X” plant produces synthetic fuel and generates low-grade heat, that too could be piped to nearby users, improving efficiency. In brief, the industrial sector becomes a balancing node: taking in renewable carriers as inputs, and outputting both products and services that support the wider energy system.
Transport Sector Integration
The transport sector—including road, maritime, and aviation—is undergoing a major transition, with multiple energy carriers expected to coexist. While electrification will dominate light-duty vehicles, heavy-duty, long-range, and marine transport require energy-dense fuels. Here, renewable hydrogen and its derivatives bridge the power and mobility sectors.
In the Netherlands and EU, hydrogen mobility is advancing. Fuel cell buses and trucks are being deployed supported by the Alternative Fuels Infrastructure Regulation20, which mandates hydrogen refuelling stations along key routes. This chain—renewable electricity -> hydrogen -> refuelling -> zero-emission transport—demonstrates sector coupling Though reverse power flow via fuel cells is rare, future technologies may enable vehicleto-grid services.
For maritime transport, major ports like Rotterdam are preparing for ammonia and methanol as alternative marine fuels. EU policies (e.g., FuelEU Maritime) and IMO targets are accelerating the shift. Maersk’s methanol-powered ships and growing interest in ammonia engines reflect the momentum [15]. Dutch initiatives are leading in ammonia safety and bunkering pilots, linking offshore renewables to clean propulsion. Import terminals could serve ships, industry, and power plants, showcasing cross-sector integration.
Aviation poses unique challenges due to energy density needs. Options like synthetic kerosene or bio-based jet fuels are emerging. Airports such as Schiphol and Rotterdam are exploring hydrogen and e-fuels for short- and long-haul flights. These developments align with the “refinery of the future”, where fuel production is integrated with broader energy systems.
Airports like Schiphol and Rotterdam are exploring hydrogen and e-fuels for both short- and long-haul flights.
Finally, rail and pipelines play a role in energy transport. Hydrogen pipelines may support both supply and hydrogen-powered trains in non-electrified regions. The EU’s TEN-E policy now includes smart gas and hydrogen networks—reinforcing the vision of an integrated infrastructure serving energy and mobility together.
Overall, decarbonizing transport is closely tied to multi-carrier energy systems, with vehicles and vessels using hydrogen, ammonia, and methanol from renewables. This sector coupling cuts emissions while lifting demand and scaling up production and infrastructure.
8.4 POLICY STRATEGIES AND PLANNING
Integrating diverse energy carriers into a cohesive system requires supportive policy and strategic planning at both national and EU levels. The EU has enacted several strategies and funding mechanisms to accelerate this multi-vector integration:
• EU Energy System Integration Strategy: Promotes cross-sector integration by removing regulatory barriers between electricity, gas, and heat, and aligning infrastructure planning. Complemented by the Hydrogen Strategy (2020), it targets 10 Mt of green hydrogen production by 2030, positioning hydrogen as a key enabler for integrating renewables into industry and transport.
• REPowerEU: In response to energy security concerns, REPowerEU raised the EU’s 2030 ambition to include 10 million tonnes of additional green hydrogen imports, alongside domestic production [2]. It prioritizes fast-tracking infrastructure such as the hydrogen backbone and import terminals. This has led to accelerated timelines—for instance, advancing the European Hydrogen Backbone corridors from 2035 to 2030. REPowerEU also supports hydrogen projects via the Innovation Fund and urges member states to incorporate hydrogen in their National Energy and Climate Plans.
• National Strategies: The Dutch government has taken a proactive role in hydrogen development. The Climate Agreement (2019) and National Hydrogen Strategy (2020) outline targets for 3–4 GW of electrolysis by 2030 and the establishment of a hydrogen backbone via Gasunie. Hydrogen is a Growth Fund priority, with cofunding for electrolysers, infrastructure, and port hubs. Dutch policy promotes sector coupling, notably in the Offshore Wind Energy Roadmap21, which links offshore wind with hydrogen production (“Wind meets Hydrogen”). The Rotterdam Hydrogen Hub vision is backed by local and national support, streamlined regulation for pilots, and cross-border coordination with Germany (e.g. Delta Corridor pipelines to North RhineWestphalia).
• Sector-Specific Policies: Integration is also driven by sector-specific regulations that indirectly promote coupling. The EU ETS makes fossil-based industrial processes more expensive, incentivizing a shift to green hydrogen and linking the power and industrial sectors. CO₂ performance standards in the automotive sector promote electrification and hydrogen vehicles, while the Renewable Energy Directives II and III set binding targets for renewables in transport, including e-fuels and renewable fuels of nonbiological origin, stimulating cross-sector investment. In the Netherlands, potential blending mandates for green hydrogen in gas networks or renewable gas quotas for industry could further accelerate integration.
In essence, policy is moving from a siloed approach to a holistic one: infrastructure planning is increasingly integrated (electric + gas + hydrogen), funding is directed at hubs and clusters rather than single-technology projects, and regulations are being updated to allow new carriers to enter markets. The alignment of policies from EU to local level, along with PPPs, is creating a favourable landscape for multi-carrier energy systems to materialize.
8.5 INTEGRATION CHALLENGES AND ENABLERS
While the vision of an integrated multi-carrier energy system is compelling, realizing it presents significant challenges. Achieving this vision requires coordinated efforts in technology development, standardization, market design, and international collaboration. The following outlines key barriers and potential strategies to address them.
• Standardization and Safety: Large-scale use of new fuels requires robust, harmonized standards to ensure safety and interoperability. Each carrier presents unique risks: hydrogen is highly diffusive and can cause pipeline embrittlement; ammonia is toxic; methanol is flammable and toxic if ingested; LOHCs involve high-temperature catalytic processes; and iron powder must be handled to prevent dust ignition and oxidation. Efforts are underway to address these challenges. In 2023, the Netherlands updated its PGS-12 guidelines to regulate ammonia storage and distribution in anticipation of rising imports [12]. International bodies like ISO and IMO are also advancing standards: ISO is working on hydrogen fuel quality and refuelling protocols (e.g., nozzle designs, pressure levels), while the IMO is developing regulations for alternative marine fuels.
• Interoperability and Infrastructure Coordination: Integrating multiple energy carriers requires aligning both physical and digital infrastructure. Physically, pipelines and terminals must be interoperable—e.g., standardized pressures, hydrogen-compatible compressors, and ports that connect seamlessly to inland networks. Digitally, energy management systems must coordinate across vectors, enabling operators to manage both electricity and hydrogen grids—deciding, for example, when to run electrolysers or draw from hydrogen storage. Advanced platforms that integrate electricity and gas SCADA systems will be key. EU projects like MAGNITUDE and eNeuron have explored such multi-vector coordination, including shared optimization tools and control algorithms [17];[18]. Another critical area is market interoperability. Today’s separate electricity and gas markets may evolve into hybrid models offering green flexibility services, where industrial users switch between power and hydrogen based on dynamic pricing. Regulatory alignment is also essential. Bodies like ACER and national regulators are beginning to address this, including efforts to synchronize investment planning across electricity, gas, and hydrogen systems—such as aligning TYNDPs (Ten-Year Network Development Plans) [19];[20].
• Economic and System Optimization: Determining the optimal mix of energy carriers is a complex techno-economic challenge, balancing risks of over- or under-investment in infrastructure. Planners must account for uncertainty—e.g., the future role of hydrogen vs. electrification in heating, or breakthroughs in battery storage. Scenario analysis and optimization models help guide these decisions. For instance, the ENTSO-E and ENTSOG joint scenario report for TYNDP 2022 integrated electricity, gas, and hydrogen planning, including power-to-gas pathways. Tools from operations research are being used to identify least-cost infrastructure combinations—such as optimal electrolyser vs. battery capacity [21]. Real-time system optimization adds another layer of complexity, requiring advanced algorithms to manage multi-vector dispatch, far beyond traditional grid management. Advances in computing and AI are making this increasingly feasible [22].
• Financial and Market Viability: Building new infrastructure for hydrogen and other carriers requires significant investment—e.g., the European Hydrogen Backbone is projected to cost €80–143 billion by 2040 [2]. Realizing such projects depends on clear business models. Currently, many rely on public funding (e.g., IPCEIs, Horizon Europe), but long-term viability requires functioning markets with robust pricing mechanisms and risk-sharing frameworks. Instruments like carbon contracts for difference—piloted for green steel and chemicals—can guarantee returns by bridging cost gaps between fossil and green options, making investments bankable.
The trajectory in the EU and Netherlands is clear: by anticipating these challenges and proactively working on them, the region aims to make the transition to a multi-carrier energy system not only technically feasible but smooth and economically efficient.
8.6 EXAMPLES IN THE EU AND NETHERLANDS
Concrete examples of multi-carrier integration are beginning to emerge, offering learning opportunities for wider rollout. Here we highlight a few representative case studies and strategic projects:
• HEAVENN (Northern Netherlands Hydrogen Valley): The HEAVENN project in Groningen/Drenthe is one of Europe’s first hydrogen valley demonstrators, representing an integrated approach. Launched in 2020, HEAVENN is creating a “fully functioning green hydrogen chain in the Northern Netherlands”, tying together production, storage, distribution, and end-use across six locations [22]. This includes a 20 MW electrolyser in the Eemshaven wind hub, underground hydrogen storage in a salt cavern at Zuidwending, pipelines connecting an industrial chemical park in Delfzijl, and multiple end-uses: hydrogen fuelling stations for buses and trucks, hydrogen boilers for residential districts, and H₂ supply for methanol production at Emmen. The project consortium spans gas infrastructure companies (Gasunie), industry (chemicals, logistics), local governments, and international partners [22]. By coordinating these elements, HEAVENN serves as a blueprint for hydrogen-based multi-carrier systems, demonstrating how regional surplus renewable power can be converted to hydrogen, stored, and utilized in various sectors locally [22]. It also highlights the importance of policy support and public engagement: the project has strong backing from provincial authorities and won the EU Hydrogen Valley of the Year award [23].
• PoR: Multi-Modal Energy Hub: Rotterdam is not just planning but actively transforming into a multi-vector energy hub. We discussed infrastructure in previous sections; here we consider the strategic vision. The PoR Authority’s program “Rotterdam, Europe's Hydrogen Hub” entails multiple integrated projects: (1) H-vision: a project to produce low-carbon hydrogen from refinery gas with CCS to supply local industry; (2) Import partnerships – e.g., with Morocco and Australia – where green ammonia or hydrogen will flow into Rotterdam, get distributed to industrial clients or converted to power. (3) Sector coupling within the port: Companies like Shell are building a 200 MW electrolyser (the Holland Hydrogen I project) that will use offshore wind power to produce hydrogen for Shell’s Pernis refinery and for trucking fuel. This links the electricity from North Sea wind, via hydrogen, to both industry and mobility. (4) Refinery of the Future concept at Maasvlakte: there is a vision to cluster new PtX facilities at Maasvlakte 2 – for example, converting imported green methanol into products or blending bio and synthetic fuels. Also, projects like Circular Rotterdam22
plan to use waste CO₂ from industry for synthetic fuel production. The Port’s Energy Transition coordinates these efforts, ensuring that decisions on (for instance) where to place a new ammonia cracker consider proximity to hydrogen pipelines and industrial customers.
• North Sea Wind Power & Hydrogen Hubs: The North Sea is set to become a multicarrier hub: projects such as Denmark’s Bornholm Energy Island and the NetherlandsGermany North Sea Wind Power Hub will gather massive offshore wind, sending electricity ashore by cable while converting surplus into hydrogen via platform-based electrolysers and pipelines. The Netherlands plans a 100 MW offshore electrolyser pilot on a repurposed gas platform by the late 2020s—a proving ground for using legacy infrastructure to deliver green H₂ to coastal industry. If successful, these initiatives could scale into full international hydrogen‐at-sea networks during the 2030s.
These pilots show that building a multi-carrier system requires tight cross-sector cooperation. Hydrogen Valleys bring together local governments, utilities, industry, and residents; ports align terminal operators, fuel producers, and TSOs; city projects merge electricity, gas, and heat grids; and the North Sea hub links nations and their power-gas systems. Each effort de-risks technology and business models - Groningen’s H₂ homeheating trial refined pipeline materials and sensors, while Rotterdam’s ammonia-andhydrogen import deals are shaping future trading rules -collectively laying a scalable template for region-specific, multi-carrier energy networks.
8.7 THE "REFINERY OF THE FUTURE": A VISION FOR SYSTEMIC INTEGRATION
Tying all the threads together is the concept of the “Refinery of the Future.” This term encapsulates the idea of a highly integrated energy and chemical complex that processes renewable inputs into a suite of outputs needed for a net-zero economy – essentially functioning as a multi-energy hub. In contrast to a traditional oil refinery (which takes crude oil and outputs fuels and chemicals), the future refinery would take in resources such as renewable electricity, water, captured CO₂, sustainable biomass, and perhaps nitrogen from air – and output hydrogen, green ammonia, e-methanol, synthetic hydrocarbons, and even electricity or heat for the grid as needed. It is an embodiment of a multi-carrier energy system at the facility scale.
In the Netherlands, with its large refining and petrochemical sector, this vision is particularly relevant. Companies like Shell, BP, and Dow are exploring how their facilities can evolve. For example, Shell’s Energy and Chemicals Park Rotterdam (formerly Pernis refinery) is shifting to produce more biofuels and plans to use green hydrogen instead of grey hydrogen in its processes. One can imagine by 2030–2040, such a site could host a cluster of Power-to-X plants: units producing ammonia, methanol, synthetic jet fuel, etc., using hydrogen from gigawatt-scale electrolysis. The integration aspect is crucial –these processes share intermediate streams (hydrogen, oxygen, CO₂) and utilities (steam, cooling). The refinery of the future will optimize flows such that, for instance, the oxygen from water electrolysis could be fed into a waste-to-methanol plant’s gasifier to improve efficiency, or the byproduct heat from a Fischer-Tropsch synthetic fuel reactor could drive a steam turbine for power. This mirrors the integration inside today’s refineries, but with all-carbon-free processes.
Professor Atsushi Urakawa of TU Delft described realizing this future refinery will require aligning technology, policy, and economics: “fascinating new technologies” like efficient CO₂-to-methanol catalysis are emerging, but “we also need political support, the right policies – like a carbon tax and accommodating definition of green fuels – and economics to make sense” [14]
The “refinery” metaphor also implies centralization, but in practice these integrations can happen in clusters of smaller plants networked together. For instance, one company might make hydrogen and oxygen, another captures CO₂, a third makes methanol using those inputs, and a fourth blends the methanol into gasoline for distribution – collectively they form a virtual e-refinery. The PoR’s vision essentially sees the whole port as one large refinery of the future, where different terminals and plants collaborate in a symbiotic way (one’s waste is another’s feedstock, etc.). Digitalization (Industry 4.0 concepts) will be a key enabler to manage such complexity.
Crucially, the refinery of the future is not only about fuels. It will continue to supply the petrochemicals and materials society needs (plastics, lubricants, etc.) but made in a circular or CO₂-free way. Some outputs will be familiar (gasoline-type fuels, ammonia for fertilizer) but with a near-zero carbon footprint; others might be new (like solid carbon or carbon fibres, if CO₂ is electrochemically reduced to carbon for materials). The point is that by integrating multiple energy and material flows, the system can achieve efficiencies and emissions reductions impossible in isolated setups. If excess renewable power is available, the complex can ramp up hydrogen production and produce more e-fuel; if power is scarce, it can throttle down and perhaps use stored ammonia to run a gas turbine to keep critical processes running – a level of flexibility current refineries does not have.
In Europe, early examples of integration include Norway’s green industrial hubs, Sweden’s LH2 steel–chemical coupling, and Groningen’s ARC Chemport linking biochemistry and hydrogen. These are stepping stones toward mid-century, when major clusters like Ruhr and Rotterdam-Antwerp may function as fully integrated energy–chemical hubs—the refineries of the future in action.
8.8 CONCLUSION
The integration of RECs in multi-carrier energy systems is a cornerstone for a lowcarbon, secure, and flexible energy future in the Netherlands and the EU. By coupling electricity, gases, liquids, and even solid fuels, synergies are unlocked that allow deep decarbonization across all sectors. Dutch and European experiences—from hydrogen valleys to port hubs and cross-border pipelines—demonstrate both the feasibility and value of such integration. Infrastructure is evolving into an interconnected network that delivers electrons where sufficient and molecules where needed, supported by evolving policies and market frameworks.
Ongoing projects are just the beginning of a new energy paradigm. Challenges of scaleup, standardization, and market creation will require continued innovation and cooperation. The vision is clear: a wind farm feeds an electrolyser producing hydrogen, which travels via pipeline to a steel mill to make green steel; its process heat warms homes via district heating, and its byproduct oxygen supports sustainable fuel production for ships and planes. The “Refinery of the Future” showcases this approach, maximizing resource efficiency and minimizing emissions.
8.9 REFERENCES
1. Hydrogen Europe. (2024). Hydrogen Infrastructure Report – Building a European Hydrogen Network. [https://hydrogeneurope.eu/wp-content/uploads/2024/10/2024.10_HE_ Hydrogen-Infrastructure-Report.pdf]
2. European Hydrogen Backbone (EHB). (2022). European Hydrogen Backbone grows to meet REPowerEU’s 2030 hydrogen targets (Press release). [European Hydrogen Backbone grows to meet REPowerEU’s 2030 hydrogen targets | EHB European Hydrogen Backbone]
3. S&P Global Commodity Insights. (2023, October 27). Netherlands begins construction of national hydrogen pipeline network. [https://www.spglobal.com/commodity-insights/en/news-research/latestnews/energy-transition/102723-netherlands-begins-construction-of-national-hydrogen-pipelinenetwork]
4. Gasunie. (2023). Dutch national hydrogen network launches in Rotterdam (press release). [Hydrogen Through Gas Pipeline: Safe and Sustainable]
6. Cleary Gottlieb Steen & Hamilton LLP. (2023, March 31). EU introduces new Hydrogen and Decarbonized Gas Market Package. [https://www.clearygottlieb.com/news-and-insights/publicationlisting/eu-introduces-new-hydrogen-and-decarbonized-gas-market-package]
8. Port of Rotterdam Authority. (2023). Import of Hydrogen – Europe’s Hydrogen Hub (web page) [Import of hydrogen | Port of Rotterdam]
9. Port of Rotterdam. (2023, February 13). Large-scale ammonia cracker to enable 1 million tonnes of hydrogen imports. [https://www.portofrotterdam.com/en/news-and-press-releases/largescale-ammonia-cracker-to-enable-1-million-tonnes-of-hydrogen-imports]
10. Moeve Global. (2024, February 21). Cepsa and ACE Terminal will create green hydrogen supply chain. [https://www.moeveglobal.com/en/press/cepsa-and-ace-terminal-will-create-greenhydrogen-supply-chain]
12. Rouwenhorst, K. (2024). "Updated PGS-12 code: Preparing for increased ammonia imports to the Netherlands." Ammonia Energy Association. [Port of Rotterdam - Ammonia Energy Association]
13. Mitsubishi Heavy Industries (MHI) Spectra. (2023). "Pipes, ports and electrolyzers: Europe’s hydrogen future." (Johnny Wood, Dec 7, 2023). [Pipes, ports and electrolyzers: Europe’s hydrogen future | Spectra by MHI]
14. Thole, E. (2024). "Towards the Refinery of the Future." C2W/ScienceLink (Dec 2, 2024). [Towards the Refinery of the Future | English | ScienceLink]
15. Reuters. (2023). Shipping group Maersk sets up green methanol company (Johannes Birkebaek & Jacob Gronholt-Pedersen, Sept 14, 2023). [Shipping group Maersk sets up green methanol company | Reuters]
16. Clean Hydrogen Partnership. (2023). Nine Hydrogen Valleys to Re-power Europe (announcement). [Nine hydrogen valleys to repower Europe - Offshore-Energy.biz]
17. Sun, J., Ding, N., Yang, Y., & Zhang, Z. (2022). Overview of Liquid Organic Hydrogen Carriers (LOHCs): Toward hydrogen storage and transportation. International Journal of Hydrogen Energy, 47(9), 5700–5720. [https://doi.org/10.1016/j.ijhydene.2021.11.151]
18. Zhang, X., Wang, R., & Chen, X. (2020). A review of liquid organic hydrogen carriers for hydrogen storage. IEEE Access, 8, 120193–120210. [https://doi.org/10.1109/ACCESS.2020.3004235]
19. ACER. (2023). The Role of Hydrogen in European Gas Networks – Report. [ACER identifies need for higher consistency in European gas and ...]; [EU introduces new Hydrogen and Decarbonized Gas Market Package]
20. Honoré, A. (2024). From natural gas to hydrogen: What are the rules for European gas network decarbonisation? (NG 190). Oxford Institute for Energy Studies. [https://www. oxfordenergy.org/wpcms/wp-content/uploads/2024/04/NG-190-From-natural-gas-to-hydrogenwhat-are-the-rules-for-European-gas-network-decarbonisaton.pdf]
21. Pregger, T., Metzler, D., & Henning, H.-M. (2020). Integration of hydrogen into multi-sector energy systems: An evaluation of the German case. Energies, 13(7), 1606. [https://doi.org/10.3390/ en13071606]
22. New Energy Coalition. (2020). HEAVENN Project Description – Hydrogen Valley Northern Netherlands. [HEAVENN - New Energy Coalition]
23. New Energy Coalition. (2023). The Netherlands awarded Europe’s Hydrogen Valley of the Year [https://www.newenergycoalition.org/en/the-netherlands-awarded-europes-hydrogen-valley-ofthe-year/]
Part V
REFLECTION AND FUTURE DIRECTIONS
Chapter 9
Renewable Energy Carriers Research Group
The Renewable Energy Carriers (REC) research group was established in 2024 to drive the transition toward sustainable energy systems by focusing on “emerging energy carriers” –technologies that store and transport renewable energy so it can be used when and where needed Founded as part of Avans University of Applied Sciences and Centre of Expertise MNEXT (Materials and Energy Transition), the REC group’s mission is rooted in maximizing the use of clean energy resources and reducing dependence on fossil fuels. It established during MNEXT’s expansion beyond biobased research into broader energy transition topics.
The guiding principles of REC emphasize practical innovation, collaboration, and impact. As a research group within a university of applied sciences, REC is led by a professor and consists of researchers, lecturers, and students working together to solve real-world problems. This practice-oriented ethos means that projects are designed with industry and societal partners, guaranteeing that the research outcomes can be directly applied in industrial settings and community initiatives. REC’s guiding philosophy is to bridge theory and practice – by developing new technologies and integrating them into living labs and pilot plants, the group aims to accelerate adoption of renewable energy carriers in sectors where direct electrification is challenging. In doing so, REC group aligns with a larger vision of a flexible, reliable, and low-carbon energy system in which green hydrogen, sustainable fuels, and circular energy carriers replace fossil fuels. Guided by this mission, the REC group has defined a clear scope for its work. Renewable electricity from wind and solar often doesn’t match demand in time or location; energy carriers like hydrogen, ammonia, synthetic fuels, and even metal powders can “buffer” this energy and deliver it for heavy transport or industrial processes where electrons alone won’t suffice. REC’s formation was catalysed by the recognition that multiple carriers will be needed to achieve climate goals – no single solution fits all applications. Thus, since its inception, REC has focused on a multi-pronged research agenda. The REC team also incorporates socio-economic considerations (like public acceptance, safety, and business models) into their technical research to ensure new energy carriers can be implemented smoothly.
The group’s mission is to enable flexible, reliable, and sustainable energy systems using hydrogen, synthetic fuels, ammonia, and metal powders.
9.1 INTEGRATION WITHIN AVANS UNIVERSITY & MNEXT STRATEGY
The REC research group operates within MNEXT, the Centre of Expertise for Material and Energy Transition—a joint initiative of Avans and HZ. Formerly known as the COE Biobased Economy, MNEXT was rebranded in 2023 to broaden its focus to the full materials and energy transition. Within this framework, REC complements other research lines to offer a holistic approach to sustainability. MNEXT’s mission is to serve as a bridge between innovation and society, working closely with SMEs and regional partners to accelerate the sustainable transition. The group’s work on energy carriers aligns with Avans University’s broader sustainability strategy and educational goals.
Avans emphasizes applied research with direct societal impact, tightly integrated with its educational programs. As part of this ecosystem, REC contributes to curriculum development, involves students in research, and helps train the future energy transition workforce. In practice, REC’s labs and projects serve as learning environments, delivering practical experience while addressing real-world challenges. For instance, if REC develops a method for dynamic electrolyser control or tests an iron fuel system, this knowledge not only benefits industry partners but is also transformed into case studies and teaching materials.
This integration ensures that graduates are equipped with hands-on experience in cutting-edge energy carrier technologies. Ultimately, embedding REC within both MNEXT and Avans’ institutional strategy means that advancing renewable energy carriers is not an isolated effort, but part of a coordinated drive to educate professionals and deliver innovations that support the Netherlands’ energy and climate ambitions.
9.2 KEY RESEARCH LINES OF REC
REC’s research agenda is organized into three primary lines, each addressing a different renewable energy carrier and its applications. Figure 19 gives an overview of these research lines and how they connect to real-world uses. The focus areas are: (a) Green Hydrogen, (b) Derivatives & E-Fuels, and (c) Iron as an Energy Carrier
Research
line 1: Green Hydrogen
Green hydrogen is a cornerstone of the REC group’s work, reflecting hydrogen’s role as a versatile zero-carbon energy carrier. The REC team addresses the entire hydrogen value chain, from production through distribution to end use. On the production side, REC researchers are advancing water electrolysis technologies, including PEM & SOEC. A key research focus is optimizing electrolyser performance under dynamic conditions, essential for integrating variable renewable energy. In the HyPRO project (GroenvermogenNL WP1), REC and partners work to improve these technologies for large-scale, low-cost hydrogen production. It focuses on predicting real-world performance and developing scaling rules from lab to industry. By addressing degradation, materials supply, and efficiency, the goal is to lower the cost of green hydrogen and support its multi-gigawatt deployment.
HySuccess
HyPRO
RESEARCH GROUP RENEWABLE ENERGY CARRIERS
RESEARCH GROUP RENEWABLE ENERGY CARRIERS
Local & seasonal estorag
Deploy energy carriers for industry & mobility
Deploy energy carriers for industry & mobility
RESEARCH GROUP RENEWABLE ENERGY CARRIERS
Regional impact in Brabant, Zeeland & Port of Rotterdam
Industrial heat
Regional impact in Brabant, Zeeland & Port of Rotterdam
Deploy energy carriers for industry & mobility
Regional impact in Brabant, Zeeland & Port of Rotterdam
tWe ecycl
Iron powder burners (fluidized bed)
Derivatives & E-Fuels
Research Line 2:
HyUSE
Pilots & rtnershipsPa
Applications
tionProduc & Integration
tionProduc & Integration Applications
Research Line 1:
Green Hydrogen
Ammoni (Haber-Bosch)
Methanol (CO₂-based)
FT E-fuels
Marine/road fuels
Industrial feedstocks
Research Line 3:
Iron as Energy Carrier
Research Line 1: Green Hydrogen
Research Line 1: Green Hydrogen
Production & Integration Applications
Ammoni (Haber-Bosch)
Ammoni (Haber-Bosch)
Pilots & Partnerships
Methanol (CO₂-based)
Methanol (CO₂-based)
FT E-fuels
FT E-fuels
Marine/road fuels
Marine/road fuels
Production & Integration Applications
Production & Integration Applications
Industrial feedstocks Figure 19 REC research lines
Industrial feedstocks
Research Line 3:
Research Line 3: Iron as Energy Carrier
Iron as Energy Carrier
Production & Integration Applications
Pilots & Partnerships
HyPRO
Electrolysis (PEM, SOEC)
Electrolysis (PEM, SOEC)
Hydrogen burners (industry)
Coupling with renewables
Electrolysis (PEM, SOEC)
Coupling with renewables
Pilots & rtnershipsPa
Production & Integration Applications
Hydrogen enabled microgrid
Hydrogen enabled microgrid
Coupling with renewables
Fuel cells (mobility
Hydrogen enabled microgrid
Fuel cells (mobility
Green Steel
Pilots & Partnerships
Pilots & Partnerships
HyPRO
HyUSE
Green Steel
Fuel cells (mobility
Green Steel
HySuccess uelF cells y(mobilit
Green Steel
Hydrogen enabled microgrid
Coupling with renewables
Hydrogen burners (industry)
Hydrogen burners (industry)
tionProduc & Integration Applications
Hydrogen burners (industry)
HyPRO
HyPRO
Electrolysis (PEM, SOEC)
HyUSE
HyUSE
HySuccess
HySuccess
Production & Integration Applications
HySuccess
Production & Integration
Research Line 2:
Research Line 2: Derivatives & E-Fuels
Derivatives & E-Fuels
Applications
Research Line 2:
Derivatives & E-Fuels
Production & Integration Applications
Iron powder burners (fluidized bed)
Iron powder burners (fluidized bed)
Iron powder burners (fluidized bed)
Wet cycle
Production & Integration Applications
Industrial heat
Wet cycle
Wet cycle
in Brabant, Zeeland & rtPo of erdamRott
Industrial heat
Industrial heat
energy carriers orf industry & mobility
Local & seasonal storage
Local & seasonal storage
Pilots & Partnerships
Pilots & Partnerships
Local & seasonal storage
HyPRO
HySuccess
HyPRO
HyPRO
HySuccess
HySuccess
Beyond production, REC’s Green Hydrogen line also explores H2 storage and use in local and industrial contexts. In the HyUSE project (GroenvermogenNL WP3), the group studies hydrogen-powered microgrids for small industries and communities, using hydrogen as a local buffer for electricity and heat during renewable shortfalls. By the end of the project, HyUSE will deliver technologies and guidelines for hydrogen integration in sectors like water treatment, glass, and steel. REC also focuses on industrial decarbonization, with hydrogen replacing fossil fuels in high-temperature processes (e.g., furnaces for steel and ceramics) and in heavy-duty transport. This includes pilot projects testing hydrogen burners and fuel cell systems with partners, investigating feasibility and safety in real-world applications.
REC’s Green Hydrogen line extends beyond pure hydrogen to explore downstream applications, interreacting with Research Line 2. Hydrogen serves as a building block for synthetic e-fuels and can generate heat or electricity via fuel cells or turbines. This holistic approach spans from developing electrolyser components (e.g., membranes, catalysts) to system integration in factories and microgrids.
Research line 2: Derivatives and E-Fuels
Another core pillar of REC’s research is electro-fuels (e-fuels); liquid fuels made by combining green hydrogen with captured CO₂ or nitrogen. These fuels serve as hydrogen carriers and low-carbon alternatives for sectors like shipping, aviation, power generation, and the chemical industry. REC focuses primarily on green ammonia (NH₃) and green methanol (CH₃OH) due to their versatility and potential for scale. REC's work follows a phased approach. Initially cantered on Fischer–Tropsch fuels from biomass, research now extends to true power-to-X pathways using renewable electricity and captured CO₂. Green ammonia is a key priority, valued as both a carbon-free fuel and fertilizer feedstock. REC investigates sustainable ammonia synthesis using renewable-powered Haber-Bosch, targeting improved catalysts, efficiency, and small-scale flexibility; critical for intermittent operation. On the utilization side, REC collaborates with partners to assess combustion behaviour, NOx control, and safety; vital due to ammonia’s toxicity. Green methanol is also central to REC’s e-fuels line. Produced from green hydrogen and captured CO₂, it can close the carbon loop if CO₂ is sourced sustainably. REC studies improved CO₂ capture, conversion processes, and integration into renewable energy systems. REC also examines the technoeconomic feasibility of e-methanol in the Dutch context, assessing the impact of electricity prices, CO₂ availability, and policy incentives.
REC’s e-fuels line covers production (power-to-X), CO₂ integration, catalyst development, and end-use applications, aiming to create viable, scalable pathways for converting renewable electricity into low-carbon fuels.
Research line 3: Iron as an Energy Carrier
One of REC’s most innovative research lines is the use of iron powder as a renewable energy carrier (see chapter 6). REC advances this on multiple fronts. In partnership, REC develops pilot-scale systems for both combustion and regeneration. On the combustion side, the group designs burners and reactors that stably burn iron powder, control reaction rates, and capture oxide particles for reuse.
On the regeneration side, REC explores efficient reduction of iron oxide, using green hydrogen/syngas to yield iron. The team investigates solid oxide electrolysis, hydrogen furnaces, and electrochemical methods to improve energy efficiency and operational
flexibility. Key challenges include minimizing sintering and degradation during cycling, which can be addressed through material coatings and additives to stabilize the iron particles.
REC is also developing a steam–iron reactor system to enable a complementary wet cycle, where oxidizing iron with steam produces hydrogen gas directly. This reversible cycle—Fe -> Fe₃O₄ -> FeO involves using iron as a hydrogen storage medium. REC’s work focuses on optimizing small-scale reactor performance and supporting the design of a pilot-scale steam–iron reactor that can store and release hydrogen on demand. This adds flexibility to the hydrogen supply chain and strengthens the link between iron-based storage and green hydrogen systems.
The research is highly collaborative. REC is an active member of the Metal Power Consortium, contributing to projects aimed at scaling iron fuel technologies. It works with industries in Brabant on practical applications, including CO₂-free heat for steel treatment and district heating.
REC also supports the “Groeien met Groen Staal” initiative to decarbonize Dutch steelmaking. REC’s expertise in iron’s redox chemistry feeds directly into these circular steel innovations.
9.3 COLLABORATIVE INITIATIVES AND STRATEGIC ALIGNMENT
The REC research group actively collaborates with national and international programs to amplify its impact and align with broader energy transition strategies. In the Netherlands, REC is embedded in major initiatives like GroenvermogenNL23 and Groeien met Groen Staal24, focusing on various aspects of the hydrogen economy. These collaborations offer funding, industry partnerships, and opportunities to contribute to collective goals such as hydrogen infrastructure, green steel development, and the deployment of emerging energy carriers.
Within GroenvermogenNL, supported by the National Growth Fund, REC contribute to several flagship projects; HyPRO, HyUSE, HyCarb and HySUCCESS. These projects integrate technical innovation with system-level planning. HyUSE promotes hydrogen use across Dutch society through a network of 30+ partners, including universities, TNO, and industry. HySUCCESS complements this by addressing socio-economic dimensions such as market design, public acceptance, legal frameworks, and labour impacts, guiding Dutch policy for a sustainable hydrogen economy.
Through Groeien met Groen Staal, REC contributes to transforming Tata Steel IJmuiden and the broader Dutch steel sector toward low-CO₂, hydrogen-based production. REC’s work on iron fuel systems supports this transition and aligns with the national ambition to become a leader in green steel.
Collaboration is central to REC’s identity. Participation in consortia provides not only funding but also access to a broader knowledge network. Industry partnerships ensure that REC’s work is grounded in practical application, accelerating real-world adoption. Beyond technology, REC aims to act as an ecosystem builder, connecting innovations with stakeholders across academia, industry, and government—demonstrating the integrated approach essential for an effective energy transition.
9.4 MEMBERS OF THE RESEARCH GROUP
Ad Breukel
At MNEXT, Ad researches business and network models to commercialize innovative sustainable energy technologies, including energy generation, storage (batteries, hydrogen), and smart grid systems. His work in the Smart Energy and Renewable Energy Carriers groups focuses on both technical and organizational innovations to support market development. Before joining MNEXT, Ad studied Industrial Engineering at the University of Twente and earned a PhD in Business Administration from the University of Groningen, later working as a researcher at Erasmus University Rotterdam. Looking ahead, he aims to shift from traditional business models to inclusive business cases that support new technologies, with an emphasis on both quantitative and narrative approaches. He also contributes to energy education through new initiatives and cross-border academic collaborations.
Ali Agha Zeeshan
Ali is currently working as a full-time researcher within the Renewable Energy Carriers research group at MNEXT. His work is related to the development and application of sustainable energy technologies, with a strong focus on hydrogen production and its integration into industrial processes. His main research interests lie in advanced electrolyser technologies, particularly proton exchange membrane (PEM) electrolysers and solid oxide electrolysers (SOE). Ali is committed to bridging the gap between cutting-edge academic research and practical, real-world applications. His aim is to support regional industries in adopting cost-effective and low-carbon solutions for their energy needs. His research contributes directly to ongoing efforts in the Netherlands and Europe to achieve climate neutrality and a circular economy.
Jeroen van Gerwen
Jeroen is a teacher-researcher at MNEXT’s Renewable Energy Carriers and Smart Energy research groups two days a week, and teaches the other two days at the Academy of Technology and Design at Avans in Den Bosch. Before joining MNEXT, Jeroen worked as a physics teacher and as a process engineer at Nanolab at TU Eindhoven, where he was responsible for operating ALD systems. At MNEXT, Jeroen’s role and ambition is to bridge the gap between education and research. He believes that new innovations and awareness in the energy transition must be integrated into engineering curricula. To support this, he aims to organize practical workshops on hydrogen for students, universities, and companies—covering the basics, showcasing potential through game-based setups, and encouraging open discussions.
Jobert Ludlage
Jobert earned his MSc in Electrical Engineering and PhD in controllability analysis for industrial processes from Eindhoven University of Technology (TU/e) in 1987 and 1997. He began working in process control engineering in 1986 and co-founded a control company in 1998, where he developed predictive control technology. Since 2009, Jobert has taught Electrical Engineering at Avans in Breda, contributing to the Smart Energy and now the Renewable Energy Carriers research group at MNEXT. He leads the “Iron Line,” focusing on iron as a renewable energy and hydrogen carrier. Jobert also holds a part-time position at TU/e’s Control Systems group. His research spans predictive control, system optimization, hybrid modeling, and energy storage using iron to ensure stable energy availability over time and location.
René Kleijntjens
René Kleijntjens combines his work for MNEXT with a position in the industry at UTB Oils in Dordrecht. After earning his PhD at TU Delft, he worked for various companies in the oil and gas, surveying, and biotechnology sectors. Part-time, he has also served as a lecturer at the Avans ALST Academy for Chemical Engineering. Currently, René is a researcher at MNEXT, focusing on innovations in (bio)fuels and refinery processes, including methanol and the Fischer-Tropsch process. In his work, he aims to closely connect industry, automotive, and shipping with research and education. Within the Renewable Energy Carriers research group, he hopes to act as a bridge between stakeholders and partners essential for driving innovation.
Sander van Gameren
Sander is a researcher for the Smart Energy and Renewable Energy Carriers research groups, working at the intersection of new energy sources and their integration into traditional energy networks. Together with his colleagues, he investigates topics such as hydrogen (Solid Oxide) and distributed control systems, exploring questions like: “Which techniques can produce hydrogen at €2/kg?” and “How should smart grids be configured to reliably supply energy?” Sander holds an MSc in Electrical Engineering from TU/e, specializing in control systems and energy technology. Before joining MNEXT as a researcher in 2023, he worked in electrotechnical roles at Seatrade, Witteveen+Bos, and ASML. Passionate about sustainability, he lives with his wife in Veldhoven and sometimes in China, and enjoys bouldering and windsurfing.
Sahar holds a Master’s degree in Sociology from the University of Tehran and has experience in both qualitative and quantitative research, including survey design, data analysis, and stakeholder engagement. Before joining MNEXT, she worked on social and cultural research projects. She is currently a researcher at MNEXT, contributing to the HySUCCESS project, Social User-Acceptable, Economically Sustainable Systems for Hydrogen. Sahar’s work explores how social values shape the acceptance of energy innovations. She is passionate about bridging the gap between technology and society and aims to contribute to more inclusive and socially responsible energy transitions in the future. Through her work, she hopes to support the development of energy systems that are not only technically efficient but also socially aligned and culturally sensitive.
Gerben is a researcher and lecturer affiliated with MNEXT, the New Materials and its Applications research group (CoE V&V), and TU Delft’s Materials Science & Engineering department as a guest researcher. At MNEXT, he focuses on applied research in nuclear energy technology, aiming for its safe, durable, and reliable deployment while integrating it into education. Trained as an applied physicist and materials scientist, Gerben specialized in photonics and earned a PhD in steel technology. He has worked at TU Delft, UGent, and TNO, and brings nearly 20 years of industrial experience in operational management, product development, and international finance. He now teaches Maintenance Management and Reliability Engineering and contributes to projects on sustainable steel production, circular materials, and the development of the MET professional master’s program.
Rima has had a passion for science from a young age, leading her to pursue both academic and professional paths in the field. She earned a Bachelor’s degree in Chemistry from Jordan University of Science and Technology and a second Bachelor’s in Chemical Engineering from Avans University of Applied Sciences. She then worked for nearly three years at an engineering and consultancy firm, contributing to sustainable projects involving fermentation, biodiesel production, and pyrolysis of biomass. In 2021, Rima began a Master’s in Chemical and Process Engineering at TU Eindhoven and joined MNEXT as a Junior Researcher. Since earning her Master’s degree in 2023, she has been working at MNEXT, contributing to both the Biobased Resources & Energy and the Renewable Energy Carriers research groups. Within the Renewable Energy Carriers group, she focuses on developing innovative solutions for green energy production while continuing to deepen her expertise.
Sahar Rezaei
Gerben Krielaart
Rima Mahmoud
Yide is currently on a teacher placement at MNEXT and the Renewable Energy Carriers research group. At Avans, he serves as a lecturer in International Business within the Academy for Business & Entrepreneurship (ABE). His main goal is to integrate business and economic perspectives into ongoing projects while enhancing the connection between education and research. With a background in sustainability science and technology management, Yide has worked across various sectors, including higher education, IT, and data consultancy. His interdisciplinary interests span didactics, analytics, policy analysis, psychology, and the social sciences. Yide looks forward to exchanging ideas and exploring collaboration opportunities on behalf of his academy, through student placements, guest lectures, and course module development.
Kim Jones is the Coordinator for Renewable Energy Carriers, having started this role in April after previously serving as Senior Management Assistant within the research group. Her main responsibility is to support the group with organizational and administrative tasks, optimizing processes to ensure efficiency. Kim studied Tourism Management at Fontys University of Applied Sciences and spent a few years in the events and congress industry. She then shifted focus to project coordination in a technical company producing gas and fluid systems. At the age of 50, she decided to seek a new challenge and joined MNEXT and Renewable Energy Carriers. Kim is excited to be part of the research group and contribute to its development.
Trisha works as a Senior Management Assistant for Renewable Energy Carriers. She started this role in April, with her main responsibility being to support the group with organizational and administrative tasks. Prior to joining MNEXT and Renewable Energy Carriers, Trisha worked for many years as an executive assistant at a law firm. The law firm, where she had the opportunity to build her knowledge over 14 years, specializes in tax litigation and financial law. Before entering the legal profession, she worked as an assistant accountant. Trisha hopes to provide valuable support to the research team and is excited about this new challenge.
Yide Gao
Kim Jones
Trisha Kessels
Chapter 10
Challenges, Opportunities, and Future Directions
Building on the previous chapters, this chapter examines the primary challenges, opportunities, and future directions for renewable energy carriers, with hydrogen reemerging as a cornerstone of Europe's clean energy transition, especially in the Netherlands. Hydrogen provides a critical pathway for decarbonizing hard-to-abate sectors. While direct electrification will significantly reduce emissions, renewable hydrogen and its derivatives could meet approximately 10% of the EU's final energy demand by 2050 [1].
Currently, hydrogen accounts for less than 2% of Europe’s energy use, predominantly grey hydrogen derived from natural gas. However, ambitious targets outlined in the EU’s Hydrogen Strategy and the REPowerEU plan aim for the production and import of 10 million tons each of renewable hydrogen by 2030.
Achieving these objectives requires addressing substantial policy, technological, and market barriers. This chapter provides an in-depth exploration of policy and regulatory challenges, technological bottlenecks, market formation strategies, workforce transformation needs and evaluates both near-term and long-term perspectives through 2030 and 2050.
10.1 POLICY AND REGULATORY BARRIERS
Despite strong decarbonisation commitments, several policy and regulatory barriers impede the rapid scale-up of hydrogen in EU include:
• Carbon Pricing and Competitiveness: The EU ETS puts a price on CO₂, improving hydrogen’s competitiveness by penalizing fossil fuels [2]. However, asymmetric carbon pricing globally means EU industries could face higher costs than foreign competitors. To address this, the EU is phasing in a Carbon Border Adjustment Mechanism (CBAM) that will apply a carbon price to imports of carbon-intensive goods to level the playing field [2]. A well-functioning carbon price is ultimately an opportunity for hydrogen: a robust CO₂ price makes green hydrogen more cost-competitive relative to unabated fossil hydrogen.
• Permitting and Planning Delays: Lengthy permitting procedures remain a major bottleneck for RE and hydrogen projects. In the EU, official permitting timelines for hydrogen production facilities range from 18 to 24 months, but actual processes often take longer due to complex environmental and safety assessments [2]. To speed things up, the EU has begun classifying dedicated hydrogen projects as being of “overriding public interest,” allowing for faster approvals [2].
A clear example is the Delta Rhine Corridor in the Netherlands—a proposed pipeline network for hydrogen, CO₂, and ammonia connecting Dutch and German industrial hubs. Despite being designated a nationally significant project in 2023, it has faced a four-year delay due to difficulties with spatial planning, multi-infrastructure coordination, and securing public support [3].
• Infrastructure Codes and Safety Standards: EU bodies are revising gas, pipeline, compressor and storage codes to create harmonised “fit-for-purpose” hydrogen standards, ensuring safe, interoperable grids, refuelling stations and appliances [4]. Clear, EU-wide rules - covering materials, odorisation and safety distances - will ease project approvals, cut local restrictions, and raise investor and public confidence. Dutch institutes such as Kiwa and NEN feed safety research into these updates, helping align national practice with the emerging norms.
• Guarantees of Origin and Certification: Differentiating green hydrogen or LC hydrogen from fossil-derived hydrogen is crucial for policy incentives and consumer trust. Yet until recently, there was no internationally recognized certification mechanism for hydrogen’s origin. This gap meant producers of renewable H₂ could not easily prove its climate credentials to claim subsidies or trade credits [5]. In Europe, this is now starting to change. The Renewable Energy Directive (RED II/III) mandates Guarantees of Origin (GO) for renewable gases including hydrogen and defines sustainability criteria for Renewable Fuels of Non-Biological Origin (RFNBOs) [1]. The Netherlands became the first EU country to implement a green hydrogen GO system: in 2022 the Dutch certifier Vertogas issued the first green hydrogen certificates and convert these certificates into tradeable units [6].
10.2 TECHNOLOGICAL BOTTLENECKS
Scaling hydrogen and its derivatives from niche to mainstream involves significant technological hurdles. This section outlines key bottlenecks and current efforts to address them.
• Conversion Efficiency Limits: Each step in the hydrogen value chain incurs energy losses, posing an efficiency challenge. Converting renewable electricity to hydrogen via electrolysis is ~65–75% efficient (LHV basis). Using hydrogen in fuel cells to generate power is ~50–60% efficient. If hydrogen is further converted to other carriers or back to electricity, additional losses accumulate at each stage [5]. These conversion losses necessitate significantly more upstream renewable capacity to deliver the same useful energy [5]. Thus, a key challenge is to deploy hydrogen in applications where its value outweighs the efficiency penalty, and to improve conversion technologies. Research is active to raise electrolyser efficiency, and to improve round-trip efficiency of hydrogen storage. Nevertheless, physics dictates hydrogen will not match the end-to-end efficiency of direct electric solutions like batteries, which shapes where hydrogen should be applied.
• High Equipment Costs: Green hydrogen remains significantly more expensive than fossil alternatives, mainly due to high capital costs. Although electrolyser prices have declined, installed systems still average €1,000–1,400 per kW [7], leading to production costs of Change dollar to Euro, keep the numbers. Fuel cells and hydrogen turbines are also costly compared to conventional technologies. The upside is that costs are expected to drop sharply with scaling and innovation. Industry roadmaps project electrolyser manufacturing to grow from under 5 GW/year in 2021 to over 100 GW/year by 2030 [7];[8], enabling economies of scale. Stack costs for mature technologies like alkaline and PEM electrolysers could fall by ~60% by 2030 [9], with some studies projecting PEM stack costs below €200/kW by then [9]. Policy support— including the US Inflation Reduction Act and EU Innovation Fund—is accelerating investment in large-scale manufacturing. However, bridging the cost gap in the 2020s will still require transitional support such as capital grants and CfD. Improving equipment durability (e.g. electrolysers lasting 80,000+ hours) will also help reduce lifecycle costs.
• Critical Materials and Supply Chains: Some hydrogen technologies depend on scarce or expensive materials, creating potential bottlenecks as deployment scales up. PEM electrolysers and fuel cells, for instance, use PGMs like platinum and iridium as catalysts. Iridium is especially rare, and widespread PEM deployment could strain global supply [10];[11]. Analysts warn that with annual iridium production at only a few tons, building tens of GW of PEM electrolysers per year may be unsustainable. To address this, manufacturers are reducing PGM usage. For example, ITM Power has cut iridium use in its PEM cells by 80% [12]. Alternatives such as alkaline electrolysers, which use nickel-based catalysts, and emerging AEM electrolysers, which are PGMfree, help diversify technology options. Fuel cell developers are also working on reducing PGM loadings and developing non-platinum catalysts. Additionally, some hydrogen compressors and motors use rare-earth magnets. However, the most hydrogen-specific bottlenecks remain PGMs and potentially rare earths. Addressing these vulnerabilities will require securing critical supply chains, investing in recycling, and improving material efficiency. The EU’s Raw Materials Strategy and clean tech investments are steps in this direction.
Alkaline and AEM electrolysers, which use nickel or no PGMs, help diversify the technology mix.
• System Integration and Infrastructure: Integrating hydrogen into the broader energy system presents both technical and logistical challenges. On the production side, electrolysers must be linked with RE sources. When connected directly to intermittent renewables, electrolysers need to handle variable loads and frequent start-stop cycles, which can reduce efficiency and wear down equipment. To manage this, smart control systems and buffering solutions are essential for optimizing electrolyser performance, balancing economic operation with grid stability. Importantly, hydrogen production can act as a grid-balancing tool by absorbing excess renewable electricity and reducing curtailment [5]. However, this requires advanced digital integration, accurate forecasting, and market mechanisms to signal optimal operation times. The EU’s Energy System Integration Strategy highlights hydrogen’s role in connecting the power sector with industry and transport, though large-scale sector coupling is still in early stages. On the demand side, integration brings additional hurdles. Existing natural gas infrastructure can only accommodate limited hydrogen blends (typically 10–20% by volume) without modifications. Beyond that, dedicated hydrogen burners or turbines are necessary. Similarly, many industrial processes must be redesigned to switch from coal or gas to hydrogen, making retrofitting complex and gradual. Infrastructure development is equally critical.
The lack of infrastructure creates a “chicken-and-egg” dilemma: large consumers need pipelines and storage to commit to hydrogen, while infrastructure developers hesitate without guaranteed demand. To overcome this, governments are financing hydrogen networks upfront, much like the early development of natural gas grids.
• Scalability of Production and Supply: Meeting climate targets will require hydrogen production to scale up dramatically. In the EU’s 2050 vision, hydrogen demand could reach 1,000–1,800 TWh per year (about 30–55 million tons), up from today’s 300 TWh (10 Mt), which is mostly used as industrial feedstock [13];[1]. Even the 2030 target of 20 Mt represents a massive expansion within a short timeframe. Achieving this scale will demand gigawatt-scale electrolyser projects, bulk transport solutions, and significant increases in renewable electricity dedicated to hydrogen. However, most planned projects in the Netherlands and the broader EU have not yet reached FID, largely due to uncertainties in hydrogen demand and market conditions [3]. Scaling up will require coordinated policy support across the entire value chain. On the technology side, the focus is on mass-manufacturing electrolysers and fuel cells, building large-scale storage, and developing global supply chains for renewable hydrogen and its carriers. Emerging hydrogen carriers could support scalability, but they also require end-use devices to be adapted for direct use. As with any new supply chain, early large-scale projects may face cost overruns, delays, and supply constraints. These “teething problems” are expected, but they highlight the need for strong early-stage support. On the positive side, Europe’s coordinated push is designed to overcome these initial hurdles and reach a point where economies of scale and market forces can drive sustained growth.
10.3 MARKET FORMATION STRATEGIES
Developing a viable hydrogen market is as much a policy and economic challenge as a technological one. Early market failures—such as high costs, lack of scale, and poor coordination—require policy support to stimulate supply and demand. To address this, the EU and its member states are implementing strategies to break the chicken-and-egg cycle and reduce costs through learning-by-doing. Key approaches include:
• Demand Aggregation and Hydrogen Hubs: One approach to trigger the market is aggregating hydrogen demand from multiple consumers to provide scale and certainty to suppliers. The EU has proposed a “Hydrogen Bank” mechanism, part of which involves collective offtake auctions where hydrogen buyers pool their demand and offer a guaranteed price for green hydrogen, which producers can bid to supply. This concept builds on Germany’s H2Global model27, wherein a government-backed intermediary signs long-term hydrogen purchase contracts and sells the hydrogen to end-users via auction – covering the price gap with a subsidy. By aggregating demand and de-risking price volatility, such mechanisms give producers the confidence to invest in large projects. On the demand side, platforms similar to the AggregateEU gas buying platform are being considered for hydrogen to jointly procure hydrogen or its derivatives for import [14]. In the Netherlands, the HyXchange initiative also envisions a trading hub where hydrogen demand and supply can be matched transparently, building a price index. Additionally, the concept of “Hydrogen Valleys” – regional clusters – serves to co-locate multiple users and suppliers of hydrogen in a confined geography, effectively aggregating demand and supply with shared infrastructure. By 2025, the EU aims to double the number of such valleys [15].
The EU’s Hydrogen Bank and Germany’s H2Global use demand aggregation and auctions to de-risk investment and guarantee offtake.
• Quotas and Mandates for GH2 Use: Another powerful tool to create a market is mandating the use of clean hydrogen or its derivatives in certain applications. The EU’s policies are moving in this direction. The revised RED III introduced binding sub-targets: for example, by 2030 at least 42% of hydrogen consumed in industry (for energy or feedstock) must be from renewable sources, and at least 1% of transport energy must be RFNBOs (rising to 5% by 2035) [3];[1]. These obligations essentially guarantee a market for GH2 in refining, ammonia production, methanol, steel and other industrial processes. The Netherlands is working to transpose these targets into national law [3]. In addition, the Dutch government is considering mandates in specific sectors: for instance, requiring a certain percentage of green hydrogen use in refineries or blending hydrogen into gas for electricity generation. By legislating demand, governments create assured markets that incentivize suppliers to invest.
• CfD and Price Guarantees: Given hydrogen’s cost gap, risk mitigation policies are vital to encourage first movers. Chief among these is CfD or similar price guarantee mechanisms. A hydrogen CfD would pay producers the difference between their cost and the market price of the fossil alternative. This assures producers a stable revenue, de-risking their investment, while ensuring that if and when green hydrogen becomes cheaper, they no longer receive payments. The EU Innovation Fund is planning to use a CfD approach for green hydrogen and low-carbon products (e.g. green steel) to cover the “green premium”. Some member states are also developing specific hydrogen subsidies: the Netherlands’ SDE++ program already provides operating support to projects that reduce CO₂ [3]. Insurance-type instruments can also help – for example, government-backed offtake agreements (as with H2Global) or guarantees on hydrogen demand for X years. Another risk mitigation measure is capital coinvestment: public funding for a share of project CAPEX. By sharing financial risk, these policies encourage private capital to flow in. The overall goal of risk mitigation tools is to break the vicious cycle of “no market, no investment” by de-risking at least one side of the equation. Early investors need confidence that if they produce green hydrogen, either someone will buy it at a remunerative price, or they will receive support to cover the cost differential. As markets mature and carbon prices rise, these supports can be tapered off – but in the 2020s they are indispensable.
These mechanisms are essential in the 2020s to break the ‘no market, no investment’ cycle.
• Public-Private Partnerships and Niche Market Cultivation: Hydrogen deployment can effectively start in niche markets where it is nearly cost-competitive or offers unique advantages. One well-known example is heavy-duty transport: fuel cell buses, trucks, and trains serve segments that are difficult to electrify with batteries. Similarly, hydrogen-powered forklifts and material handling equipment have gained traction in warehouse operations due to their fast-refuelling capabilities. While these early markets do not generate large-scale hydrogen demand on their own, they are critical for building supply chains and enabling incremental improvements. Another promising niche is industrial feedstock switching—specifically, replacing grey hydrogen in refineries and fertilizer production with green hydrogen. This transition is relatively straightforward, as demand already exists. In the Netherlands, major industrial sites like Shell Pernis and Tata Steel IJmuiden have announced plans to integrate hydrogen into their decarbonization strategies. By targeting such niches, governments aim to validate business cases and pave the way for broader market adoption. This approach follows a familiar pattern: market formation -> scale-up -> cost decline -> wider adoption. PPP, such as the EU’s CHP, have played a role in funding early-stage projects across these niches. Overall, these efforts represent a strategic pathway— focusing first on areas where hydrogen is most viable, and using them as stepping stones for long-term, system-wide deployment.
In essence, hydrogen market formation in the EU combines regulatory mandates (demand pull), financial incentives (supply push), and infrastructure development. The EU’s Hydrogen Strategy outlines three phases: (1) 2020–2024 focuses on installing 6 GW of electrolysers and developing hydrogen valleys; (2) 2025–2030 targets 40 GW capacity and a functioning internal market; and (3) 2030–2050 envisions mature, global hydrogen trade. We are now in the critical seeding phase, supported by instruments like the Hydrogen Bank, IPCEIs, and RED III targets. The success of these coordinated efforts will shape whether hydrogen becomes a self-sustaining market by the 2030s.
We are now in the seeding phase -driven by RED III mandates, IPCEIs, and the Hydrogen Bank.
10.4 NEAR-TERM OPPORTUNITIES (TO 2030)
Despite the challenges, the coming decade presents significant opportunities for the EU and the Netherlands to lead and benefit from hydrogen and other RE carriers. By 2030, strategic initiatives could position Europe at the forefront of this emerging industry. Key near-term opportunities include:
Industrial Innovation and Value Chain Leadership: Europe hosts many leading electrolyser and fuel cell manufacturers, giving it a strong foundation for a robust hydrogen value chain. As demand grows, European firms can capture market share in electrolyser production, advanced membranes, and hydrogen-ready infrastructure. The EU already hosts 9 of the world’s top 15 electrolyser manufacturers [19], while the global electrolyser market could reach €50 billion by 2030. By scaling R&D and gigafactory capacity now, the EU can position itself as a leading exporter of hydrogen technology and expertise. The Netherlands, with its gas infrastructure and chemical processing background, can specialize in areas like high-pressure compressors and storage innovations. Startups supported by IPCEI funding and Horizon Europe grants are advancing novel solutions. By setting technology standards early, the EU can outpace rivals.
Regional Economic Development (“Hydrogen Valleys”): Hydrogen projects typically cluster in industrial regions and ports. In the Netherlands, Groningen—traditionally reliant on natural gas—is transforming into a clean energy hub with a planned 1 GW electrolyser and salt cavern storage. The PoR seeks to become Northwest Europe’s hydrogen import and trading centre, building on its petrochemical complex and logistical expertise. These initiatives attract investments, create thousands of jobs, and repurpose existing infrastructure for a decarbonized future. EU structural funds and the Just Transition Fund can help coal and heavy industry regions pivot to hydrogen. By 2030, Europe could host 20–30 such hotspots, each specializing in a different facet of hydrogen, forming a vibrant network of regional expertise.
Energy Trade and Geopolitical Leadership: The EU’s proactive hydrogen policies allow it to shape global clean energy trade. Historically a major fossil fuel importer, Europe can rebalance by exporting technology and setting standards. The EU is signing cooperation agreements with exporters like Namibia, Chile, UAE, and Australia to build green hydrogen supply chains. This approach diversifies energy imports, enhances security, and positions EU firms to develop infrastructure abroad. The Netherlands, with its maritime tradition, is already negotiating green ammonia imports through its ports (e.g., from Oman), aiming to become the EU’s gateway for hydrogen. Early moves can secure long-term supply deals. By demonstrating how to integrate hydrogen into a common market, the EU can boost climate diplomacy and secure strategic autonomy. Establishing even a few reliable import corridors this decade would prove hydrogen’s viability and reduce dependence on volatile fossil markets.
Decarbonizing Industry and Maintaining Competitiveness: Europe’s heavy industries— steel, chemicals, cement, refining—face carbon regulation and high energy costs. Hydrogen can help decarbonize these sectors and keep them in Europe rather than relocating. Early success in projects like Sweden’s HYBRIT and hydrogen-based steel at ArcelorMittal plants could yield the world’s first large-scale green steel by 2030. This firstmover status may allow European firms to charge a premium and comply with stringent carbon rules.
In total, these near-term opportunities mirror the challenges—once addressed, each obstacle yields strategic advantages. By focusing on these, the EU can secure a prominent role in the hydrogen economy.
10.5 FUTURE OUTLOOK TO 2030 AND 2050
Looking ahead, hydrogen’s role is expected to grow significantly by 2030 and even more so by mid-century. This section examines projected trends through 2030 and toward 2050, and how EU and Dutch strategies align with these global developments.
By 2030 – Scaling and Initial Integration
The EU aims for 20 Mt H₂ use by 2030 (including 10 Mt produced domestically), demanding a vast expansion of electrolysis—potentially 40–50 GW EU-wide (compared to ~0.3 GW in 2020) [5].
Large electrolyser clusters (100–300 MW) and a few 1 GW “gigafactory” projects are on the horizon, especially in the Netherlands and adjacent offshore wind regions. For instance, the NorthH2 initiative in the Dutch North Sea plans multi-gigawatt electrolysers by the early 2030s, drawing power from dedicated wind farms [3]. International hydrogen trade routes may also become operational by 2030, with green ammonia shipped from North Africa, Australia, or Chile. Europe targets 10 Mt of imports, partnering with regions like the Middle East/North Africa. Ports such as Rotterdam and Hamburg are building terminals and ammonia cracking facilities to accommodate these flows. Within Europe, a hydrogen transmission network is taking shape. The European Hydrogen Backbone envisions at least 6,000 km of dedicated pipelines by 2030, many converted from natural gas lines. The Netherlands expects a national backbone linking Rotterdam, and major industrial areas by 2030 [3], with cross-border links like DRC.
Fuel cell technology will expand in buses, trucks, trains, and maritime. By 2030, tens of thousands of fuel cell vehicles could be on European roads. Hydrogen-powered trains are already running in Germany, France, and Italy; fuel cell buses may become standard in urban fleets. In shipping, hydrogen or ammonia-fuelled vessels could debut on short-sea routes.
Sector coupling may advance offshore wind-to-hydrogen projects could circumvent power grids, sending hydrogen ashore via dedicated pipelines. Some gas turbines in the Netherlands, Germany, and Italy can co-fire hydrogen, aiming for 100% hydrogen in the future. A more defined hydrogen market may arise, featuring transparent pricing at hubs like Rotterdam. Digital tools (IoT, blockchain) will optimize hydrogen distribution [20]. By 2030, hydrogen could be a common element in energy planning, tracked alongside oil and gas prices.
Looking to 2050 – Widespread Adoption and System Transformation
If the EU meets its climate neutrality goals, hydrogen and its derivatives may become ubiquitous by mid-century. Projections suggest hydrogen could supply around 10% of EU final energy by 2050 [1]. Global models, including IEA Net Zero and IRENA 1.5°C, estimate 12–20% worldwide [5]. This points to massive volumes and terawatt-scale electrolysis. IRENA’s 1.5°C scenario expects 4–5 TW of electrolysers worldwide by 2050 [5], complemented by low-carbon “blue” hydrogen from SMR+CCS or pyrolysis where renewables are limited.
IRENA’s 1.5 °C scenario projects 4–5 TW of electrolysers worldwide by 2050, supplying 12–20 % of global final energy.
Europe’s hydrogen infrastructure could mirror today’s gas network, with thousands of kilometres of dedicated lines and vast storage in salt caverns or depleted fields. The European Hydrogen Backbone envisions ~20,000 km by 2040+, possibly expanding further by 2050. Seasonal storage would be essential, harnessing excess summer solar or wind generation as hydrogen to be used for winter heating and power. In some regions, gas distribution systems might carry blended or pure hydrogen for HT industrial processes, heavy transportation, or limited building heating needs.
By 2050, sector integration could be seamless: green hydrogen powers steel mills, with oxygen byproducts used in chemical syntheses, and waste heat channelled to district heating. Green ammonia from these industrial hubs could supply agriculture, closing the loop between energy and food production. Hydrogen-based fuels might dominate heavy trucking and rail, and possibly aviation and shipping for long-distance routes. Airbus’s hydrogen-powered aircraft, planned around 2035, could be widespread by 2050 if key challenges are overcome.
Emerging technologies may reach maturity: solid oxide electrolysers and reversible fuel cells could achieve high efficiency in power-to-hydrogen-to-power cycles, acting as largescale storage systems. Ammonia, methanol, or synthetic methane might become dominant carriers, linking renewable-rich regions (Australia, Middle East, Africa) to demand centres (Europe, East Asia). The Netherlands and EU, as technology and logistics leaders, could host import terminals, re-export hydrogen, and export advanced services.
Digital oversight will likely be pervasive: AI-driven systems could predict renewable output, dynamically adjusting electrolyser operations Europe-wide. Industrial demand might shift in real-time to align with hydrogen availability, creating an “energy internet” that synchronizes electrons and molecules. End-use devices, such as fuel cell combined heat and power units, could communicate with the grid to optimize consumption.
Policy mechanisms like carbon pricing and emissions standards would supplant direct subsidies by 2050, making hydrogen competitive in its core applications. Certification requirements should ensure only low-carbon hydrogen circulates, potentially reinforced by an international framework or “Global Hydrogen Agreement.” With net-zero targets, fossil fuels without carbon capture may be phased out, removing competition for hydrogen in many sectors.
In the Netherlands specifically, one can imagine 2050: the country has a fully decarbonized power sector (mostly offshore wind and some nuclear, plus hydrogen turbines for backup), a national hydrogen grid carrying hydrogen to industrial clusters in Rotterdam, Zeeland, Limburg and supplying heavy transport fuelling stations along highways.
By 2050, the Dutch petrochemical industry has reinvented itself to produce sustainable fuels and materials using green hydrogen and captured CO₂ for synthetic hydrocarbons. Effectively, traditional oil refining could be replaced by “electro-fuel” refining.
The major Dutch ports, instead of oil and coal, handle ammonia, methanol, and hydrogen imports, with Rotterdam possibly re-exporting to hinterland countries. Dutch gas storage sites in Groningen may serve as Europe’s hydrogen storage reservoirs, providing seasonal supply. The workforce has transitioned – former oil platform engineers might now operate offshore hydrogen production platforms or maintain wind-to-hydrogen islands in the North Sea.
Of course, this vision hinges on many uncertainties – the pace of technology, societal acceptance, global economic conditions, etc. There is also a possibility of negative outcomes if hurdles aren’t overcome: hydrogen might remain limited if costs stay high or if policy support wanes. Competing solutions (like advanced batteries or biofuels or direct electrification) could outpace hydrogen in some areas, narrowing its role. Nonetheless, most deep decarbonization analyses converge on hydrogen being indispensable for certain sectors, so a future with significant hydrogen use is very likely.
In conclusion, the period up to 2030 is about laying the foundation – scaling up, driving down costs, building initial networks and markets. The period from 2030 to 2050 is about full-scale deployment and integration, where hydrogen transitions from a niche solution to a mainstream, global energy carrier on par with electricity in importance. The EU and Netherlands’ actions today will greatly influence whether this future becomes a reality and whether they reap the economic and environmental rewards.
10.6 CONCLUSION
Hydrogen and emerging RECs stand at the nexus of technology, policy, and markets in the clean energy transition. In the Dutch and EU context, evolving frameworks—such as carbon pricing mechanisms like the ETS and CBAM that internalize climate costs, streamlined permitting rules, safety standards, and certification schemes are removing barriers to large-scale deployment. Meanwhile, technological advances in electrolyser and fuel cell design, along with digital integration, are lowering costs and improving efficiency. Market creation tools help bridge the initial “valley of death,” while workforce development efforts turn a skills gap into job opportunities that boost public acceptance.
The Netherlands illustrates how a country can position itself within the hydrogen economy: it is developing a national hydrogen network, investing in offshore wind-to-hydrogen projects, pioneering certification, and integrating hydrogen into industrial planning. Even setbacks like the Delta Corridor delay highlight the need for holistic coordination in policy, spatial planning, and community engagement. At the EU level, the CHP, IPCEI initiatives, and the Hydrogen Strategy’s roadmap align policy, technology, and markets. This creates a reinforcing cycle: robust policies stimulate market demand, which justifies investment in technology and reduces costs, enabling further policy ambition and wider market adoption.
By 2030, large-scale electrolysis, hydrogen use in trucks and industry, green ammonia trade routes, and “hydrogen valleys” may operate as blueprints. By 2050, hydrogen could rival natural gas’s current role, underpinning a net-zero European economy with interconnected electricity and molecule networks. If the challenges outlined here are addressed, hydrogen and its sibling carriers can deliver not only climate benefits but also industrial renewal and energy resilience for decades to come.
10.7 REFERENCES
1. European Commission (2025). “Hydrogen.” Energy Topics – EU’s Energy System, Brussels. (Accessed via energy.ec.europa.eu) [Hydrogen]
2. European Court of Auditors (2024). “The EU’s industrial policy on renewable hydrogen” (Special Report 11/2024). Luxembourg. [Special report 11/2024: The EU’s industrial policy on renewable hydrogen]
3. IEA – International Energy Agency (2024). “The Netherlands Energy Policy Review 2024.” Paris. [The Netherlands 2024]
4. CEN-CENELEC (2023). “Roadmap on Hydrogen Standardisation.” European Clean Hydrogen Alliance Working Group on Standardisation. [ROADMAP ON HYDROGEN STANDARDISATION]
5. IRENA – International Renewable Energy Agency (2022). “Hydrogen: A renewable energy perspective.” Abu Dhabi.[Hydrogen]
6. Offshore Energy (2022). “Europe’s first green hydrogen certificates issued in the Netherlands.” News article, 25 Oct 2022. [Europe's first green hydrogen certificates issued in the NetherlandsOffshore Energy]
7. Lichner, C. (2024, March 21). Electrolyser prices – what to expect. pv magazine. [Electrolyser prices – what to expect]
8. International Energy Agency. (n.d.). Electrolysers. IEA. [Electrolysers]
9. Krishnan, S., Koning, V., de Groot, M. T., de Groot, A., Granados Mendoza, P., Junginger, M., & Kramer, G. J. (2023). Present and future cost of alkaline and PEM electrolyser stacks. International Journal of Hydrogen Energy, 48(83), 32313–32330.
10. Hydrogen Insight. (n.d.). Bottleneck: Hydrogen electrolysers could require more of the world's platinum reserves than previously thought. Hydrogen Insight. Retrieved April 8, 2025, from [https:// www.hydrogeninsight.com/electrolysers/bottleneck-hydrogen-electrolysers-could-require-moreof-the-worlds-platinum-reserves-than-previously-thought/2-1-1511811]
11. VoltaChem. (2022, October 24). A factor of 200 reduction of iridium catalyst for PEM electrolysers is demonstrated to be possible keeping on average 1/3 of performance. [https://www.voltachem. com/news/a-factor-of-200-reduction-of-iridium-catalyst-for-pem-electrolysers]
12. Parkes, R. (2024, November 7). ‘Cost reduction’ | UK hydrogen electrolyser maker ITM cuts iridium content in its PEM models Hydrogen Insight. [https://www.hydrogeninsight.com/electrolysers/cost-reduction-uk-hydrogen-electrolyser-maker-itm-cuts-iridium-content-in-its-pemmodels/2-1-1735948]
13. Peters, C. (2023, August 9). How much green hydrogen will Europe’s industry need in 2050? Fraunhofer Institute for Systems and Innovation Research ISI. [https://www.isi.fraunhofer.de/en/ blog/2023/europa-energiesystem-2050-wasserstoff-industrie.html]
14. Osborne Clarke. (2024, October 10). Regulation (EU) 2024/1789 and its impact on the Renewable, Natural Gas and Hydrogen Markets. Lexology. [https://www.lexology.com/library/detail. aspx?g=c8baa589-630f-4363-89db-c307c20fea96]
18. CIC energiGUNE (2023). “Betting on green hydrogen to fulfil employment growth.” Blog post, Jan 24, 2023. [Betting on green hydrogen to fulfil employment growth | CIC energiGUNE]
20. Lexology (2024). “EU Regulation 2024/1789: Internal markets for renewable gas, natural gas and hydrogen.” [Summary of Gas Decarbonisation Package]
Chapter 11
Conclusion: The Road Ahead to a Low-Carbon Future
11.1 SUMMARY OF KEY FINDINGS
The journey through this book has highlighted that achieving a low-carbon energy system will require a portfolio of RECs working in tandem. No single technology can decarbonize all sectors; instead, hydrogen, ammonia, methanol, LOHCs, and iron each offer unique strengths that complement one another in the transition to net-zero emissions. A recurring theme is the importance of complementarity; these carriers are not competitors but allies, each suited to different applications and often more effective together than alone.
As noted by the IREA, hydrogen and electricity are “complementary in the energy transition,” enabling renewable power to reach sectors where direct electrification is difficult [1].
In practice, this means using direct electrification wherever feasible and deploying alternative carriers in the hard-to-electrify sectors.
One key finding is that hard-to-electrify sectors will rely on these alternative carriers. Direct use of renewable electricity in these sectors is often impractical due to technical limitations. Here, hydrogen and its derivatives step in as low-carbon substitutes for fossil fuels [6]. The latest IPCC report underscores that “alternative carriers such as hydrogen and ammonia must substitute for fossil fuels in sectors where electrification will be difficult” [2]. Each carrier covered in this book offers distinct advantages for specific uses:
• Hydrogen (H₂): Hydrogen is a versatile energy carrier that can be used directly as a fuel or feedstock. It produces no CO₂ at point of use and can be made from water via electrolysis using renewable power. Hydrogen is crucial for decarbonizing existing industrial uses by replacing grey hydrogen with green [1]. It also enables new pathways in industries like steel, where hydrogen can reduce iron ore in place of coal. In transportation, hydrogen FCEVs complement battery EVs by serving high-duty, long-range applications where batteries are less practical [1]. Moreover, hydrogen can be stored in large quantities (e.g. in salt caverns or pressurized tanks), offering a means of seasonal energy storage to balance intermittent renewables [1]. A limitation of hydrogen is its low volumetric energy density as a gas, meaning that for some applications it must either be compressed, liquefied, or chemically converted to other carriers for efficient transport.
• Ammonia (NH₃): Ammonia, a compound of hydrogen and nitrogen, emerged as a critical energy-dense carrier and carbon-free fuel. It is already produced at scale and has well-established transport and storage infrastructure. Green ammonia can fuel shipping and power generation without CO₂ emissions. Ammonia contains 17.6% hydrogen by weight and can be stored as a liquid under modest pressures or refrigeration, making it attractive for transporting hydrogen energy over long distances. Shipping is a focal point: ammonia can be used in maritime engines or fuel cells, offering a viable path to decarbonize international shipping. In addition, co-firing ammonia in thermal power plants or using it in gas turbines can provide dispatchable power. The trade-off is that ammonia is toxic and requires careful handling and burning it can produce NOx emissions that must be managed. Nonetheless, studies identify ammonia as one of the most promising hydrogen-based carriers ready for large-scale use, alongside methanol and synthetic methane.
• Methanol (CH₃OH): Methanol is a liquid organic chemical that can be produced from hydrogen and captured CO₂ – making it a potential carbon-neutral fuel and feedstock. As a liquid at ambient temperature and pressure, methanol is easy to store, transport, and use in existing infrastructure. This makes it a compelling option for transportation fuels, especially for shipping and potentially aviation via conversion to synthetic jet fuel. In fact, the shipping industry is rapidly embracing green methanol. Methanol can also be used in road transport and is a valuable feedstock for the chemical industry (to produce plastics, solvents, etc.), thereby integrating into industrial value chains as a circular carbon carrier. By chemically recycling CO₂ into methanol and then reusing it, a methanol economy can contribute to a closed-carbon-loop in tandem with bio-based and direct air capture technologies. A key insight here is that carbon-containing carriers like methanol (and synthetic hydrocarbons) will likely play an important role in aviation and chemicals where a carbon molecule is needed, even as we strive for net-zero emissions.
• LOHCs: LOHCs are hydrogen-rich organic liquids that can absorb and release hydrogen through chemical reactions. They allow hydrogen to be handled in a liquid form at ambient conditions, leveraging existing fuel logistics (tankers, rail, storage tanks) with no boil-off losses. LOHCs offer a safe and convenient means of transporting hydrogen energy over long distances or distributing it in urban areas without new pipeline infrastructure [3]. The chapters in this book noted that LOHC technology trades efficiency for flexibility – the hydrogenation/dehydrogenation steps require energy and catalysts, resulting in round-trip efficiency penalties, but the benefit is a liquid fuel that is stable and non-explosive, simplifying storage and transport. LOHCs may fill niche roles in the hydrogen economy, such as buffer storage, smallscale distribution by truck, and early-phase hydrogen import/export before dedicated pipelines or ammonia infrastructures are fully established [4].
• Iron (Fe): Perhaps the most novel carrier discussed is the iron fuel cycle. This concept uses fine iron powder as a recyclable fuel: when oxidized to iron oxide, it releases heat that can produce high-temperature steam or power, and the rust can then be renewably reduced back to iron using hydrogen for reuse. Iron thus serves as a closed-loop energy carrier that can store energy in a solid, carbon-free form. Iron has an energy density by volume comparable to fossil fuels – for instance, 1 cubic meter of iron powder contains about as much energy as 11 cubic meters of hydrogen gas at high pressure. Moreover, the only by-product of iron combustion is iron oxide (rust), which, as a solid, is contained and then regenerated. This carrier shines for high-grade heat applications and possibly power generation, where the direct combustion of iron powder can reach high temperatures without greenhouse gases. Its round-trip efficiency depends on the hydrogen used to regenerate the iron, but because no cryogenics or compression are needed for storage, it has low energy loss in standby. Iron’s abundance and non-toxicity are additional perks. The key insight is that iron could complement gaseous and liquid carriers by providing a storable, transportable fuel for industries requiring flame temperatures and by offering seasonal storage.
A unifying finding across these carriers is the value of flexibility and sector coupling. By converting renewable electricity into different carriers, we can extend the reach of clean energy into every corner of the economy. Hydrogen can link the power sector with industry and mobility; ammonia and methanol can connect the energy sector with agriculture (fertilizers) and international transport; LOHCs and metal fuels can create new links in supply chains leveraging existing assets. This diversity adds resilience to the energy system – if one pathway faces constraints, another can fill the gap. Indeed, a recent study comparing hydrogen carriers concluded that no single carrier or supply source will dominate; multiple options will likely co-exist, allowing decisions based on regional strengths and needs rather than one-size-fits-all economics [5]. This complementarity enables what we might call a “system of systems”, where electricity, molecules, and even solid fuels interplay to drive deep decarbonization.
Importantly, the book’s chapters showed that integrating these carriers is not just theory –it is starting to happen now. Across Europe and the Netherlands, we see early signs of the multi-carrier energy future: industrial clusters planning to switch to green hydrogen, ports preparing ammonia import terminals and LOHC facilities, shipping companies building methanol- and ammonia-fuelled ships, and pilot projects for iron fuel in industrial heat.
These examples reinforce the book’s central message: a low-carbon future will be built on a tapestry of solutions, woven together by smart integration.
Figure 20 A conceptual illustration of an integrated net-zero energy system leveraging diverse renewable energy carriers
The final section of this chapter outlines a call to action, recognizing that achieving such an integrated low-carbon energy system will demand concerted efforts by researchers, policymakers, industry, and civil society in the coming years.
11.2 CALL TO ACTION FOR STAKEHOLDERS
The transition to a LC future powered by complementary RECs will not happen automatically. It requires deliberate and coordinated action from every segment of society. As we conclude, it is worth distilling the insights of this book into key recommendations for those who have the power to drive change. Researchers, policymakers, industry actors, and civil society each have pivotal roles to play in turning the multi-carrier vision into reality. In fact, a coalition of Belgian and Dutch companies studying hydrogen imports framed their findings as “an open call for action to public and private stakeholders to forge partnerships” for pilot projects and market development [7].
Inspired by that spirit, we present a call to action for each stakeholder group:
STAKEHOLDER KEY ROLES AND RECOMMENDATIONS
Researchers & Innovators
Policymakers & Regulators
Advance technologies and cut costs across all carriers—improving electrolysers, fuel cells, catalysts, ammonia crackers, methanol synthesis, LOHCs, and iron fuel cycles. Cross-disciplinary R&D is key to tackling integration challenges, from safe hydrogen storage to efficient conversions. Real-world pilots—like hydrogen in steel, ammonia in shipping, or iron burners in industry—are vital to validate scale-up. Open collaboration and independent assessments of efficiency and sustainability will ensure responsible deployment.
Establish a strong policy framework to drive investment and deployment of energy carriers. Key tools include carbon pricing, subsidies or CfDs for early projects, and mandates for low-carbon fuels. Public funding should support shared infrastructure—pipelines, terminals, storage—as essential utilities. Safety standards, certification schemes, and interoperability regulations must be harmonized. Governments should invest in workforce training and foster international agreements on green fuel trade, certification, and R&D. Clear, long-term signals and the removal of regulatory barriers will give industry the confidence to scale.
Industry & Investors
Accelerate deployment through investment and strategic collaboration. Highemitting industries should lead by piloting renewable carriers—hydrogen in steelmaking, ammonia/methanol in shipping, hydrogen refuelling for logistics. Energy companies must diversify into green hydrogen and power-to-X. Industry consortia and public-private partnerships can de-risk first-of-a-kind projects. Financial institutions should support scale-up via green bonds, sustainability-linked loans, and infrastructure funding. Forward contracts and offtake agreements ensure demand certainty, enabling producers to invest. Early adopters will shape markets and standards. Transparency and lifecycle sustainability must guide implementation to ensure true climate impact.
Civil Society & Academia
Support the energy transition by aligning it with societal values. Civil society, academics, and NGOs must inform the public, counter myths, and advocate for climate action. Community engagement is vital for fair project planning and acceptance, especially in regions affected by fossil phase-out. Education systems should train the future workforce for hydrogen and e-fuel technologies. Sharing success stories and emphasizing health, climate, and energy benefits will build public trust. Civil society should also monitor lifecycle impacts to ensure sustainability. A well-informed, engaged public is key to a just and resilient transition.
In conclusion, the road ahead to a low-carbon future is challenging but now clearly charted. The various chapters of the book have shown that we have at our disposal a powerful toolbox of renewable energy carriers – each a piece of the puzzle for decarbonizing our modern world. By summarizing their roles and envisioning their integration, we see that a holistic approach can unlock synergies across sectors and countries. The challenge now is execution. It falls on the collective will of experts, engineers, lawmakers, business leaders, and citizens to turn this vision into reality. The coming decades must be a time of unprecedented innovation, investment, and cooperation. As the Hydrogen Import Coalition urged, a diversified portfolio of projects should be rapidly implemented to gain experience and drive down costs [7]. Each successful pilot builds confidence and knowledge to fuel the next.
A world powered by clean, complementary energy carriers is not only possible—it is already in sight.
The Netherlands and the EU stand poised to lead by example, showcasing how an advanced economy can transform its energy basis while maintaining prosperity and reliability. The choices made in the 2020s and 2030s will determine whether we achieve climate targets and secure a liveable planet. This concluding chapter makes it evident that the tools for a net-zero energy system are at hand; what remains is to deploy them at scale and integrate them wisely. As we move forward, let this knowledge inspire a sense of urgency but also optimism: a world powered by clean, complementary energy carriers is not only possible, it is already in sight. By acting decisively and collaboratively, we can drive the road ahead toward a sustainable, low-carbon future for the Netherlands, the EU, and the world.
11.3 REFERENCES
1. International Renewable Energy Agency. (2018). Hydrogen from renewable power: Technology outlook for the energy transition. Abu Dhabi: Author. Retrieved from [https://www.irena.org/ publications/2018/Sep/Hydrogen-from-renewable-power]
2. World Resources Institute. (2022, April 5). 6 takeaways from the 2022 IPCC climate change mitigation report. World Resources Institute. [https://www.wri.org/insights/ipcc-report-2022mitigation-climate-change]
3. Axens. (n.d.). LOHC, a compelling hydrogen transport and storage solution. Retrieved April 8, 2025, from [https://www.axens.net/expertise/low-carbon-hydrogen/lohc-compelling-hydrogentransport-and-storage-solution]
4. International Renewable Energy Agency. (2022). Global hydrogen trade to meet the 1.5°C climate goal: Part I – Trade outlook for 2050 and way forward. Abu Dhabi: Author. Retrieved from [https:// www.irena.org/publications/2022/Jul/Global-Hydrogen-Trade-Outlook]
5. Hampp, J., Düren, M., & Brown, T. (2023). Import options for chemical energy carriers from renewable sources to Germany. PLOS ONE, 18(2), e0281380. [https://doi.org/10.1371/journal. pone.0281380]
6. Intergovernmental Panel on Climate Change (IPCC). (2022). Climate Change 2022: Mitigation of Climate Change (Working Group III Contribution to the IPCC Sixth Assessment Report). Geneva: IPCC.
7. Hydrogen Import Coalition. (2020). Shipping sun and wind to Belgium is key in climate neutral economy. WaterstofNet. Retrieved from [https://www.waterstofnet.eu/_asset/_public/ H2Importcoalitie/Waterstofimportcoalitie.pdf]
Acknowledgements
I would like to take a moment to express my deepest appreciation to those who have supported and inspired me along the journey leading to this special day.
Firstly, my heartfelt thanks go to Avans and MNEXT for their unwavering support and the warm welcome I have received since joining. Your belief in my vision and consistent encouragement have provided me with the confidence and foundation to pursue this path with passion.
I extend my sincere appreciation to Ralph Simons, MNEXT Director, for warmly welcoming me into this role and consistently supporting my growth within the research group. Your support and openness have created a space where I’ve been able to grow both professionally and personally, without hesitation or fear.
Special gratitude goes to Jack Doomernik, Lector of Smart Energy, whose invaluable coaching and guidance have had a significant impact on my journey. Your wisdom and dedication have greatly supported me in my role, and your mentorship has been truly instrumental.
To the lectors of MNEXT and my colleagues in the Renewable Energy Carriers research group, thank you for your support and collaborative spirit. Your insights, feedback, and company have enriched my experience immensely.
My appreciation goes to Marlies Schets and André van de Wijdeven for their exceptional creativity and persistence in designing the symbolic chain for this event. The thoughtful discussions, innovative brainstorming sessions, and shared effort resulted in a beautiful and meaningful final design.
I am also grateful to Jobert Ludlage and the talented student team for their outstanding support in preparing the iron burner demonstration for this inauguration.
Special thanks to Kim Jones and Wendy van Rijsbergen for your tireless support throughout the preparation of my inauguration. Your meticulous attention to detail, patience, and dedication have been indispensable in making every arrangement seamless. Without your support, this would not have been possible.
My sincere gratitude goes to Koen Haans from Witteveen+Bos for your continuous support over the years, accommodating my academic ambitions and giving me the space I needed to complete this journey. Your flexibility and trust have truly made a meaningful difference.
Above all, my deepest gratitude belongs to my family, particularly my wonderful wife, Narges, and beloved children, Ariwan and Adrian. Your endless love, patience, and understanding have been my greatest strength. Without your unwavering support, none of this would have been possible.
Thank you all for being part of this remarkable journey.
About the Chain
This text is drafted by the chain design team, consisting of Marlies Schets and André van de Wijdeven:
“The research of Renewable Energy Carriers serves as the primary inspiration for this chain, where we explore innovative ways to store and transfer energy. One of the research topics focuses on the charging and discharging of iron powder as energy carriers, which directly provided us a material to work with. Additionally, the focus was on visually representing the various energy carriers and their molecules. As a result, we used molecular structures as the foundation.
The chain's structure is functional and dynamic, with molecules acting as hinges that are interconnected through ball-and-socket joints, symbolizing the way molecules interact in real-world.
The polygonal shapes of the links are a reference to molecular structures, while also adding volume and depth to the design, intensifying the visual impact of the chain.
More than just an aesthetic element, the design also carries a deeper meaning, symbolizing a circular process. The chain clearly represents the cycle of charging and discharging, where the links shift from a charged (iron) to a discharged (iron oxide) state. This transformation is visually highlighted by the contrast between the closed (charged) and open (discharged) polygonal forms.
In a metaphorical sense, the chain itself becomes a carrier of energy, mirroring the very concept of energy carriers in real-world applications. Through this design, we aim to not only capture the essence of the research but also bring it to life in a visually compelling way, making the invisible processes of energy storage and transfer tangible.”
In May 2025, I delivered my inaugural address as Lector of Renewable Energy Carriers, articulating the pivotal role of hydrogen and emerging energy carriers in achieving climate goals. Charting a Low-Carbon Future Energy System: The Rationale for Hydrogen and other Emerging Energy Carriers arises from this academic milestone, expanding this vision into a scholarly analysis. The book examines hydrogen and hydrogen-based carriers—such as ammonia, methanol, liquid organic hydrogen carriers (LOHCs), and metal fuels—and explains their essential roles in low-carbon energy systems. It explains how these carriers can store intermittent renewable energy and decarbonize sectors that are otherwise difficult to electrify, thus underpinning a flexible, resilient, and secure energy transition.
Positioned within the context of Dutch and European climate policy, the work aligns its technical discourse with initiatives such as the EU’s “Fit for 55” Package and the Netherlands’ Climate Act, which mandate steep emissions reductions and route to climate neutrality by mid-century. Insights from the Renewable Energy Carriers (REC) Research Group infuse the discussion, reflecting our strategic focus on green hydrogen, e-fuels, and novel carriers and underscoring the multifaceted approach needed for the energy transition. Through a formal yet accessible narrative, I bridge theory and practice by drawing on research findings and REC-led case studies to inform strategic decision-making. It is my hope that this volume will prove a useful resource for scholars, policymakers, and professionals committed to advancing the energy transition toward a sustainable, low-carbon future.
Saleh Mohammadi Professor Renewable Energy Carriers
