Issuu

Summer 2026

PAGE 09

THE WORKHORSE OF BLUE IS NAMED SYNCOR™

Maximize your mega-scale blue hydrogen and ammonia production with our SynCOR™ technology. Achieve more than 99% carbon recovery, unmatched efficiency, and the lowest levelized cost of hydrogen. Powered by our industrially proven autothermal reforming, SynCOR is a next-generation technology for today – and tomorrow. Step into the future with SynCOR today!

Summer 2026 Volume 5 Number 2 ISSN 2977-1927 03 Comment

33 Engineering a solution for a

decarbonised grid

04 Shifting hydrogen into action in Asia

Karl Wygant, Enver Karakas, and Stephen Todd Omatick, Ebara Elliott Energy, and Rainer Kurz, RKSBenergy, discuss the engineering of centrifugal hydrogen compressors and pumps for a decarbonised energy grid.

Mark Elliot, Xodus, reviews the current progress being made to develop hydrogen production in the Asia-Pacific region.

09 Advancing ATR burners through

37 Speeding into a new age of

additive manufacturing

hydrogen compression

Giovanni Genova, CASALE, Switzerland, provides an overview of current developments in hydrogen and syngas production through oxidative methods.

Sébastien Kohler and Samuel Stutz, Greene Tweed, Switzerland, analyse how a new technological development in high-speed composite impeller design can address the challenge of hydrogen compression.

13 Material engineering in electrolyser systems

Luca Frigerio, SAATI, examines the role of advanced woven meshes in electrolyser systems.

41 The quiet innovations

Nico Schmaeling, John Crane, UK, discusses the innovations behind sealing solutions in hydrogen pumps and compressors.

17 A new mode of electrodes

Abigail Lister, M-Spin, UK, explains how ultra-high surface area nanofelts can be used to improve electrolyser efficiency while reducing costs.

44 The beating heart of Europe’s

hydrogen revolution

Andrés Hernando, Hiperbaric, discusses how Spain’s Castilla y León is leveraging a 96% green grid to build a €385 million continental hydrogen hub.

20 From cell signals to site decisions

Stefano Andreola and Alberto Lando, Nextchem (MAIRE), outline strategies to digitalise alkaline electrolysis using a cell monitoring system and real-time optimiser.

49 Building a future hydrogen system

Chloe Tindale, Air Products, UK, explores real-world deployments of hydrogen in transport and infrastructure projects, highlighting how policy frameworks can support its scale up.

25 The digital path from hydrogen ambition

to delivery

G. Balaji, ABB Energy Industries, outlines why digitalisation is a proven lever for managing the power costs of green hydrogen and turning climate ambition into a commercial reality.

53 Understanding when hydrogen trucks

deliver real value

Tim Murray, HTEC Engineering Services, analyses the cost of hydrogen truck operations, identifying the use cases where hydrogen offers the best outcome.

29 Why the future of energy demands

smarter automation

Mark Richards, Beckhoff, UK, explains why producing, storing, and using hydrogen safely and efficiently requires flexible control solutions that can operate in demanding environments.

57 Moving beyond ‘black paper’

Dr Jason Morgan, AvCarb, USA, outlines the steps for how a properly designed gas diffusion layer can remove bottlenecks and help keep up with a changing industry.

61 From power to propulsion: unlocking the

hydrogen economy

Edward Cubero, Amogy, USA, outlines how ammonia’s role as a hydrogen carrier can create opportunities for wide scale hydrogen adoption.

CASALE is a global partner in the chemical industry, offering integrated technologies, engineering, contracting and construction solutions for over a century. Committed to a sustainable, greener future, its unwavering dedication drives the group to innovate, creating solutions that harmonise industry progress with environmental responsibility. Leveraging on its comprehensive technology portfolio, CASALE is among the few licensors that can provide the entire production chain of nitrogenous and phosphate fertilizers (ammonia, urea, nitric acid, nitrates, and phosphates), as well as melamine, methanol, and syngas.

Join the conversation follow @Hydrogen_Review

join

@HydrogenReview

Global Hydrogen Review

Copyright© Palladian Publications Ltd 2026. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

CBP019982

ZEV R

Willow Munz Editorial Assistant Managing Editor James Little

james.little@palladianpublications.com

Senior Editor Callum O'Reilly

callum.oreilly@palladianpublications.com

Deputy Editor Oliver Kleinschmidt

oliver.kleinschmidt@palladianpublications.com

Editorial Assistant Willow Munz

willow.munz@palladianpublications.com

Sales Director Rod Hardy

rod.hardy@palladianpublications.com

Sales Manager Chris Atkin

chris.atkin@palladianpublications.com

Production Manager Kyla Waller

kyla.waller@palladianpublications.com

Head of Events Louise Cameron

louise.cameron@palladianpublications.com

Digital Events Coordinator Merili Jurivete merili.jurivete@palladianpublications.com

Digital Content Coordinator Kristian Ilasko kristian.ilasko@palladianpublications.com

Digital Administrator Nicole Harman-Smith

nicole.harman-smith@palladianpublications.com

Video & Motion Graphics Amélie Meury-Cashman amelie.meury-cashman@palladianpublications.com

Events Coordinator Chloe Lelliott

chloe.lelliott@palladianpublications.com

Admin Manager Laura White

laura.white@palladianpublications.com

Editorial/advertisement offices: Palladian Publications 15 South Street, Farnham, Surrey GU9 7QU, UK Tel: +44 (0) 1252 718 999 www.globalhydrogenreview.com

s the year races by, a few major sporting events have taken centre stage in the headlines: from the recent Monaco Grand Prix to the 2026 World Cup already underway. Whilst global energy markets are still grappling with the disruptions caused by the Middle East crisis, these events retain a unique ability to capture global attention. And at the intersection of sustainability and sport, a new player is steadily gaining traction: hydrogen-fuelled motor cars. Though operating on a much smaller stage, hydrogen motorsport is beginning to emerge as a strong contender in the race for a low-carbon future. With high energy density and rapid refuelling, hydrogen offers an attractive alternative to conventional combustion engines on the race track. Unlike battery electric vehicles, these cars can be refuelled in a matter of minutes, making them ideal for endurance racing.1 Additionally, in fuel cell vehicles, the only direct by-product is water vapour, meaning carbon emissions are almost completely eliminated. This method has already influenced Toyota Motor Corp., which has developed a liquid hydrogen-powered race car showcased at 24 Hours of Le Mans.2 The vehicle stores hydrogen in liquid form, before supplying it to a modified combustion engine, helping engineers explore the potential of hydrogen under the extreme demands of endurance racing. Whilst Formula 1 receives the most media coverage and highest global viewership, hydrogen racing is quietly beginning to move into the fast lane. In October 2025, the first hydrogen powered motorsport championship, the FIA Extreme H World Cup, was launched in Qiddiya City, Saudi Arabia. And it’s now returning to the grid in 2026. This race will take place against the backdrop of the Saudi Desert, as eight teams compete across two time trials followed by a series of head-to-head rounds. But will hydrogen make an appearance in Formula 1 itself? For now, that remains unlikely. Formula 1 has already committed to sustainable fuels and hybrid technologies as part of its 2026 regulations, meaning hydrogen is unlikely to be incorporated in the near term.3 Aside from this, another potential hurdle may lie in the nature of the show itself. Anyone who’s an avid watcher of Formula 1 will be aware that the sport is as much about sound as it is about speed, and hydrogen-powered vehicles operate with much less of the dramatic engine noise that fans have become accustomed to. While this is far from the main reason hydrogen has yet to breach Formula 1, it highlights a broader challenge in the roadmap to sustainable motorsport: preserving the spectacle that keeps viewers hooked. Whilst hydrogen motorsport remains a niche sector, competitions like Extreme H demonstrate hydrogen’s growing presence in both experimental and mainstream fields. But hitting the brakes on motorsport, this issue of Global Hydrogen Review will keep readers up to speed with developments across a wide range of sectors, from electrolysers to digitalisation, with plenty more to exhaust on the subject of mobility later on. 1. https://www.prv-engineering.co.uk/how-hydrogen-race-cars-are-transforming-the-future-ofmotorsport/ 2. https://www.globalhydrogenreview.com/hydrogen/08062026/toyotas-hydrogen-powered-carenters-race/ 3. https://www.formula1.com/en/latest/article/2026-regulations-explained-all-you-need-toknow-about-f1s-advanced.4h53Szn4Z3VsD6rGcR3LtU

Mark Elliot, Xodus, reviews the current progress being made to develop hydrogen production in the Asia-Pacific region.

ver the past few years, hydrogen’s role in the global energy transition has become clear, notably in the case of the high-consuming and high-producing Asia-Pacific (APAC) region. While ambition around low-carbon hydrogen remains strong, the narrative in 2026 has become noticeably more pragmatic, and importantly, more delivery-focused. The past year has seen a shift away from the early optimism that characterised many national hydrogen strategies. The early years of the hydrogen boom were characterised by gigawatt scale announcements and vast export ambitions. After several years defined by ambition and large scale announcements, the industry is entering a more mature phase with attention shifting towards smaller, phased projects that provide clearer use cases and build practical foundations for a viable hydrogen economy.

Rather than signalling a slowdown, this switch reflects a natural evolution. As the sector moves from concept to execution, developers and governments alike are increasingly focusing on the projects and policies that can deliver real progress in the near-term.

A material step forward

For much of the past decade, the hydrogen sector has been dominated by announcements. Governments have launched national strategies, companies have signed memorandums of understanding (MoU), and developers have proposed large scale facilities designed to produce hydrogen at unprecedented scale. While these signals of intent remain important, the industry is more commonly looking for evidence that projects are progressing beyond feasibility studies and into construction and operation.

Across the APAC region, there are early indications that this transition is starting to take place. In China, several projects have already reached meaningful production levels, with numerous plants producing more than 10 000 tpy of hydrogen. Meanwhile, developments such as Envision Energy’s Chifeng facility are expected to begin exporting energy later in 2026, marking an important milestone in the commercialisation of integrated hydrogen systems. Although these projects remain relatively modest when compared with the gigawatt scale developments once envisaged, they represent an important step forward. Early production assets are allowing developers to test technologies, while establishing supply chains and gaining the operational experience required for future expansion. This gradual scaling approach is becoming a defining feature of the sector. Rather than attempting to launch enormous projects immediately, many companies are opting for smaller first phases that can demonstrate bankability and create a clearer pathway to larger scale investment.

A more realistic industry outlook

The recalibration of project ambitions is largely driven by the realities of hydrogen economics. While the technology has advanced rapidly, green hydrogen remains significantly more expensive than hydrogen produced from fossil fuels. In many markets, green hydrogen can still cost several times more to produce. This cost gap, as ever, presents a major challenge to developers seeking to secure long-term offtake agreements and attract investment for large scale projects. As a result, developers and policymakers are increasingly focusing on areas where hydrogen can deliver the greatest value. Instead of attempting to deploy hydrogen across every part of the energy system, attention is sharpening towards sectors where alternative decarbonisation options are limited. This evolution is particularly visible in APAC. Several countries that previously promoted large scale hydrogen exports are now prioritising domestic industrial applications as a starting point for market development. Australia provides a clear example of this shift. The country continues to promote large green hydrogen projects through initiatives such as the Hydrogen HeadStart programme, which sees revenue provided for large scale projects through competitive hydrogen production contracts. However, developers are increasingly structuring projects around phased delivery and nearer-term domestic opportunities. This approach reflects a broader recognition that establishing local supply chains and proven use cases is a necessary precursor to scaling export markets.

Focusing on the hardest-to-abate sectors

One of the most notable changes in the hydrogen industry is the growing alignment on specific applications where hydrogen offers clear advantages. Heavy industry has emerged as one of the most promising areas. Processes such as steelmaking, iron production, cement manufacturing, and high-temperature industrial heating are extremely difficult to electrify, making hydrogen an attractive alternative.

GlobalHydrogenReview.com

Summer 2026

In many cases, developers are exploring ways to integrate hydrogen production directly with industrial facilities. By locating production close to the point of consumption, projects can avoid the significant energy losses and costs associated with transporting hydrogen over long distances. This approach is beginning to shape industrial policy in several countries. Initiatives such as the Future Made in Australia Act aim to strengthen domestic processing industries that can utilise low-carbon hydrogen in the production of green metals and other materials. Such strategies highlight a significant opportunity. Hydrogen’s greatest near-term value may lie in decarbonising industrial supply chains rather than replacing conventional fuels across the entire energy system.

Energy security returns to the agenda

Alongside decarbonisation, energy security is once again becoming a major driver of hydrogen policy. The ongoing conflict in the Middle East has highlighted the vulnerability of global energy supply chains. For many countries, reducing reliance on imported fossil fuels is fast becoming an imperative strategic objective. Low-carbon hydrogen and hydrogen-derived fuels could play an important role in addressing this challenge. Hydrogen can be used to produce synthetic fuels such as ammonia or methanol, which can serve as alternatives to conventional hydrocarbons in sectors such as shipping and aviation. In parts of APAC with limited domestic resources but strong demand for liquid fuels, this presents a clear opportunity. Developing local hydrogen production capacity can simultaneously enhance energy security and support decarbonisation goals. As a result, the intersection between energy security and decarbonisation is set to play an increasingly influential role in shaping hydrogen investment decisions.

Growing competition in global export markets

While many countries are focusing on domestic applications in the near term, the long-term vision of international hydrogen trade remains an important part of the global energy transition. Several APAC nations have positioned themselves as potential exporters of hydrogen or hydrogen-derived fuels. However, they face increasing competition from other regions with favourable production conditions. The Middle East, in particular, is emerging as a significant player. Projects such as Fertiglobe’s planned 1 million tpy blue ammonia facility in the UAE, scheduled to enter commercial operation in 2027, demonstrate the scale of ambition in the region. Countries such as Oman are also moving quickly to attract investment. By offering clear development pathways, allocating land to project developers and providing favourable tax incentives, these nations are creating an environment designed to accelerate large scale hydrogen production. The Middle East benefits from several structural advantages too, including access to low-cost natural gas, abundant renewable resources, and proximity to key import markets in Europe and Asia. Subject to the impact of the current conflict,

TDW SHiiELD

™

Double Independent Isolation and Bleed System

Uncompromising safety. Unmatched throughput. The TDW SHiiELD™ System is the safest isolation tool on the market, eliminating emissions with a continuously monitored, leak-proof seal. The integrated bypass reduces flow restrictions, delivering more throughput without additional fittings or hot taps. SHiiELD sets a new industry standard exceeding traditional double block and bleed systems by independently anchoring each pressure boundary ensuring isolation integrity.

See it in action. tdw.red/SHiiELD TM

these factors could allow the region to become a major exporter of low-carbon fuels in the coming decades. For established hydrogen exporters in APAC, this growing competition underscores the importance of maintaining supportive policy frameworks and ensuring projects remain commercially competitive, while offering reliable delivery timelines.

Policy frameworks shaping the market

As with many emerging energy technologies, government policy continues to play a decisive role in determining how quickly hydrogen projects can move forward. Several countries in APAC have introduced subsidy schemes and financial incentives aimed at closing the cost gap between low-carbon hydrogen and conventional fuels. In Japan and South Korea, policy frameworks are designed to stimulate demand by supporting imports of hydrogen and hydrogen-based fuels. Notably, these programmes often focus on emissions intensity rather than the specific production pathway. By allowing both green and blue hydrogen to qualify for support, policymakers aim to rapidly develop the availability of lower-carbon alternatives while maintaining flexibility in how they are produced. Australia is also continuing to expand its support mechanisms. The second round of the Hydrogen HeadStart programme, expected to announce shortlisted projects later in 2026, has lowered the minimum electrolysis capacity threshold in order to encourage a broader range of developments.

Such initiatives reflect the growing recognition that hydrogen markets will require sustained policy support during their early stages of development.

Pragmatism leads the way

While challenges remain, the outlook for hydrogen in APAC remains broadly positive. The technology continues to offer one of the most viable pathways for decarbonising sectors that cannot easily transition to electrification. What has changed is the industry’s understanding of how quickly this transition can occur. Rather than relying on a handful of enormous projects to transform the market overnight, the sector is gradually building the infrastructure and expertise needed to support a future hydrogen economy. Smaller projects developed today can provide valuable operational experience, helping to drive technological improvements and demonstrate commercial viability. Over time, these developments may pave the way for the larger scale deployments that were once expected to emerge more rapidly. APAC will remain central to this process. With a vast industrial base, paired with growing energy demand and active government support, the region is well positioned to shape the next phase of hydrogen development. While the path forward may prove more gradual than early projections suggested, the industry is beginning to take the next step towards execution. In doing so, it is laying the groundwork needed for hydrogen to play a meaningful role in the global energy transition.

Global Hydrogen Review Online

Home to the latest hydrogen news, analysis and events Visit our website today: www.globalhydrogenreview.com

Giovanni Genova, CASALE, Switzerland, provides an overview of current developments in hydrogen and syngas production through oxidative methods.

ydrogen and synthesis gas (syngas) play an increasingly important role in modern industrial processes and in strategies aimed at reducing greenhouse gas emissions. Their relevance spans established chemical production routes as well as emerging applications linked to cleaner fuels and energy systems. As global demand for hydrogen approaches 100 million tpy in 20251 and it is expected that sustainable hydrogen production may reach 14 million tpy in 2030,2 and as regulations tighten around carbon intensity thresholds for energy carriers, attention has turned to production technologies capable of supporting large scale, low‑carbon output. Syngas is used in several industrial sectors, as a precursor or intermediate to bulk chemicals, like ammonia

and methanol, fuels through Fischer-Tropsch, or new processes for sustainable aviation fuel (SAF) production and various refinery and steelmaking operations. As global markets consider lower‑carbon production routes, syngas also appears in discussions around clean energy carriers, blending in pipelines, and new mobility applications. The hydrogen derived from syngas can subsequently be used as a clean fuel, offering a low-carbon energy vector across multiple applications – from mobility and heat to power generation. Notably, the EU has already defined a regulatory threshold for low carbon hydrogen: in Europe, under Commission Delegated Regulation (EU) 2025/2359, hydrogen qualifies as low carbon only if its life-cycle GHG emissions do not exceed 28.2 g CO2e/MJ, ensuring at least

a 70% reduction compared to fossil-based hydrogen, but similar regulations can be founded in most countries.

Technology

Several technological routes exist for converting hydrocarbon feedstocks into hydrogen or syngas. Each presents different characteristics in terms of scale, energy efficiency, flexibility, carbon footprint, and integration with downstream processes. Steam methane reforming (SMR) is widely adopted due to its maturity and suitability for small to medium scale installations (up to roughly 250 kNm3/h of hydrogen). It relies on external fired heaters to supply the heat needed for endothermic reforming reactions. While efficient at moderate scales, SMR becomes less competitive for very large projects because heat transfer limitations restrict single‑train capacity or in such

projects where carbon emissions must be minimised without significantly penalising overall efficiency, as is often the case when post combustion carbon capture is implemented. Another syngas production method is partial oxidation (POX), which involves the non‑catalytic oxidation of hydrocarbons at high temperatures. This reaction produces syngas with minimal methane slip and allows for flexible adjustment of hydrogen to carbon monoxide ratios. It is often used when a high CO content is required, or when processing heavier feedstocks with no or minimum pretreating. Instead, autothermal reforming (ATR), known as CASALE HEARTTM in CASALE’s portfolio, combines elements of SMR and POX, referred to as POX-ARTTM by CASALE, by integrating partial oxidation (exothermic) and steam reforming (endothermic) inside a single reactor. The heat generated by the oxidation reaction internally sustains the reforming process, eliminating the need for external fuel firing and keeping the CO2 produced within the process boundary. This configuration supports larger single‑train capacities – several HEARTTM units designed by CASALE are in operation at industrial scale, with individual capacities in the range of approximately 475 kNm3/h and up to 630 kNm3/h of hydrogen equivalent – and offers efficient integration with a single pre-combustion CO2 capture system. For these reasons, ATR is increasingly evaluated for large scale hydrogen and syngas facilities.

Autothermal reforming

Figure 1. CASALE HEARTTM (ATR) installed in a Chinese plant.

Figure 2. CASALE HEARTTM (ATR) cutaway view.

GlobalHydrogenReview.com

Summer 2026

The ATR reactor is designed as a pressure vessel lined internally with refractory materials, engineered to withstand the severe thermal and mechanical conditions typical of autothermal reforming processes. Its structural configuration must tolerate both the high temperatures generated inside the reformer and the repeated thermal cycles that occur during start-ups, shutdowns, and load variations. Inside the reactor, a multi-layer refractory system provides the thermal protection required to insulate the steel shell and maintain stable operating temperatures in the reaction zone. The arrangement and composition of these layers are crucial for ensuring that the refractory can resist mechanical stress, thermal gradients, and chemical wear during prolonged operation. At the core of the ATR unit lies the process burner, the component responsible for initiating and sustaining the flame by introducing and mixing the hydrocarbon feed with oxygen. The burner must generate a stable flame under pure oxygen combustion, achieving temperatures that can reach up to 2000°C. Such extreme conditions place stringent demands on burner performance, focusing on flame stability, safe operation, and mechanical reliability. Any deviation in the burner’s behaviour can significantly affect both the safety and the reforming reaction, overall syngas composition, and the lifetime of surrounding components. In the most severe failure scenario, if the burner is not properly designed, flame impingement on the refractory lining may occur, leading to refractory degradation or collapse and consequent severe damage. Alternatively, in the event of flame detachment, flame extinction may take place, potentially resulting in the formation of an explosive atmosphere. For these reasons, the design of ATR burners is of critical importance: effective cooling is essential to avoid excessive

thermal stresses, mitigate creep and fatigue, and prevent localised overheating that could lead to deformation or premature failure. The HEARTTM burner design developed by CASALE incorporates water cooling systems intended to maintain metal surfaces well within the design temperature limits. In recent years, additive manufacturing (AM) has been introduced by CASALE in its process burners: this enables a new set of possibilities in their design, like for ATR, POX, and secondary reforming applications, particularly for components like burner tips that experience the most severe thermal and mechanical loads. AM enables the production of complex, highly optimised geometries that are difficult or impossible to create using conventional machining or casting. Applying this technology to the burner tip aims to enhance its structural robustness and thermal performance, especially in regions subject to intense heat flux and rapid temperature fluctuations. Traditional burner tips are typically assembled from multiple parts joined by welds; however, welds can act as initiation points for cracks or fatigue damage, especially under repeated thermal cycling. By contrast, AM allows the burner tip to be fabricated as a single monolithic piece, eliminating welds entirely and thereby removing one of the most common structural weaknesses.

Figure 3. CASALE HEARTTM (ATR) water-cooler burner.

The additive manufacturing

Another significant advantage of AM lies in the ability to integrate internal cooling channels with shapes and positions optimised for improved heat removal. These channels can be placed closer to the hot external surface than is feasible with conventional manufacturing methods, enabling more efficient thermal management. The improved cooling performance reduces the temperature of the metal, minimises thermal gradients, and ultimately lowers the accumulation of damage from creep and fatigue mechanisms. Such characteristics can extend the component’s service life and contribute to more stable operation under varying loads. Furthermore, AM produced burner tips have demonstrated the capacity to withstand wider differential pressures between feed and oxygen streams – up to approximately 300 bar in tests – without compromising structural integrity or flame behaviour. This enhanced pressure tolerance supports stable operation during transient phases, such as start-ups or rapid load modulations. Thanks to the intrinsically higher robustness due to the design, the AM enables increased gas flow capacity manageable by a single burner, and unlocks the single-burner design for jumbo production. A first industrial application of an AM burner was deployed in a plant producing syngas for monoethylene glycol synthesis, with a hydrogen equivalent capacity of around 190 000 Nm3/h. The unit underwent a start-up sequence consisting of nitrogen circulation, operation in steam mode, gradual introduction of the hydrocarbon feed, controlled addition of oxygen, and final parameter alignment. During start-up, the burner’s behaviour aligned well with design expectations. No flame impingement or local hot spots were observed, and the combustion process remained stable even when operating at reduced loads of approximately 30% of capacity. In parallel, the water cooling circuit exhibited temperatures and pressure differences consistent with design predictions throughout both start-up and steady-state operation. Observations collected during the first year of operation indicated stable differential pressures across the burner – both in the cooling circuit and between the feed and oxygen lines – demonstrating that the mechanical and thermal assumptions underlying the AM-based design were validated in industrial conditions. No early signs of degradation were detected, and all monitored parameters stayed within the expected operational envelope. The introduction of AM into CASALE’s HEARTTM burner design thus appears to offer substantial potential for improving mechanical reliability, thermal efficiency, and operational flexibility. The initial evidence suggests that AM-enabled components may contribute meaningfully to the evolution of oxidative technology, by enabling innovative geometries, eliminating welds, and enhancing cooling performance. This design approach represents a noteworthy advancement in the engineering of high temperature equipment.

References Figure 4. CASALE HEARTTM burner tip made with AM.

GlobalHydrogenReview.com

Summer 2026

1. ‘Global Hydrogen Review 2025’, IEA, https://www.iea.org/reports/ global-hydrogen-review-2025/executive-summary 2. ‘Global Hydrogen Compass 2025’, Hydrogen Council / McKinsey & Company, https://compass.hydrogencouncil.com/

Luca Frigerio, SAATI, examines the role of advanced woven meshes in electrolyser systems.

ydrogen is increasingly recognised as a central vector in the transition towards low-carbon energy systems. Its versatility – spanning industrial processes, mobility, and energy storage – positions it as a key enabler of decarbonisation. Among available production pathways, water electrolysis has emerged as a scalable and flexible solution, particularly when coupled with renewable power sources. As deployment accelerates, the technical focus is shifting from feasibility to optimisation. Electrolyser systems are now expected to operate with greater efficiency, durability, and reliability under increasingly demanding conditions. This evolution places greater emphasis on the role of materials, not only within core electrochemical components but also across the broader system architecture. While catalysts and membranes often receive primary attention, supporting materials – particularly those involved in structural reinforcement and fluid management – are equally critical to long-term performance. In this context, companies such as SAATI, with expertise in precision technical fabrics and filtration media, are contributing to the evolution of material solutions tailored to electrochemical systems.

Technology landscape: different systems, different constraints

The main electrolysis technologies – alkaline (AWE), proton exchange membrane (PEM), and anion exchange membrane (AEM) – each present distinct operational environments and design constraints. Alkaline systems, long established in industrial hydrogen production, rely on liquid electrolytes and are valued for their robustness and cost efficiency. However, the trend towards higher operating pressures introduces increased mechanical stress on internal components. PEM electrolysers offer compact design, high current density, and rapid response to variable renewable inputs. These advantages come with more demanding material requirements, particularly in acidic environments and under dynamic operating conditions. AEM technologies, still developing at scale, aim to bridge the gap between the two. Across all configurations, the membrane remains a central element. It must simultaneously facilitate ion transport while maintaining a strict separation between hydrogen and oxygen. This dual function places significant demands on both its intrinsic properties and the materials that support it.

Operating conditions: where materials fail – or enable

In modern electrolyser systems, membranes are exposed to a combination of mechanical load, chemical stress, and thermal variation. As operating pressures increase, unsupported membranes may deform or fail, leading to reduced efficiency or compromised safety. Membranes, therefore, require mechanical reinforcement to withstand these conditions. The following application studies highlight how reinforcement structures must provide strength without obstructing ionic transport or introducing defects. Chemical compatibility is equally critical. Alkaline electrolysers involve highly caustic environments, while PEM systems operate under acidic conditions. Materials must maintain integrity over extended periods, resisting degradation mechanisms such as hydrolysis, oxidation, and thermal fatigue. Fluid dynamics add a further layer of complexity. Uniform distribution of reactants and effective removal of products are essential to maintaining efficiency. Poor flow management can result in localised degradation, reduced performance, and shortened system lifetime – factors that can be addressed through controlled mesh design and material selection.

Functional materials: the role of engineered meshes

Engineered woven meshes are increasingly used as multifunctional components within electrolyser systems. SAATI has developed precision monofilament woven meshes based on high-performance polymers such as PEEK and PPS, combining chemical resistance with mechanical robustness. Their function is twofold: y Reinforcing membrane structures under pressure. y Acting as spacers to regulate flow distribution within the stack. The effectiveness of these meshes lies in their structural precision. Monofilament construction ensures dimensional stability and minimises contamination risks, while controlled mesh

geometry enables tuning of key parameters such as permeability, turbulence, and mechanical support. Careful design of open area and thickness allows these materials to support membrane performance rather than hinder it – an essential requirement in high-efficiency electrochemical systems.

Material engineering as a differentiator

While reinforcement meshes are often considered auxiliary components, their design and manufacturing approach can significantly influence electrolyser performance. SAATI’s approach illustrates how differences in polymer selection, filament structure, and weaving precision translate into measurable performance outcomes. The use of high-tenacity monofilaments, for example, reduces the risk of particle release compared to multifilament alternatives – supporting cleaner operation in sensitive electrochemical environments. Similarly, maintaining control over mesh geometry and thickness uniformity enables predictable integration within membrane assemblies. This level of precision is critical for ensuring consistent electrochemical behaviour across large scale systems. A further differentiating factor is material formulation. SAATI has focused on the development of PFAS-free solutions based on advanced polymers such as PEEK and PPS, addressing both regulatory requirements and performance constraints. Achieving this balance requires a combination of polymer expertise and process control. In addition, delivering not only raw fabrics but also engineered and fabricated components – including cut, shaped, or multilayer structures – supports closer integration with customer system designs. Together, these elements position material engineering not as a secondary consideration, but as a key contributor to electrolyser performance.

Alkaline electrolysis: reinforcement under harsh conditions

In alkaline electrolysis, diaphragms, and membranes must operate in aggressive chemical environments while maintaining structural integrity under pressure. Reinforcement is therefore essential to prevent deformation and ensure stable operation. SAATI’s PPS-based woven meshes are well suited to these conditions. Their resistance to alkaline electrolytes and thermal stability enables long-term durability, even in high-pressure systems. A critical requirement is maintaining porosity while providing support. The mesh architectures are designed to achieve this balance, ensuring that reinforcement does not compromise ion transport while still providing the necessary mechanical stability.

Figure 1. SAATI PEEK fabric.

PEM and AEM systems: supporting thin, high-performance membranes

Figure 2. SAATI membrane reinforcement.

GlobalHydrogenReview.com

Summer 2026

In PEM and AEM electrolysers, system efficiency is closely linked to membrane thickness. Thinner membranes improve ion transport but are more susceptible to mechanical failure.

geometry or thickness can translate directly into performance variability. SAATI’s manufacturing approach includes advanced weaving techniques and thermoset stabilisation processes, ensuring dimensional control, stability across both warp and weft directions and planarity. Beyond dimensional precision, process know-how – such as controlled weaving tension and clean processing environments – supports repeatability and scalability, which are essential as electrolyser production increases. Testing and validation further reinforce performance reliability. Through internal laboratory capabilities, properties such as permeability, pore distribution, and mechanical strength can be evaluated to ensure consistent product behaviour.

Figure 3. SAATI stack assembly. PEEK-based meshes provide an effective reinforcement strategy in these systems. Their mechanical strength supports ultra-thin membranes, while their chemical resistance ensures compatibility across both acidic and alkaline environments. Precision manufacturing is central to this approach. Weaving technologies enable uniform thickness and consistent pore structure, supporting stable electrochemical performance and reliable integration into composite membrane assemblies.

Flow dynamics: a hidden lever for efficiency

Beyond structural reinforcement, meshes play a significant role in managing fluid dynamics within electrolyser stacks. As spacers, they influence flow distribution, turbulence, and pressure drop. Optimised flow conditions improve mass transport and reduce localised inefficiencies. At the same time, spacer structures act as a protective interface, reducing mechanical stress on membrane surfaces. Through tailored mesh architectures, system designers are able to fine-tune hydraulic performance while maintaining structural consistency.

Sustainability: from performance to compliance

Material selection is increasingly influenced by sustainability and regulatory considerations. In particular, restrictions on PFAS are driving the development of alternative material solutions. SAATI has actively developed PFAS-free reinforcement materials, eliminating intentionally added fluorinated compounds while maintaining high levels of chemical resistance and durability. These solutions, based on polymers such as PEEK and PPS, demonstrate how sustainability and performance can be addressed simultaneously. In addition, their durability contributes to extended component lifetimes and reduced material consumption. This approach reflects a broader industry shift, where materials must meet not only technical requirements but also environmental and regulatory expectations.

Manufacturing and validation: precision as a requirement

In electrolyser systems, material performance is closely linked to manufacturing precision. Variations in mesh

GlobalHydrogenReview.com

Summer 2026

Best practices in material integration

Experience across electrolyser development suggests several key principles for effective material integration: y Selection of chemically and thermally compatible materials. y Incorporation of reinforcement structures to maintain membrane integrity. y Optimisation of mesh geometry for flow and structural performance. y Minimisation of contamination through monofilament design. y Alignment with sustainability and regulatory requirements. The company’s material solutions are developed with these principles in mind, supporting both performance and reliability in industrial applications.

Outlook: increasing demands, expanding roles

As electrolyser technologies evolve, operating conditions are becoming more demanding. Higher pressures, thinner membranes, and dynamic operation will continue to challenge material performance. In this context, focusing on advanced material engineering can position companies to support next-generation system requirements. The combination of structural support, flow optimisation, and chemical resistance offered by engineered meshes is expected to play an increasingly important role. Beyond hydrogen production, similar material solutions are being applied in adjacent electrochemical fields, including carbon capture, water treatment, and energy storage.

Conclusion

The performance of electrolyser systems is shaped by more than electrochemistry alone. Structural integrity, fluid dynamics, and material durability are equally critical to achieving efficient and reliable operation. Engineered woven meshes illustrate how material design can address multiple challenges simultaneously, supporting membrane stability, improving flow behaviour, and contributing to system longevity. As hydrogen production continues to scale, the integration of advanced, PFAS-free, and precision-engineered materials will be a key factor in enabling both performance and long-term viability.

Abigail Lister, M-Spin, UK, explains how ultra-high surface area nanofelts can be used to improve electrolyser efficiency while reducing costs.

he production of green hydrogen plays a vital role in the clean energy transition. To decarbonise hard-to-abate industries such as steel, cement, and chemical production, low-cost green hydrogen needs to be generated at a large scale. Electrolyser technologies enable this hydrogen to be produced using renewable energy, but high production costs are currently limiting the use of electrolytic hydrogen over conventional ‘grey’ fossil-fuel derived hydrogen (which has associated carbon emissions). This article explores the critical limitations of existing electrolyser electrode materials before introducing a novel class of materials called ‘nanofelts’, which can boost electrolyser efficiency and drive down the production cost of electrolytic hydrogen.

Electrolyser electrodes: factors to consider

There is great similarity between the factors that determine the performance of electrodes across the three main electrolyser technologies; alkaline water electrolysis (AWE), anion exchange membrane electrolysis (AEM), and proton exchange membrane electrolysis (PEM).

Electrochemical performance Perhaps the most important metric of all is the voltage required to generate a given current density. Energy is

needed to generate the voltage that must be applied between the anode and cathode to drive the current flow that results in hydrogen production. More efficient electrodes require lower voltages and therefore less energy to generate a given current. As higher currents increase the hydrogen production rate, more efficient electrodes produce a greater volume of hydrogen for a given energy input.

Cost It is important to consider whether the extra cost of purchasing a more efficient electrode material (CAPEX) is outweighed by the reduced cell running costs over the lifetime of the electrode (OPEX). This consideration is influenced by externalities such as electricity cost. For example, in regions like Europe where electricity is comparatively expensive, hydrogen producers tend to favour higher CAPEX/lower OPEX electrolysers.

Stability The electrode material and any catalysts must be stable in the electrolyte and under the electrolysis conditions used. Tests can be performed to determine whether electrode material is leaching into the electrolyte over time, or if the performance is degrading with extended use. Some electrolysis technologies apply high pressures and temperatures

to the electrodes, so the electrode must be mechanically robust enough to withstand this.

Catalyst necessity Electrode efficiency can be increased significantly by adding catalysts to their surfaces. These catalysts often include precious metals such as platinum or iridium and are consequently very expensive. An ideal electrode material would use low-cost, high-stability catalysts, or avoid them entirely.

Electrode microstructure High surface areas are desirable as this tends to drive enhanced activity towards the hydrogen evolution reaction. Additionally, higher surface areas and porosities lend themselves to increased efficiency of bubble removal from electrode surfaces. Bubbles of produced gas can limit the performance if they become stuck and block the active surface for further hydrogen production. Porosity is important for easing the transport of reactants to the separator or membrane, but increasing the porosity too much can worsen the mechanical stability of the electrode so a careful balance must be obtained.

Current materials solutions

Different electrolysis cell designs use different electrode materials to facilitate the anode and cathode gas evolution reactions. Existing electrode materials tend to fall into two broad categories: high performance but high cost, or low cost but low performance. Achieving an electrode with a high performance and lower cost could help drive the cost of green electrolytic hydrogen down to

parity with fossil fuel-derived hydrogen. The electrode materials typically used on the anode and cathode for each of AWE, AEM, and PEM electrolysis systems are shown in Table 1. Standard nickel (Ni) foams and meshes are low-cost options for AWE but are also low performance, which results from their insufficient surface areas. They therefore require higher operating voltages and energy inputs to generate a given amount of hydrogen. Consequently, it only makes sense to use bare meshes or felts in scenarios where high OPEX, low CAPEX systems are suitable. If required, Raney Ni can be applied onto these materials to provide a high surface area coating and improve their hydrogen generation efficiency. Raney Ni is highly active as a catalyst for the hydrogen evolution reaction in alkaline conditions and it is cheaper than precious metal alternatives. However, Raney Ni has several disadvantages: it is comparatively expensive to make at scale (top-down fabrication method), has poor stability in alkaline conditions during prolonged use, and has pyrophoric properties when dried. At the time of writing, the majority of PEM electrolysers rely on iridium (Ir) and platinum (Pt) catalysts. As rare and expensive precious metal resources, there is a clear need for materials that can achieve the required performance without reliance on precious metals, or with lower precious metal loadings. In AWE and AEM systems, there is demand for better electrode materials that can be made at scale, can match performance of Raney Ni without a catalyst, or will exceed the performance of standard catalysed electrodes when a catalyst is added, all whilst being cost competitive. The following case studies explore how nanofibrous meshes are addressing these challenges.

Ultra-high surface area for improved efficiency

M-Spin has developed a series of ultra-porous metallic products for electrolyser applications. These ‘nanofelts’ have 1000x the surface area of commercial metal foams. The proprietary process generates sheets of material comprised of metal fibres with diameters between 0.5 and 2.5 µm (see Figure 1). Nanofelts with different porosities, elemental compositions, and supporting substrates are available, targeting different electrolyser technologies. The higher surface areas and flexibility in composition (e.g., by including iron) offered by the nanofelts leads to step-change performance improvements in electrolyser applications. In addition, the process by which these nanofelts are manufactured offers significant advantages. Raney Ni, for example, Figure 1. Example morphology of a M-Spin Ni nanofelt. The is made through an expensive to scale and atom inefficient process fibrous nature gives a high surface area and porosity, leading to based on de-alloying of NiAl. On the other hand, traditional felts excellent performance in electrolyser applications. are made from bundle drawing metal fibres followed by sintering. This bundle drawing process Table 1. Electrode materials and catalysts typically in commercial use across different electrolyser technologies (largely high cost and high performance, or low cost and requires a matrix that must be low performance) removed to avoid contamination of the fibres; this process is often AEM AWE PEM done by acid leaching, adding Anode Ni felt (£) Raney Ni on Ni mesh (££) IrO2 catalyst on Ti felt and another level of complexity to the NiFe on Ni felt (£) Ni mesh (£) sintered Ti powder (£££) manufacturing process. In contrast, IrO2 catalyst on Ni felt (£££) M-Spin’s nanofelts are made using a Cathode Pt/C catalyst on C felt (£££) Raney Ni on Ni mesh (££) Pt/C catalyst on C paper (£££) proprietary bottom-up, low-waste, Pt/C catalyst on Ni felt (£££) and scalable method that can NiMo on C felt (££) generate nanofelts in-situ on the Note: (£) solutions are the lowest cost, whilst (£££) solutions are the most expensive desired substrates. Unlike Raney Ni

GlobalHydrogenReview.com

Summer 2026

fabrication, the nanofelts use an atom efficient process that does not rely on dealloying.

AEM with nanofelt electrodes

In a standard AEM test cell, Ni nanofelt with no additional catalyst has been found to outperform Raney Ni loaded Ni mesh across the voltage range. Figure 2 shows how the Ni nanofelt generates a larger current density for a given voltage than both Ni foam and Raney nickel. At 2 V, for example, the nanofelt generates 5x the current density than the Ni foam, and over 50% more current density than the Raney Ni substrate. In industrial operation, these reductions in operating voltage translate to energy input requirement reductions of the same percentages. NiFe alloys are also attractive anode materials in AEM because of their impressive electrochemical performances without precious metal catalysts, their high stability in alkaline conditions, and their lower costs compared to precious metal alternatives. M-Spin also produces NiFe nanofelts and customer testing has demonstrated improved performance metrics over pure Ni nanofelts. Ni nanofelts have been found to be very stable in AEM conditions – accelerated stress testing has found the degradation of the nanofelt to be minimal. Such data can be seen in Figure 3, which shows a negligible voltage increase over 10 000 accelerated stress testing cycles (equivalent to 8000 - 10 000 hrs of continuous operation). Electrode materials that suffer significant degradation over time (such as Raney Ni) increase electricity costs and effectively limit the lifetime of the electrolyser, incurring replacement costs for the hydrogen producer.

Figure 2. Plot showing the current density generated by a given cell voltage in an AEM test cell. The M-Spin Ni nanofelt cell generates higher current densities than the cells with Ni foam and Raney Ni loaded Ni mesh electrodes.

AWE and nanofelts

M-Spin’s Ni and NiFe nanofelts also perform impressively in AWE single cell test systems, showing significantly higher current densities over Raney Ni and good stability in accelerated stress testing. Third party stack testing was scheduled to commence in April 2026.

Opportunities for PEM electrolysers

Demand for PEM electrolysers has been growing steadily in the last two years, with users attracted by their fast start-up times. However, the PEM field is reliant on expensive precious metal group catalysts as well as expensive titanium (Ti) felt porous transport layers. Costs are driven up by the huge expense associated with Ti processing; removing it from its ore is energy intensive, the molten metal must be handled under vacuum, and it must be sintered at high temperatures. The complex manufacturing of conventional Ti felt through multi-pass bundle-drawing and sintering further pushes up the cost. PEM material development is therefore primed for disruption with a Ti nanofelt product that reduces the precious metal loading requirement and can be produced more cheaply. Ti nanofelts are currently in development at M-Spin, with promising small scale results and larger scale nanofelts on target for production by the end of 2026.

A solution for electrolyser technologies

To compete with fossil fuel derived hydrogen, more efficient electrolysers are necessary. Achieving this requires electrodes with high activity for hydrogen production while avoiding expensive or difficult to produce materials such as precious group metals and Raney Ni, respectively. Nanofelts, which are ultrahigh surface area

Figure 3. Current density changes with cell voltage before stress testing (red) and after stress testing (blue) for a standard AEM test cell. Cathodes and anodes are unsupported Ni nanofelts made by M-Spin. Stress testing protocol held the current density at 0 A cm-2 for 30 sec., then 4 A cm-2 for 30 sec., repeated 10 000 times. No significant decrease in current density at a given voltage after stress testing demonstrates that the nanofelt is stable. materials made from low-cost Ni and NiFe metals, enable extremely high production rates of hydrogen at low voltages while avoiding expensive catalysts in alkaline systems (AWE/AEM). Nanofelts are also projected to give enhanced performances in PEM systems, enabling lower or more efficient use of precious metal catalysts. Overall, nanofelts are a very attractive electrode technology due to their combination of low cost and high hydrogen production rate, reducing electrolyser CAPEX and OPEX. Their ultra-high surface areas mean that lower energy inputs are needed to generate a given amount of hydrogen, lowering electrolyser operating costs. This can mean that precious metal catalysts are no longer needed. The versatile process in which the nanofelts are made has a clear route to scale and can be used to generate nanofelts with different thicknesses and mechanical properties. The adoption of nanofelt electrodes across the electrolyser industry will help to close the cost-gap between grey and green hydrogen and facilitate decarbonisation of steel, cement, and fertilizer production.

Summer 2026

GlobalHydrogenReview.com

Stefano Andreola and Alberto Lando, Nextchem (MAIRE), outline strategies to digitalise alkaline electrolysis using a cell monitoring system and real-time optimiser.

s hydrogen projects scale up and integrate with power markets and downstream synthesis (e.g., methanol, ammonia), operators need better support to make decisions on performance, starting from the electrolysis cell and spanning all the way to the integrated plant. One such solution is a two-layer digital architecture that produces green hydrogen through alkaline electrolysis: a cell monitoring system (CMS) that translates per-cell and stack signals into an interpretable Health Index (HI) and actionable maintenance advisories; and a real-time optimiser (RTO) that co-optimises the electrolyser with downstream power-to-X (PtX) units and storage to manage volatile power prices and renewable forecasts. Together, these layers improve plant availability, reduce avoidable degradation, and increase the overall project profitability.

Why digitalise alkaline electrolysis?

Alkaline electrolysers are increasingly asked to do more with less to be competitive: assess intermittent renewable production, arbitrate power prices, and feed complex downstream value chains. Traditional control schemes can keep plants safe and on-specification, but they rarely deliver lifetime-based, market-informed decisions. Digitalisation adds three capabilities: � Early insight into cell-level changes that often precede performance drift or risk events. � Load stability through buffering by leveraging upstream energy storage and downstream hydrogen inventories so the system can absorb power-side oscillations and sudden changes in electrical feed, smoothing the electrolyser load and avoiding ramp shocks.

� Economic alignment by steering set-points with awareness of power costs, renewable availability, storage inventories, and synthesis constraints. This article will explain how Nextchem (MAIRE’s sustainable technology business unit) delivers these benefits for its NX-FHYVE green hydrogen production technology via an interpretable CMS and a plant-wide RTO, kept intentionally modular so that each can be deployed independently or coupled.

Layer one: the CMS What the CMS ‘sees’ A CMS ingests cell-level, stack-level, and plant-level operating variables routinely available in industrial alkaline systems, mainly system current, voltage, temperature, pressure, and electrolyte composition along with cell voltage where available. The CMS can rely on signals that are already measured (or easily measurable). Expensive sensor suites are not essential for value.

From signals to insight: a HI Rather than relying on a single predictive metric, which can be hard to interpret, more value is delivered by computing a HI – a composite, interpretable indicator aligned to observable physics and electrochemistry. A HI can blend features derived from voltage dispersion, temperature trends, and electrolyte conditions to reflect state-of-health (SOH). The aim is to show trends, confidence levels,

and actionability. A tested example is when a cell’s voltage trends to a higher value than the predictable value, which may trigger the need to plan inspection within a set number of operating cycles.

Methods that stay explainable The CMS uses an increasingly automated analytics approach: y Rule-based guards and trend bands to detect excursions (e.g., rolling voltage variance, drift rates). y Unsupervised anomaly detection to highlight multi-signal deviations, flagging what specific parameters the operator should keep an eye on.

Figure 1. Cell monitoring system validation and output architecture.

Figure 2. RTO illustrative Scenario A – renewable variability.

All the parameters and statistical relations used in the CMS need to be first validated and tested through the R&D phase to ensure they are a high-fidelity representation of the physical reality. In particular, two tools are used in the validation of the CMS: y Physics-informed dynamic simulation features (e.g., normalising voltages by load and temperature proxies) to verify that the statistical relationships also translate in clear physical relationships. y Electrochemical Impedance Spectroscopy (EIS) and polarisation results from test benches or scheduled campaigns; typically used offline to calibrate thresholds but can also be used online during test phases. But why does interpretability matter? When the CMS recommends an action, operators can see which features contributed to the decision, and with a degree of confidence. A disciplined alarm strategy (few, meaningful alerts) builds trust and adoption. In sum, the CMS converts what has already been measured into readings that operators can act on. As Figure 1 shows, cell, stack, and plant-level signals feed the CMS for training, while physics-based dynamic modelling and EIS act as validation gates. The system aggregates these inputs into an interpretable HI and physically grounded deviations, which translate into clear maintenance and safety indications without requiring expensive sensors. This keeps the solution deployable and auditable on today’s assets. It creates a reliable, R&D-validated bridge from data to action, whose outputs can later be consumed by the RTO at plant scale.

Layer two: the RTO for PtX sites What the RTO ingests

Figure 3. RTO illustrative scenario B – inventory bottleneck.

Figure 4. RTO illustrative scenario C – anomaly triage.

GlobalHydrogenReview.com

Summer 2026

An RTO exploits a mixture of economic and technical data, which are live price signals and specific to the operating plant. y Power market data: available contracted electricity price and quantity (e.g., PPAs level and structure, penalties, etc.) day-ahead and intra-day price signals. y Renewable data: on-site renewable generation forecasts. y Process constraints: electrolyser, storage and downstream synthesis minimum turn down, ramp rates and preferred operating windows. y Inventory and offtake: hydrogen buffer levels, product storage, shipping schedules, quality-linked penalties. y Degradation-aware penalties: soft constraints derived from the CMS to avoid accelerated degradation by ramping electrolysis stacks with low health levels.

Large-scale EPC projects delivered globally, backed by a solid record of success. Meet us at Gastech Bangkok 14 - 17 September 2026 Stand P85

Scenario B: inventory bottleneck With the ammonia loop at maximum and hydrogen storage near the upper bound, RTO advises moderate electrolyser load and pre-positions for the next ramp; CMS flags a module for inspection during an opportunistic pause, while hydrogen storage is emptied (Figure 3).

Scenario C: anomaly triage CMS detects upward drift in voltage variance; operators tag and partially derate that module; RTO reshapes timing while an inspection is planned (Figure 4).

Scenario C: a tested example

Figure 5. Stack A cell voltage drift triggers CMS fault flag (a). After de-rating stack A, RTO reallocates power to healthy stack B (b).

How the RTO functions The RTO maximises site margins (or minimises total cost) over a rolling horizon while respecting safety and operability. It can be expressed in a simplified equation: profit = product revenue – power cost – variable OPEX – degradation cost proxy. The proxy scales with the HI and penalises aggressive patterns (e.g., deep cycling, prolonged high severity). The RTO solves an optimisation problem and publishes advisory or bounded set-points depending on governance.

Computational power and runtime The challenge is in balancing accuracy and computational time, so that each run is implementable in a timeframe to give useful insights. For example, if the relevant timeframe to making a decision is every 15 minutes to match the timeframe of electricity markets (this would be the case for a grid-connected project in Europe), the model run should take less than 15 minutes to produce results. If the model, however, is run using the full level of process simulation detail, the runtime is usually longer than 15 minutes. So, to strike a balance between accuracy and time, companies need to deploy a synthetic model that closely mimics the real simulation.

Illustrative scenarios Scenario A: renewable variability Pure energy management optimisation would suggest raising the electrolyser load to capture price dips, but CMS HI imposes guardrails; the RTO selects a second-best that preserves asset life (Figure 2).

GlobalHydrogenReview.com

Summer 2026

Figure 5 A and B show how the CMS and the RTO interact when a fault develops on Stack A. The CMS tracks individual cell voltages in Stack A and computes a drift metric based on dispersion (highest minus median cell voltage). When this metric exceeds its band for a given window, the CMS raises a fault flag. This is a rule-based safeguard: it does not predict remaining life; it signals abnormal behaviour that requires mitigation. The response is a predefined derating envelope on Stack A, applied as a lower load cap. After derating, cell-voltage spread and drift stabilise because the operating point is less aggressive, reducing overpotential while inspection is planned. Derating cuts hydrogen output from Stack A, but the electricity price stays low, so additional production is still attractive. The RTO, which explicitly accounts for electricity prices in its rolling optimisation, reshapes dispatch: it keeps Stack A within the CMS constraint and ramps up Stack B to recover lost production in the same low-price window. The net effect: the site maintains throughput without stressing the flagged stack. CMS provides transparent constraints; the RTO allocates production around them.

Takeaways: make it useful, not flashy

y Interpretability beats opacity. It is vital to show which features contributed to alerts and with what confidence. y Start with what is being measured. Cell voltage, temperature proxies, and electrolyte concentration (e.g., KOH) are sufficient to begin. y Align to maintenance and safety culture. Codify how alerts translate into work orders and inspection steps. y The landscape is maturing. Condition monitoring and safety analytics are advancing across the sector.

Conclusion: digitalisation as a disciplined craft

Digitalisation is a disciplined craft that respects operations and accelerates decisions. A clear separation of concerns: CMS for cell-level health and RTO for plant-level economics helps navigate renewable energy volatility, market signals, and complex synthesis chains without trading away asset life. For Nextchem’s NX-FHYVE, this layered approach leverages existing measurements, builds interpretable indicators, and threads those indicators into site-wide optimisation: useful and safe for public disclosure, yet meaningful for plant performance.

G. Balaji, ABB Energy Industries, outlines why digitalisation is a proven lever for managing the power costs of green hydrogen and turning climate ambition into a commercial reality.

reen hydrogen carries significant potential as a pathway to decarbonising some of the world’s most energy-intensive industries. But there are challenges, the most fundamental of which is that the cost of producing green hydrogen remains, in most contexts, more expensive than its fossil-fuel-derived alternatives. Bridging that gap requires progress on multiple fronts simultaneously – electrolyser technology, renewable energy pricing, infrastructure, and policy. Yet one lever that is already deployable, already proven, and consistently underestimated is digitalisation. The scale of the challenge is clear. The International Energy Agency’s (IEA) ‘Global Hydrogen Review 2025’ reports that global hydrogen demand reached almost 100 million t in 2024, but low-emissions hydrogen still accounts for less than 1% of

total production.1 A wave of project cancellations and delays has reduced the expected pipeline of low-emissions production by 2030 from 49 million tpy to 37 million tpy. The gap between ambition and delivery is real and closing it demands that every available efficiency lever is engaged from the outset of a project. Digital technologies are not an optional enhancement to a green hydrogen plant. They are a core requirement for making any plant economically viable – regardless of scale. That is the view from ABB, which works with green hydrogen producers, EPCs, and project developers across the value chain to deploy integrated automation, electrification, and digital solutions. This reflects both what the data shows about hydrogen’s cost structure and what operational experience reveals about where efficiency gains are realistically achievable.

The cost challenge is predominantly an energy challenge

Any serious analysis of green hydrogen economics leads quickly to the same conclusion: electricity is the dominant cost driver. Approximately 70% of the total operating costs required to make hydrogen are estimated to come from the electricity needed to power the production process. This creates significant opportunities for where digital technology can make a material difference on the levelised cost of hydrogen (LCOH) – the all-in per-kilogram figure that ultimately determines whether a project is commercially viable. ABB’s energy management system has demonstrated the potential to reduce energy costs by up to 10%, while increasing overall production efficiency by a further 5%. By coordinating multiple electrolyser modules based on their specific, non-linear efficiency curves, rather than treating the plant as a single, static load, digitalisation turns the production process into a dynamic, price-responsive operation. The cost of electricity for hydrogen production is not fixed. It varies depending on the source – whether solar, wind, grid power purchased under a power purchase agreement, or stored battery energy – and it fluctuates throughout the day and across seasons. A plant that cannot intelligently navigate that variability, automatically selecting the cheapest available source at any given moment and modulating production accordingly, carries a structural cost disadvantage over its operational lifetime. This is one of the primary functions of an advanced energy management system in a green hydrogen context. The system continuously monitors available power inputs – on-site renewables, battery storage, grid supply – alongside real-time pricing data, and directs the electrolysers to produce when energy costs are lowest. In solar-heavy configurations without battery storage, that means maximising production during daylight hours when generation is at its peak. Where battery capacity exists, the system can assess the economic case for charging the battery rather than driving production directly, and, where there is surplus energy, it can optimise the decision to export it back to the grid as an additional revenue stream. Beyond moment-to-moment source optimisation, an intelligent energy management platform can incorporate weather forecasting to anticipate renewable generation availability hours or days ahead. Solar irradiance prediction and wind pattern modelling feed into a planning layer that helps operators make better production scheduling decisions. On the demand side, where hydrogen offtake patterns can be modelled or predicted, as is the case in mobility applications, and where fuelling demand

Figure 1. OPTIMAX® green hydrogen.

GlobalHydrogenReview.com

Summer 2026

follows relatively consistent patterns, the system can synchronise supply and demand across the entire value chain, factoring in projected energy prices to minimise end-to-end costs.

Optimisation at the electrolyser level

Energy source management addresses one dimension of cost. A second is efficiency within the production process itself, specifically, how the electrolysers are operated in real time. Commercial scale hydrogen production typically involves multiple electrolyser stacks operating in parallel. Each stack has its own efficiency curve – the relationship between electrical input and hydrogen output is non-linear, and operating stacks at their most efficient load point matters considerably over the life of an asset. An advanced process control system that coordinates multiple stacks and distributes load intelligently based on each unit’s current efficiency can deliver meaningful gains in output per unit of energy consumed. Real-time optimisation also encompasses resilience. When a stack goes offline unexpectedly – for maintenance, a fault, or a grid event – a digitally managed plant can isolate the affected unit, redistribute load across the remaining stacks and maintain production continuity. Modelling these scenarios in advance, with control logic ready to respond automatically, is what separates a plant that absorbs disruption from one that incurs costly unplanned downtime. Both dimensions, source optimisation and electrolyser-level control, feed directly into the LCOH. ABB has demonstrated this in practice through its work with Hynamics at a pilot green hydrogen facility in France. Its ABB AbilityTM OPTIMAX® platform enabled real-time monitoring, optimisation of electrolyser performance and predictive control of hydrogen production. The result is a more stable, efficient, and scalable operation, illustrating how digital control can materially improve both efficiency and resilience in hydrogen production.

Making the business case bankable

While the LCOH serves as the ultimate metric for success, the path to reaching it is as much a challenge of commercial confidence as it is of chemical engineering. Building this confidence requires a shift in how projects are conceived and executed. According to ABB’s Energy Industries division Green Hydrogen Research Study, 76% of industry decision-makers identify global strategic partnerships as central to successful project execution, with 60% prioritising collaborators who can support with the initial financial challenge.2 Against this backdrop, digitalisation is the primary tool for technical due diligence. By providing a digital thread of a project’s expected performance before capital is committed, technology partners can de-risk the final investment decision (FID) for lenders and equity investors alike. The role of digital technology in green hydrogen does not begin at commissioning. Some of the most valuable work happens before a single piece of equipment is ordered. Project developers and investors need to model a hydrogen plant’s performance and economics with a reasonable degree of accuracy before committing capital. Process simulation and digital twin tools enable this computationally, using engineering process documents and equipment specifications to build a dynamic model of the plant before it exists physically. The model can be run through a large number of scenarios – varying power mix, load profiles, demand curves, and market

SOLVING TODAY’S OPERATIONAL CHALLENGES WITH AUTONOMOUS-READY SOLUTIONS Built on 100+ years of domain expertise and powered by AI, simulation, and advanced process control, ABB Digital Solutions help industrial facilities transition from automation to autonomy.

See solutions, use cases, and next steps.

pricing – to identify the configuration that offers the best risk-adjusted economics. This kind of pre-investment analysis is what lenders and equity investors now routinely expect to see as part of a credible business case. The value of the digital twin does not stop at the FID. Once a plant moves from execution to operations, the model can be integrated with the live automation system, updated with real-world performance data, and used to apply machine learning techniques that improve forecasting accuracy over time. The same environment that helped de-risk the investment decision becomes both a continuous improvement tool and a training resource for operations teams. ABB’s role in both automation and electrification is relevant here. The electrical design of a green hydrogen facility, including the power distribution architecture upstream of the rectifiers, has a bearing on both efficiency and CAPEX. Modelling and optimising that design within the same digital environment as the production process creates a more accurate and more actionable picture of plant economics than treating electrification and process automation as separate workstreams.

Certification and the RFNBO requirement

As green hydrogen markets mature, regulatory requirements are adding another dimension to the digital challenge. In Europe, the Renewable Fuels of Non-Biological Origin (RFNBO) regulations set out criteria for what qualifies as green hydrogen, including the requirement that the electricity used in production can be demonstrated to have come from renewable sources on a temporal and geographic basis.4 Meeting those requirements in practice demands continuous, granular tracking of energy inputs into hydrogen production, typically at hourly intervals. Digital platforms that monitor renewable energy usage in real time, automatically assess compliance against RFNBO criteria, and generate the data trail needed for certification are moving from a regulatory nice to have to a commercial need to have. Without the ability to certify green credentials, producers in certain markets risk their products being unable to command pricing that underpins project economics.

The AI horizon

The digital capabilities described above are deployed today. Looking ahead, artificial intelligence (AI) offers the prospect of taking each of them further. Supply predictability is one clear area. Weather forecasting is challenging, but AI systems trained on large volumes of historical meteorological and generation data can deliver material improvements in the accuracy of renewable output predictions, thereby improving the quality of production scheduling decisions. Demand forecasting is another area, particularly for applications where hydrogen consumption is variable. In industrial settings such as refining, demand tends to be stable and predictable. In other applications, mobility and distributed industrial use among them, load profiles are more dynamic, and AI-enabled forecasting can help producers anticipate and plan for that variability. The third area is cost transparency: accurate, real-time visibility of the true cost of production at any given moment, factoring in energy source mix, electrolyser efficiency, maintenance state and market pricing. AI can improve the granularity of that cost picture.

GlobalHydrogenReview.com

Summer 2026

These are incremental developments built on existing foundations rather than capabilities requiring new infrastructure. The direction of travel, however, points toward hydrogen plant operations that are more automated, more self-optimising, and more data-driven with each successive generation of deployed technology.

Architectural readiness through standardisation

While AI and digital twins provide the intelligence to optimise production, the physical transition to GW scale requires a parallel shift in hardware philosophy. The industry must move away from bespoke, one-off engineering toward repeatable, modular designs. Architectural readiness involves creating standardised building blocks for automation and electrification that can be replicated across multiple sites with minimal reconfiguration. This approach, currently being deployed in partnerships like the Charbone Hydrogen development in North America, significantly reduces engineering lead times and accelerates the deployment of new facilities.3 By utilising modular and integrated control systems, developers can ensure that a MW scale plant commissioned today establishes the template for the larger facilities required tomorrow.

The path to gigawatt scale

The ambition for green hydrogen remains at GW scale deployment. The IEA’s ‘Global Hydrogen Review 2025’ notes that while more than 200 low-emissions hydrogen projects have reached FID since 2020, the pipeline to 2030 has reduced due to project cancellations and delays.1 Low-emissions production from projects that are operational or have reached FID is set to reach 4.2 million tpy by 2030 – a fivefold increase on today, but below targets set at the start of this decade. Closing the remaining gap requires cost reductions that make hydrogen competitive without subsidy, and that demands every available efficiency lever being engaged. Scale alone does not guarantee lower costs. Large plants require a confirmed offtake, access to competitively priced renewable power, and the right infrastructure conditions. Given those fundamentals, though, the operational efficiency advantage of a digitally managed facility compounds over time – savings on energy costs, maintenance and compliance accrue across an asset life measured in decades. Bringing down the cost of green hydrogen production is ultimately an engineering and operational challenge as much as a technology and policy one. Digitalisation addresses the operational dimension directly, using tools and systems that are available today. For project developers, operators, and investors working to make green hydrogen work commercially, it is a core part of the value case.

References

1. ‘Global Hydrogen Review 2025’, IEA (2025), https://www.iea.org/ reports/global-hydrogen-review-2025. 2. ‘Green Hydrogen Research Study’, ABB, https://new.abb.com/processautomation/energy-industries/enabling-your-green-hydrogen-journey/ green-hydrogen-research-study. 3. ‘ABB and Charbone Hydrogen sign agreement to advance North American green hydrogen production facilities’, ABB, https://new.abb. com/news/detail/124187/abb-and-charbone-hydrogen-sign-agreementto-advance-north-american-green-hydrogen-production-facilities. 4. ‘Renewable Hydrogen’, European Commission, https://energy. ec.europa.eu/topics/eus-energy-system/hydrogen/renewablehydrogen_en.

Mark Richards, Beckhoff, UK, explains why producing, storing, and using hydrogen safely and efficiently requires flexible control solutions that can operate in demanding environments.

ccording to Hydrogen Council’s inaugural 2025 report, the clean hydrogen sector has averaged a 50% year-on-year investment growth rate since 2020.1 This puts the total investment so far at US$110 billion with more than 500 projects worldwide that are past final investment decision, in construction or already operational. This article explains why producing, storing, and using hydrogen safely and efficiently requires control solutions that are flexible and capable of operating in demanding environments. As many industries continue to accelerate their path to decarbonisation, hydrogen is emerging as a vital enabler in the transition to net zero. No longer a distant theoretical vision, the hydrogen economy is beginning to take shape across areas like storage facilities and mobility infrastructure. Its role in the global energy system is multi-faceted and technically demanding.

Green hydrogen is produced by electrolysis using renewable energy. It offers a carbon-free energy carrier that can be used in transport, industry, and power generation. Its potential to store renewable energy and to decarbonise sectors like steelmaking and chemicals makes it critical to the future energy mix. However, the unique properties of hydrogen, including its small molecules, high flammability, and requirements for high pressures and low temperatures create challenges. This means rethinking how hydrogen facilities are automated. Integrated control systems capable of managing complex processes and ensuring safety at every stage are essential. Traditional automation architectures are based on separated and inflexible systems, making them ill-suited to this challenge. Instead, modular, PC-based automation platforms that can combine real-time control, monitoring, safety, and connectivity in a single environment are necessary. In practical terms, this convergence is significant. In many legacy plants, process control, safety systems, condition monitoring, and data logging operate in isolated layers. In hydrogen applications, where fast transients, pressure fluctuations, and thermal effects interact continuously, this separation can introduce latency and blind spots. A unified, PC-based architecture allows deterministic real-time control tasks to run alongside high-resolution measurement and secure communication protocols within one framework that reduces integration complexity and improves system transparency.

From electrolysis to storage

Electrolysis is the cornerstone of green hydrogen production, but while splitting water into its component elements may seem simple in principle, it requires finely tuned control over electrical input, temperature, pressure, and chemical balances. Relatively small fluctuations can cause inefficiencies or damaged equipment that prevents operators from achieving high reliability and efficiency. For example, in proton exchange membrane (PEM) systems, current density is a key operating parameter, which requires tight regulation to prevent membrane degradation. Similarly, alkaline electrolysers require careful management of electrolyte concentration and circulation rates. Automation platforms must therefore handle high-speed data acquisition and precise control of specific parameters. The goal is to ensure synchronisation between measurement terminals and control algorithms, even at sub-millisecond cycle times. This requires a system that integrates control and measurement technology to enable precise management of the electrolysis process. Real-time data acquisition allows operators to optimise conditions continuously. In addition, these systems can incorporate predictive maintenance functions that analyse trends and predict failures before they happen, reducing costly downtime. Trend analysis of stack voltages, differential pressures, and temperature gradients can reveal early signs of cell imbalance or scaling. By embedding analytics directly within the control environment, operators can move beyond reactive maintenance to condition-based strategies. For large scale plants, even marginal efficiency gains or avoided shutdowns can have a substantial economic impact. Hydrogen can be stored as a gas under high pressure, as a liquid at very low temperatures, or chemically in materials such as metal hydrides. Each storage method carries its own unique challenges. Metal hydride storage, for example, offers a compact and safe alternative to pressurised gas tanks, but it demands careful thermal management and pressure control.

Modular platforms in practice Figure 1. Efficiency gains for large scale plants.

Figure 2. Hydrogen set to transform transportation and mobility.

GlobalHydrogenReview.com

Summer 2026

GKN Hydrogen is a good example of a company employing this storage method. Its innovative systems use metal hydrides to safely store hydrogen at low pressures, offering long-term stability and high energy density. With up to 8.3 MWh of storage capacity in its HY2MEGA system, precise control is paramount. In metal hydride systems, hydrogen absorption is an exothermic reaction, meaning heat must be removed efficiently to maintain absorption rates, while controlled heating is required to release hydrogen on demand. This means that temperature distribution directly influences storage performance. Advanced automation systems continuously monitor temperature, pressure and system health, ensuring safe absorption and release of hydrogen. Real-time synchronisation of data across distributed sensors, combined with intuitive visualisation tools, gives operators the insight needed to manage complex storage systems. GKN Hydrogen’s modular platforms (HY2MINI, HY2MEDI, and the larger HY2MEGA configurations) are designed for

From planning to construction, we guide our clients through a new era of energy, making their dreams a reality. 80 years of hydrogen firsts. Experience to accelerate your vision. Bolder Vision for the hydrogen economy

LEARN MORE

repeated charge and discharge cycling over extended operational lifetimes, while maintaining stable storage capacity. Each storage module incorporates extensive temperature and pressure sensing to manage the exothermic absorption and endothermic release processes. Deploying modular units within PC-based control platforms also enables scalability. For example, additional storage modules can be integrated via standardised fieldbus connections without reengineering the entire architecture. Integrated safety I/O processes overtemperature or overpressure signals within the same framework, reducing hardware duplication while maintaining safety standards.

Automation and hydrogen mobility

Hydrogen is set to transform transportation and mobility. Heavy-duty vehicles, trains and even aircraft are turning to hydrogen to cut carbon emissions. However, hydrogen fuelling presents challenges distinct from traditional petrol or diesel. Fuel must be dispensed at pressures up to 1000 bar. Every step of the dispensing process must be monitored for safety, efficiency, and reliability. Fast-filling protocols require precise pressure ramping and temperature compensation. During rapid compression, hydrogen temperature rises significantly, and without active pre-cooling and controlled flow rates, vehicle tank limits could be exceeded. Automation must therefore not only offer real-time control, but also seamless integration with Internet of Things (IoT) platforms. Operational data is captured and transmitted securely to cloud-based systems, enabling remote monitoring and optimisation of maintenance schedules. A good example of what this looks like in practice is provided by Cavendish Hydrogen, a developer of hydrogen fuelling stations. Its stations are capable of serving dozens of vehicles daily and rely on fast, reliable control systems to manage the entire fuelling process — from monitoring tank pressure and temperature to detecting leaks and ensuring safe refuelling. Real-time data from sensors is analysed instantly to control fuelling precisely, while simultaneously being transmitted to remote monitoring platforms. This approach ensures safety and efficiency of individual stations as well as providing fleet-wide insights that support wider system optimisation and predictive maintenance. During dispensing, pressure ramp rates must follow defined fuelling protocols to ensure safe and efficient vehicle tank filling, particularly for 350 bar and 700 bar applications. Pre-cooling systems are synchronised with flow control to compensate for temperature increases during rapid filling, while leak detection and emergency shutdown systems remain continuously active. These refuelling stations typically use Beckhoff embedded PCs such as the CX5140 with EtherCAT communication and TwinCAT software to control the entire fuelling process. Real-time data from sensors monitoring pressure, temperature, flow, and gas detection are captured and distributed to cloud-based supervisory systems. Fast signal processing is critical and a key requirement for consumer acceptance and uptime. Milliseconds between sensor capture and action allow the system to behave as

GlobalHydrogenReview.com

Summer 2026

responsively as modern petrol and diesel pumps. This control approach emphasises open communication standards and software flexibility, enabling reuse of code across platforms and easier scaling to meet future demand as station throughput is expected to grow significantly. An open architecture also facilitates seamless communication between diverse sensors, actuators and cloud services, regardless of manufacturer. It ensures future-proofing that allows operators to upgrade or expand their systems easily as technology requirements evolve. This interoperability is particularly valuable for operators managing multiple stations across regions, as it enables harmonised performance benchmarking, remote diagnostics, and software updates without disrupting operations.

Resilience and safety

Safety is paramount at every stage of the hydrogen value chain. Explosion risks must be mitigated not only in high-risk zones but throughout entire facilities. Automation platforms must therefore offer integrated functional safety, with the ability to process safety-relevant signals alongside regular process data. Certified safety controllers and intrinsically safe I/O modules enable direct installation in hazardous areas, reducing the need for additional barrier cabinets and complex wiring. By using deterministic processing, systems given the same input and conditions will always produce identical, predictable outputs. This means gas detection signals, emergency stop circuits, and pressure relief triggers are all considered to ensure that protective actions occur within defined response times. Combining standard and safety control within one environment also simplifies validation and documentation processes. In hazardous areas, equipment must be certified for explosion protection. Intrinsically safe input and output modules that are capable of operating directly within explosion zones, can dramatically simplify system design and reduce installation costs. They also allow for more flexible system layouts, essential for sprawling hydrogen production plans or refuelling sites. Ensuring resilience against system failures is also crucial. Redundancy in communication networks, controllers and data storage projects against downtime supports continuous operation. Whether monitoring hydrogen pipelines that stretch for kilometres or managing distributed storage units, a robust, fail-safe approach is vital, especially for facilities participating in grid balancing or long-term supply contracts. The rapid rise in hydrogen projects shows that momentum is building at an unprecedented rate. Automation technology is keeping pace, evolving to deliver the flexibility, safety, and intelligence this sector demands. By embedding smart control across the entire hydrogen value chain, the industry can fulfil the enormous potential forecast by the International Energy Agency, driving forward a cleaner, greener energy future.

Reference 1. Hydrogen Council. ‘Global Hydrogen Compass: Introduction and highlights’, https://compass.hydrogencouncil.com/

s the global energy landscape pivots toward sustainability, hydrogen has emerged as a cornerstone for long-term, large scale energy storage and decarbonisation. The strategy of power-to-gas (P2G) utilises surplus renewable power to produce hydrogen, effectively acting as a chemical battery for the power grid. However, transitioning from a natural gas-based infrastructure to a hydrogen economy presents engineering challenges. To move from theory to implementation, the industry must develop advanced centrifugal compression and pumping technologies capable of handling a gas that is notoriously light, highly diffusive, and chemically aggressive toward traditional materials.

Hydrogen in the energy value chain

The appeal of hydrogen lies in its versatility. It can be stored at high pressures, approximately 2900 psia (200 bar), for long-duration energy storage and transported through pressurised pipelines at up to 1450 psia (100 bar), as seen in Figure 1. This capability is critical for addressing the daily and seasonal fluctuations inherent in renewable energy sources like wind and solar. Currently, hydrogen production is categorised by ‘colours’ based on the carbon footprint of its generation; green hydrogen is produced via electrolysis using curtailed renewable electricity, blue hydrogen is derived from fossil fuels (typically via steam methane reforming) but is coupled with carbon capture and sequestration (CCS) to mitigate emissions, and pink hydrogen is produced using nuclear power to drive electrolysis.

Each of these pathways requires a unique compression profile. For instance, while initial blue hydrogen production may occur near existing gas-fired plants, which reduces the need for long-distance transport, the long-term evolution toward green hydrogen will likely require extensive pipeline networks to connect remote renewable sites to industrial hubs (Figure 2).

Why hydrogen is hard to compress

The most significant hurdle in hydrogen transport is the sheer energy required for compression. For an equivalent energy content, hydrogen compression demands 5 - 6 times the power required for natural gas.2 This energy intensity is a direct result of hydrogen’s thermodynamics. Hydrogen possesses a very low volumetric energy density and a very high specific heat. Because it is so light, centrifugal compressors must generate significantly more ‘head’ per stage

Figure 1. Hydrogen gas storage pressures and temperatures.1

Figure 2. Production means of hydrogen with indicated compression points.2

Figure 3. Effect of hydrogen pressure on ductility of 304L stainless steel tested to fracture in hydrogen gas at room temperature.3

GlobalHydrogenReview.com

Summer 2026

to achieve a meaningful pressure ratio. Thermodynamically, the pressure ratio is inversely proportional to the gas’ specific heat (cp); as cp increases, the pressure rise for a given amount of work decreases. To compensate, engineers must design compressors with increased staging, utilising many more impellers or casings in series than are required for natural gas and ultra-high tip speeds, which increases rotational speeds to maximise head per stage. One silver lining in hydrogen’s physical properties is its extremely high speed of sound, reaching nearly 4140 ft/sec. (1250 m/sec.) at pipeline pressures. This means that, unlike CO2 compression, hydrogen compression typically results in low machine Mach numbers. Consequently, mechanical stress and material limits usually become the governing constraints long before aerodynamic Mach limits are reached.

The battle against embrittlement

The push for higher rotational speeds to achieve better head is restricted by the phenomenon of hydrogen embrittlement (HE). Hydrogen molecules have the smallest atomic size and the highest diffusivity of any element, allowing them to settle within the metal lattice of a compressor’s rotating parts. While hydrogen does not necessarily change the yield or tensile strength of a material, it drastically reduces its ductility (Figure 3). This transition from ductile to brittle behaviour can lead to catastrophic failure under stress. To manage this risk, API Standard 617 strictly limits the material yield strength to 120 ksi (827 MPa) for high-hydrogen environments. Engineers are forced to balance weight, strength, and chemical compatibility, and some candidate materials include: y Steel: standard martensitic stainless steels (like 15-5PH) are common but must remain below hardness and strength thresholds. y Titanium: offers an excellent strength-to-weight ratio but is highly susceptible to forming brittle hydrides in hydrogen environments. y Aluminium: high-strength alloys (like 7075-T6) are promising and commonly used for impellers, because they are generally resistant to dry hydrogen embrittlement. However, they lose significant strength at temperatures above 392°F (200°C) and can embrittle if moisture is present.

Advancing compressor architectures

Because no single machine can meet the diverse needs of the hydrogen economy, several architectural options are in development. Inline barrel compressors are the workhorses of the refinery industry. They are highly reliable and robust, but for pure hydrogen service, they often require multi-body strings (multiple casings in series), because a single casing cannot accommodate the necessary number of stages to reach high pressures. Integrally geared compressors (IGC) allow each stage to operate at its own optimised speed by utilising a multi-pinion gearbox. They are compact and allow for easy inter-cooling between stages, which brings the process closer to isothermal compression and saves power. However, the high number of seals required (one per stage) can increase the risk of leakage.

Trust Ebara Elliott Energy

to Close the Gap in the Global Hydrogen Value Chain. As the world moves from hydrogen pilot projects to commercial-scale infrastructure, the requirement for absolute reliability has never been higher. Ebara Elliott Energy provides the missing link in the energy transition. By offering a total solution for both liquid and gas phases—including our high-pressure booster pumps and cryogenic return gas blowers—we enable the safe, efficient, and scalable transport of hydrogen. We don’t just anticipate the needs of a decarbonized society; we engineer the equipment that makes it possible. Learn more about our range of service capabilities at elliott-turbo.com.

Trusted Solutions for a Sustainable Future COMPRESSORS | STEAM TURBINES | P U M P S | GLOBAL SERVICE

For applications requiring high flow but limited pressure ratios, a double-ended motor driving a compressor on each side is an effective, high-reliability solution.

Pumping liquid hydrogen (LH2)

While gas compression is the standard for pipelines, moving hydrogen in its liquid phase offers distinct advantages for transportation and storage. Liquid hydrogen (LH2) is approximately 850 times denser than hydrogen gas at atmospheric pressure. To handle LH2 at cryogenic temperatures of -423°F (-253°C), engineers utilise submerged motor centrifugal pumps (Figure 4). In this design, the electric motor is completely immersed in the cryogenic fluid. This provides excellent cooling for the motor and eliminates the need for complex shaft seals that would otherwise leak gaseous hydrogen. These pumps often utilise ceramic ball bearings because LH2 has a very low viscosity (0.013 cP), requiring extremely smooth surfaces to maintain a lubricating film. Given the difficulties of transporting pure hydrogen, ammonia (NH3) is being explored as a carrier.

Ammonia is easier to liquefy and store than pure hydrogen, but it is chemically aggressive toward copper and highly toxic. Advanced seal-less ammonia pumps solve these issues by isolating the motor stator from the process fluid using a ‘can’ structure and employing product-lubricated bearings (Figure 5). This technology allows for the safe handling of ammonia as a medium for moving hydrogen across global trade routes.

Safety and infrastructure challenges

Transitioning existing natural gas infrastructure to hydrogen involves more than just swapping compressors. Hydrogen has a broad flammability range (4 - 75% in air) and a low auto-ignition temperature. Because hydrogen molecules are so small, they permeate and leak through materials far more easily than methane. Elastomer O-rings (typically FKM) are scrutinised for their ‘satisfactory’ chemical compatibility with hydrogen gas and extrusion resistance at high pressures. Furthermore, traditional gas detectors and flow meters must be replaced with hydrogen-specific semi-conductor or ultrasonic technology to ensure accurate monitoring. Legacy pipelines made of high-strength steel are particularly susceptible to embrittlement. Current research suggests that blending up to 20% hydrogen into existing natural gas streams may be possible with minimal modifications, but 100% hydrogen service will likely require entirely new infrastructure or significant upgrades.

Conclusion: engineering the future

Figure 4. Cryogenic centrifugal submerged motor pump (courtesy of Ebara Elliott Energy).

The shift toward a hydrogen-based energy economy is not merely a policy goal; it is a massive undertaking for mechanical and material engineering. While centrifugal compressors and pumps are technically mature for many gases, pure hydrogen pushes these machines to their physical limits. Success will depend on the continued development of: y Innovative materials: beyond standard steels, exploring composites and advanced coatings to allow for higher tip speeds without embrittlement. y Advanced compression trains: combining the high flow of centrifugal designs with the pressure capabilities of multi-body staging. y Cryogenic mastery: improving the efficiency and reliability of LH2 and ammonia transport systems to enable a global hydrogen trade. As the industry moves forward, the collaboration between OEMs, research laboratories, and grid operators will be essential to ensure that hydrogen fulfils its promise as the clean energy carrier of the 21st century.

References

Figure 5. Example of a seal-less ammonia pump (courtesy of Ebara Elliott Energy).

GlobalHydrogenReview.com

Summer 2026

1. KURZ R., ALLISON T., and BRUN K., ‘Pipeline Compression for the Hydrogen Economy’, DOE Seminar, (2021). 2. ALLISON, T., KLAERNER, J., CICH, S., KURZ, R., and MCBAIN, M., ‘Power and Compression Analysis of Power to Gas Implementations in Natural Gas Pipelines with up to 100% Hydrogen Concentration,’ Proceedings of ASME Turbo Expo, (2021), Paper GT2021-59398, https://doi.org/10.1115/GT2021-59398 3. BRUN,K., ALLISON,T., KURZ,R., and WYGANT, K., ‘Energy Transport Infrastructure for a Decarbonized Economy’, Elsevier, Amsterdam, the Netherlands, (2025).

Sébastien Kohler and Samuel Stutz, Greene Tweed, Switzerland, analyse how a new technological development in high-speed composite impeller design can address the challenge of hydrogen compression.

ydrogen is a key to a sustainable energy future, but compressing it efficiently is one of the industry’s greatest engineering challenges. Transporting hydrogen through extensive pipeline networks requires large centrifugal compressors to maintain large volumes of gas at an adequate pressure. However, traditional centrifugal compression technology has reached a physical threshold dictated by the materials used to construct impellers. While metallic impellers have been the industry standard for decades, they cannot withstand the operational speeds required to compress a gas as light as hydrogen efficiently.

To overcome this limitation, Greene Tweed initiated the R&D of a closed composite impeller in 2020, capable of operating well beyond the burst limit of traditional metal impellers. By leveraging carbon fibre-reinforced polyetheretherketone (C/PEEK), the engineering team achieved a tip speed of 688 m/sec. This advancement represents a breakthrough in the application of high-performance thermoplastic composites and opens up a new design space for aerodynamic engineering. It establishes a new benchmark for centrifugal compressor technology and paves the way for scalable, cost-effective hydrogen infrastructure.

A new impeller tip speed

To understand the significance of a 688 m/sec. tip speed, it is necessary to examine the physics of centrifugal compression and the unique properties of hydrogen gas. Centrifugal compressors increase the pressure of a gas by adding kinetic energy through a rotating impeller, which is then converted into potential energy (pressure) in a diffuser. Hydrogen’s very low molecular mass means compressors must spin much faster to achieve a compression ratio that enables an economically viable compression of the lightest element of the periodic table. While heavier gases can be effectively compressed at moderate speeds, hydrogen needs tip speeds that exceed 600 m/sec. to reduce the number of required compression stages to a practical level. Traditional metallic impellers fail to meet this requirement due to two primary limitations: y Centrifugal stress and burst limits: as an impeller spins, it experiences immense centrifugal forces. The stress on the material increases with the square of the rotational speed. The faster the impeller spins, the more dramatically the rotation induced stress it has to withstand increases. Conventional metallic impellers typically reach their mechanical limit and burst at speeds around 360 m/sec. for closed designs and 500 m/sec. for open designs.

y Hydrogen embrittlement: when exposed to hydrogen under high pressure, certain metals absorb hydrogen atoms into their crystalline lattice. This process, known as hydrogen embrittlement, degrades the mechanical properties of the metal, resulting in microscopic cracking, loss of ductility, and catastrophic failure under high-stress conditions. Because metallic impellers cannot safely exceed 500 m/sec. in the best of circumstances, operators are forced to use multiple compression stages to reach the desired pipeline pressure. Each additional stage increases the physical footprint, CAPEX, and maintenance requirements of the compressor station.

How thermoplastic composites solve hydrogen challenges

The engineering team broke the 600 m/sec. barrier by turning to advanced thermoplastic composites, specifically carbon fibre-reinforced PEEK (C/PEEK). This material choice provided a pathway to resolve the weight, strength, and chemical compatibility issues inherent in metal impellers.

Strength-to-weight superiority The primary advantage of C/PEEK in centrifugal applications is its exceptional specific strength (strength-to-weight ratio). The C/PEEK composite is close to five times lighter than conventional metals used in compressor impellers and offers three times their strength-to-weight ratio. Because centrifugal force increases with the mass, radius, and the square of angular velocity, reducing the mass of the impeller drastically lowers the internal stresses generated at high rotational speeds. C/PEEK composite allows the composite impeller to spin significantly faster before reaching its breaking point.

Resistance to hydrogen embrittlement

Figure 1. A centrifugal compressor with composite impellers shown in yellow.

Table 1. Material comparison for centrifugal impellers

Property

Traditional metallic C/PEEK composite alloys

Maximum safe tip speed

~360 m/sec. (closed), 500 m/sec. (open)

≥ 688 m/sec. (closed)

Relative weight

High (baseline)

5x lighter

Strength-toweight ratio

Moderate

3x higher

Hydrogen embrittlement risk

High (requires specialised alloys)

None

Stage requirement for hydrogen

High (due to low per-stage pressure)

Low (due to high tip speed)

GlobalHydrogenReview.com

Summer 2026

Unlike metallic alloys, polymers and carbon fibres do not feature crystalline lattice structures susceptible to hydrogen embrittlement. Extensive testing confirmed that the C/PEEK matrix and carbon fibre reinforcement remain chemically stable and structurally sound when exposed to pure hydrogen gas at high pressures. This chemical compatibility ensures long-term reliability and mitigates the risk of sudden mechanical failure in demanding continuous-operation environments.

Engineering the new impeller

Transitioning from a theoretical material advantage to a functional, brand new component required a rigorous approach to composite manufacturing. The development of the composite closed impeller spanned three rigorous design and testing cycles, integrating advanced methodologies to optimise the geometry and internal structure of the part.

Advanced computational modelling and testing The design process relied heavily on finite element analysis (FEA). By simulating the extreme centrifugal loads that the

Engineered to Scale Hydrogen Compression

Greene Tweed is your partner to achieve efficient hydrogen compression with fewer stages, lighter rotating mass, and stronger infrastructure economics With proven composite impeller technology validated at record burst tip speeds up to 688 m/s, Greene Tweed helps OEMs and service providers go beyond the limits of conventional metallic designs. Our advanced thermoplastic composite manufacturing capabilities support lighter, stronger impellers for hydrogen compressors and other high-performance rotating equipment—backed by the engineering expertise and responsive partnership you need to develop next-generation critical equipment and components.

Learn how Greene Tweed is meeting the demands of Hydrogen power

gtweed.com

impeller would face, engineers could identify and mitigate stress concentrations. To validate these digital models, the team used in-situ, high-speed camera analysis and digital image correlation (DIC). It allowed the engineering team to track microscopic deformations and strain patterns across the surface of the impeller during active spin testing. In observing exactly how and where the material deformed under load, the team refined their computational models and adjusted the impeller geometry to distribute stress more evenly.

Innovative manufacturing techniques The performance of a carbon fibre composite is highly dependent on fibre orientation. In a centrifugal impeller, the mechanical loads are complex and multi-directional. To address this, the manufacturing process utilised quasi-isotropic layups. This technique involves layering the carbon fibre prepregs in multiple directions, ensuring that the final material possesses uniform strength across its plane. Furthermore, the molding process was heavily optimised to eliminate fibre misalignments and void formations within the thermoplastic matrix. Consistent material properties throughout the impeller are critical, as even a minor microscopic defect can propagate into a catastrophic failure when subjected to the extreme kinetic energy of a 600+ m/sec. tip speed rotation. The material science and engineering culminated in a composite closed impeller that achieved a tip speed of 688 m/sec. during spin testing. This result nearly doubles the operational speed of traditional closed metallic impellers and far exceeds the 600 m/sec. target required for efficient hydrogen compression.

Impact on the hydrogen economy

The development of a composite impeller carries immediate and profound implications for the global hydrogen economy. By enabling centrifugal compressors to handle pure hydrogen efficiently, this technology addresses a major logistical bottleneck in the clean energy transition.

Reducing capital and operational costs Because the high-speed impeller imparts significantly more kinetic energy into the hydrogen gas, it achieves a

Figure 2. Hydrogen renewable energy production. Courtesy of R. Classen, Shutterstock.

GlobalHydrogenReview.com

Summer 2026

much higher compression ratio per stage. For pipeline operators, this means a centrifugal compressor requires fewer stages to reach the target pressure. Fewer stages directly translate to smaller compressor footprints and lower capital costs for hydrogen recompression stations.

Enabling pipeline scalability Global clean energy initiatives, like the European Hydrogen Backbone, rely on the ability to move massive volumes of hydrogen across vast distances reliably. In reducing the size, cost, and complexity of the required compression stations, the composite impeller makes the construction and operation of widespread hydrogen pipeline networks economically and technically viable.

Beyond hydrogen: expanding the scope of thermoplastic composites

While the composite impeller was engineered specifically to solve the challenges of hydrogen compression, the underlying technology and manufacturing methodologies have broad applications across the industrial sector. For other industrial gases, the ability to operate impellers at exceptionally high tip speeds offers similar benefits: higher per-stage compression ratios, reduced equipment footprints, and lower CAPEX. It can also help with higher chemical compatibility, non-existent corrosion and fouling resistance in certain cases where metallic impellers are ill suited to certain trace elements in the gasses they need to compress. This project demonstrates that thermoplastic composites can successfully replace metallic components in extreme, high-stress environments. This advancement is poised to inspire further research and development into structural thermoplastic composites across multiple sectors. Aerospace, energy generation, and chemical processing industries all face challenges related to weight, rotational stress, and chemical degradation. The proven performance of C/PEEK under extreme centrifugal loads provides a clear use-case for integrating these advanced materials into future mechanical designs, from compressor vanes to high-speed industrial fans.

The path to scalable hydrogen infrastructure

The development of the composite impeller addresses the fundamental challenge of compressing light gases like hydrogen, which demand impeller tip speeds beyond the safe limits of traditional metals. By engineering a solution with carbon fibre-reinforced PEEK, a material five times lighter than steel and immune to hydrogen embrittlement, the new development achieved an unprecedented tip speed of 688 m/sec. This breakthrough enables more efficient and cost-effective hydrogen compression – reducing the number of compressor stages and overall infrastructure costs – and sets the stage for future adoption of thermoplastic composites across other demanding industrial applications, from gas compression to aerospace and energy systems.

Nico Schmaeling, John Crane, UK, discusses the innovations behind sealing solutions in hydrogen pumps and compressors.

he energy transition is often associated with cutting-edge clean technology innovations, bold new start-ups, and ambitious digital transformation initiatives designed to overhaul existing infrastructure. But what lies beneath these trends is a different story. A story of quiet innovation, precision engineering, and small, incremental changes that move the needle when it comes to sustainability. Every energy system relies on thousands of small components working perfectly together. Pipelines carry fuels across long distances and rely on compressor or pumping stations to do so. Compressors move gases, pumps move liquids, and hidden inside many of these machines are sealing solutions that prevent hydrocarbons from leaking into the atmosphere. These components rarely make the news, but they matter enormously. Without these small engineering innovations, many of the ambitious energy transition goals would remain out of reach. Why? Because the first step towards decarbonising traditional industries is improving the efficiency of their operations today. 2026 marks the 50th anniversary of dry gas seal technology. For half a century, this innovation has quietly helped industries operate more safely and efficiently. Today, it plays an important role in some of the most pressing challenges of the modern day: reducing emissions, improving industrial reliability, and making green hydrogen a more viable source of clean energy. It is a reminder that the energy transition is not only about cutting-edge, clean-tech inventions and new fuels (although they are of critical importance). It is also about increasing the efficiency of existing equipment and more effective system integration.

The challenges behind the hydrogen opportunity

Hydrogen and its derivatives have become one of the most talked about energy solutions in the world. Governments see it as a tool for decarbonising energy supply. Energy companies themselves see it as a way to store renewable power. Transport companies see it as a route to cleaner fuels for trucks, ships, trains, and even planes. While natural gas and coal are today’s primary sources of hydrogen production, there is growing momentum behind clean, electrolytic hydrogen. Using renewable green electricity to produce hydrogen can help decarbonise key sectors that traditionally rely on fossil fuels. However, scaling a renewable hydrogen economy requires the product to be more cost-competitive to increase demand and offtake. Faster progress in cost reduction, safety, and efficiency is needed. The issue is that hydrogen brings its own set of challenges. Hydrogen molecules are extremely small, making compression technically more challenging. Hydrogen also has a wide flammable range in air with a nearly invisible flame. These properties make hydrogen difficult to handle safely and efficiently. If hydrogen production sites remain exotic, specially designed installations, costs will remain high. If they are more modular and scalable – as seen for LNG trains – hydrogen becomes far more viable as a large scale energy solution.

Figure 1. Inside innovation, where advanced design meets operational performance.

At the moment, there is no single solution for hydrogen storage or distribution. While compressed gas storage is the most prevalent method used in industry today, it does not deliver the same volumetric energy density as natural gas. Obviously, liquefied hydrogen offers higher energy density. However, liquifying and then storing hydrogen requires specialised equipment capable of withstanding cryogenic temperatures as low as -253°C. Solid-state storage approaches are emerging as a new area of innovation in this space. This involves chemically binding hydrogen with a metal to form a solid metal hydride. The metal absorbs hydrogen, much like a sponge, and when it is heated, the hydrogen is released. This approach offers a simpler alternative, as it eliminates the need to manage pressurised tanks or complex cryogenic systems.

A viable transport infrastructure

Safe, reliable infrastructure for hydrogen transport is critical for the new hydrogen value chain. Existing methods for moving compressed and liquid hydrogen include pipeline and truck transport. Pipeline networks are an established method for transporting gases under pressure. However, existing infrastructure, typically designed for natural gas transport, is not hydrogen-ready. Using trucks to transport compressed hydrogen cylinders is a simple alternative. However, the CO2 emissions associated with hydrogen transportation could offset its sustainability benefits unless trucking is decarbonised. The good news is that new methods for transporting clean hydrogen are emerging, offering promising alternatives to traditional approaches. For instance, liquid organic hydrogen carriers (LOHCs) enable hydrogen to be bonded to a stable organic liquid, allowing it to be transported using conventional infrastructure. Liquid ammonia is another promising solution, as it is already a globally traded commodity with established transport networks. The hydrogen and nitrogen can then be separated at the destination, improving delivery efficiency and cost-effectiveness. These examples demonstrate why evaluating existing methods and developing new options for hydrogen storage and distribution is essential. Reducing the cost and complexity of each step of the hydrogen value chain is critical to scaling adoption. This is where innovations in mechanical sealing come into play.

A small innovation with a big impact

Figure 2. Engineering excellence at scale, delivering quality through every stage of production.

GlobalHydrogenReview.com

Summer 2026

Rotating equipment is critical and supporting reliable delivery at scale requires a range of technologies to enable compression, expansion, pumping, and filtration, as well as secondary processes, such as those that maintain cryogenic conditions. In any gas pipeline ecosystem, compressors are key critical pieces of rotating equipment used to move gases under high-pressure. Traditional sealing technologies relied on oil lubrication, which led to inherent leakage. Over time, those leaks added up to higher emissions and lower efficiency. Dry gas seals changed that equation. Pioneered and continuously advanced by companies like John Crane, these businesses have transformed compressor performance across multiple industries. Instead of relying on oil, these seals use a thin film of gas between the rotating surfaces to create a non-contacting operating mode. The result is extremely low

leakage and minimal friction. Equipment runs more efficiently and requires less maintenance. Typical dry gas seal applications in the hydrogen value chain include compressors and turboexpanders. Moreover, effective mechanical seals and seal support systems are key for transporting ammonia, making LOHCs more reliable, and enabling cryogenic liquid hydrogen storage. At first glance, dry seals may seem like a modest innovation. But their impact has been profound. Over the past five decades, dry gas seals have become standard technology across industries, including oil and gas, chemicals, and power generation. Their environmental impact has also been significant. In certain applications, wet-to-gas seal retrofit programmes have reduced CO2 emissions by 278 000 tpy, while modern dry gas seals can reduce methane and fugitive emissions by up to 95% when replacing traditional oil-lubricated wet seals. That translates into hundreds of thousands of tonnes of avoided CO2 emissions every year. What started as a reliability improvement has become an important tool for making industrial equipment more sustainable.

Figure 3. Precision in every detail, ensuring reliability where it matters most.

Innovation driven by partnership

The challenges facing the hydrogen industry are not theoretical. They are being solved in real time by engineers working with customers on complex industrial systems. Industry players are evolving innovation strategies to meet these challenges. As a result, the focus is shifting from individual components to integrated solutions that support entire energy systems. In the hydrogen sector, this means working closely with operators to understand how compressors, turbines, and storage facilities perform under real conditions. Hydrogen’s unique properties require sealing technologies that can withstand high speeds and hydrogen embrittlement while preventing leakage. For example, most compressors are compatible with natural gas, which is primarily methane. As hydrogen has a molecular weight much lighter than methane, it requires extremely high impeller-tip speeds to reach usable output pressures. This ‘need for speed’ challenges the material-strength limits of many components, including dry gas seals. Another factor to consider in sealing solutions for hydrogen applications is material selection. A carbon-based primary ring can be relatively mixed-friction-tolerant due to carbon’s self-lubricating properties. However, a mating seal ring of silicon carbide or tungsten carbide may benefit from a specialised coating to increase durability when put into intermittent service. Using the right materials is critical for reducing friction and ensuring the longevity and reliability of dry seal technology. It is also important to remember that many hydrogen projects are being developed alongside existing natural gas or industrial systems. In these scenarios, retrofitting and adapting equipment becomes essential. Sealing technologies must therefore be flexible enough to support both current operations and future hydrogen applications.

Quiet technologies enabling big transitions

The energy transition is often framed as a competition between strategies: molecule vs electron, decarbonisation vs efficiency,

Figure 4. Protected from the moment it leaves the workshop, ready to perform from day one. photovoltaic panels vs wind turbines, electrification vs synthetic fuels, but the reality is more complex. Large energy systems depend on countless supporting technologies that rarely appear in public discussions. Seals, filters, and couplings may not capture headlines, but they determine how efficiently those systems operate. In hydrogen infrastructure, reliability is essential. A single leak can mean lost product, safety risks, and higher operating costs. Effective sealing technologies, therefore, become foundational components of the entire value chain. When those technologies improve, the entire system becomes more viable. As the world moves toward a low-carbon future, engineering innovation will remain essential. Hydrogen production is expected to grow rapidly over the coming decades. But scaling the technology will require advanced equipment capable of operating reliably for long periods under demanding conditions. This will involve new materials capable of handling emerging energy carriers and sealing solutions designed specifically for hydrogen-rich environments. It will also involve continued cross-industry collaboration. The most effective innovations often emerge when engineers and operators work together to solve problems. 50 years after the introduction of dry gas seals, the lesson remains clear. Sometimes, the most important breakthroughs are the ones quietly improving the machinery that powers the world.

Summer 2026

GlobalHydrogenReview.com

Andrés Hernando, Hiperbaric, discusses how Spain’s Castilla y León is leveraging a 96% green grid to build a €385 million continental hydrogen hub.

astilla y León stands today in a position of natural leadership within the European energy transition. Its vast geography, in the northwestern quadrant of the Iberian Peninsula, makes it a privileged setting for clean energy generation. With a consolidated renewable infrastructure that already allows it to cover 96% of its internal electricity demand through wind and solar sources, the region produces nearly double the energy it consumes. This energy reality, far from being a ceiling, is the launchpad for a greater ambition: to transform that renewable surplus into a versatile, storable, and high-value-added energy vector. The region possesses not only the resources but also the industrial vision and technical capacity to lead the creation of a robust and scalable hydrogen economy. Under this approach, CyLH2Valley (Castilla y León Hydrogen Valley) was born. This is a systemic initiative, led by the Cartif Technology Centre and the Castilla y León Hydrogen Association (H2CYL), with the close academic and scientific collaboration of the University of Burgos (UBU). The Valley is a circular and multidisciplinary ecosystem, co-funded by the EU through the Clean Hydrogen Partnership and the Horizon Europe programme. With a mobilised investment of €385.1 million, the project integrates a consortium of 36 strategic partners from nine countries. CyLH2Valley aims to establish the Castilla y León Hydrogen Valley by developing a large scale hydrogen ecosystem in the region, which includes 11 pilot facilities covering the entire hydrogen value chain: from production and distribution to end-use in mobility, industry, and energy. This industrial deployment is estimated to generate more than 2000 direct and indirect jobs over the next 10 years, becoming a driver of socio-economic development and population stabilisation in the territory.

The objective of CyLH2Valley is to establish an infrastructure capable of producing more than 19 321 tpy of green hydrogen, which will prevent the emission of 152 000 tpy of CO2. Fully operational for the 2028 - 2030 period, the Valley is positioning itself as a technical benchmark for the decarbonisation of the hardest-to-abate sectors, from heavy chemicals to long-haul transport.

The 11 pillars of decarbonisation: a connected ecosystem

For renewable hydrogen to consolidate itself as a commercial solution, it must demonstrate robustness at every stage of the value chain. In CyLH2Valley, this principle has materialised through 10 + 1 pilot sites, covering renewable energy generation, industrial transformation, and mobility, forming a fully integrated and operational ecosystem. Large scale hydrogen production is structured around Pilots P1A developed by Univergy, and P1B, by Ignis, two high capacity electrolysis plants that leverage Castilla y León’s exceptional renewable resources. Their renewable hydrogen powers some of the valley’s most energy-intensive industrial processes. In chemical transformation, Pilot P2, by the company Elyse, enables the production of synthetic methanol using green hydrogen and captured CO2, while Pilot P3, by Buramove, demonstrates the feasibility of green ammonia through the Haber-Bosch process. This transition to green fuels is a decisive step toward replacing fossil-based alternatives and achieving a significant reduction in industrial CO2 emissions. The metallurgical sector advances toward decarbonisation with Pilot P6 which adapts aluminium furnaces to operate with progressive hydrogen blends while maintaining thermal efficiency and material quality. These initiatives represent a structural shift in industries traditionally dependent on natural gas. In the field of essential public services, Pilot P7, headed by a hospital management company, integrates hydrogen into its thermal system through controlled blending of hydrogen with natural gas, proving that critical infrastructures can reduce emissions without compromising safety or operational continuity. Sustainable mobility is deployed through Pilot P4, under the leadership of Joanca, for heavy duty transport using

Figure 1. Castilla y León in Spain is a key benchmark in sustainable energy production.

GlobalHydrogenReview.com

Summer 2026

FCEV trucks and Pilot P5 (Burgos City Council) for fuel cell urban buses. Both applications rely on Pilot P8 (managed by Hiperbaric, Desmasa, Aciturri, and Beroil), a high flow hydrogen refuelling station (HRS) with dispensers at 350 and 700 bar, serving as the central hub for refuelling buses, trucks, and light vehicles, and with tube trailer filling capacities. Fixed infrastructure is reinforced with Pilot P9 led by Buramove, a 1.5 km hydrogen pipeline that connects P9’s production plant with the refuelling station, ensuring stable and continuous supply. Finally, Pilot P10, by Youta, represents the first regional upscaling phase: a new photovoltaic powered electrolysis plant that increases hydrogen production capacity and connects the valley’s deployment with future expansions across Castilla y León. Together, these 10 + 1 pilots constitute a complete architecture that demonstrates, under real operating conditions, how renewable hydrogen can transform industrial processes, decarbonise mobility, and strengthen regional energy security.

The multimodal refuelling hub: powering hydrogen mobility

Technically known as the Tube Trailer Filling (TTF) High Flow Hydrogen Refuelling Station (HFHRS), Pilot 8 is an advanced service facility in the Hydrogen Valley, conceived as a high capacity, multimodal refuelling station capable of supporting both light and heavy duty mobility as well as regional hydrogen distribution. The station receives hydrogen from tube trailers and from the pipeline connected to Pilot 9, managing its compression in two stages: a booster that raises the pressure from 15 to 40 bar, and a main compressor that increases it up to 900 bar. The compressed hydrogen is stored in three banks at 300 bar, 500 bar, and 900 bar. Thanks to this configuration, the station achieves an operational throughput of around 1 tpd of hydrogen, allowing fast refuelling – approximately 5 minutes for light duty vehicles and up to 20 minutes for heavy duty trucks – in H35 (350 bar) and H70 (700 bar) modes. The dispensing system incorporates pre-cooling to ensure compliance with filling profiles and maintain operational temperatures within the required limits. The execution of Pilot 8 is the direct result of coordinated technical contributions from four industrial partners of the Valley. Hiperbaric provides compression systems, including both the booster and the main compressor capable of raising hydrogen pressure up to 900 bar, ensuring continuous flow under high demand operations. Aciturri supplies the 350 and 500 bar storage system, providing the storage volume necessary for sustained mobility and distribution operations. Beroil, in addition to leading the project engineering, manages permitting procedures, civil works, equipment integration, and supplies the 900 bar storage bank, enabling full commissioning of the facility. Desmasa, for its part, provides the dispensing system – including the H35 and H70 dispensers – along with the valve panels for tube trailer unloading, the cooling system, and the loading panel used for tube trailer filling for hydrogen distribution.

OUT NOW!

2024

A SUPPLEMENT TO HYDROCARBON ENGINEERING

2025

A SUPPLEMENT TO HYDROCARBON ENGINEERING

Exploring decarbonisation Exploring decarbonisation technology and solutions technology and solutions for the downstream sector

forA special thesupplement downstream sector focusing on decarbonisation pathways for the

Thisdownstream special supplement focuses on sector, highlighting innovative decarbonisation pathways for the technology and solutions that will help you downstream sector, highlighting innovative thrive within the energy transition. technology and solutions that will help you thrive within the energy transition.

Scan the QR code to download your Scan the QRof code free copy to download your EnviroTech 2025.

free copy of EnviroTech 2024.

Figure 2. Hiperbaric hydrogen compression factory.

hydrogen – the station can serve multiple vehicles consecutively without performance loss. This configuration allows the station to perform two vital functions simultaneously. First, high-pressure refuelling at 700 bar for light vehicles and long-haul trucks, and at 350 bar for buses and last-mile vans. Second, the Tube Trailer Filling (TTF) function, which allows for loading distribution trucks at pressures between 300 and 500 bar. This ‘tanker filling’ capability turns the station into a regional logistical hub, allowing hydrogen to be transported by road to supply other pilots in the valley that lack a direct pipeline connection.

Heavy mobility and real-world operability

Figure 3. Map of CyLH2Valley. With this technological configuration and the specialised contribution of each partner, Pilot 8 becomes the central element of the Hydrogen Valley’s mobility system, enabling refuelling for buses, trucks, and light duty vehicles, as well as tube trailer filling for distribution. It provides the operational flexibility required to demonstrate the viability of a renewable hydrogen ecosystem at regional scale.

The dual H2 compression revolution

Hiperbaric’s technology compresses the gas to the pressures required for movement. Compressing hydrogen is one of the most complex engineering challenges in fluid physics; due to its low density and small molecular size, hydrogen requires extreme precision to prevent leaks and ensure energy efficiency. The modular solution developed by Hiperbaric for Pilot 8 is a system capable of adapting to different pressure ranges. The most ambitious concept implemented at this station is its five-stage compression system, utilising two synchronised compressor modules. These units can raise the pressure from the 15 bar arriving via pipeline to the 900 bar required for hydrogen tanks storage. This pressure leap is fundamental: only at these pressures does hydrogen reach sufficient density to be stored compactly and dispensed rapidly. The station’s goal is to reach a dispensing flow of 4 kg/min. To understand the magnitude of this figure, it must be compared with first-generation hydrogen stations, which often require hours to recover pressure after a single refuelling. Thanks to the cascade storage system – with a capacity to dispense 1000 kg/d of

GlobalHydrogenReview.com

Summer 2026

The ultimate test for Hiperbaric’s technology and the Pilot 8 infrastructure is on the road, specifically in Pilot 4, featuring the Joanca fleet. Long-haul heavy transport is the sector that stands to benefit most from hydrogen, as conventional electric batteries would add excessive weight to trucks, reducing their payload. Joanca’s hydrogen FCEVs trucks have ranges of up to 1500 km and tanks holding 116 kg of hydrogen at 700 bar. Refuelling such a truck, as well as any other fuel cell vehicle, in under 30 minutes is a massive thermal challenge. As gas expands at high pressure, the temperature tends to rise; therefore, the station incorporates advanced cooling systems designed by Hiperbaric to pre-cool the gas to -40°C. In addition to long haul heavy duty vehicles, the station will also supply the fuel cell bus fleet operated by the Burgos City Council Pilot 5, which relies on Pilot 8 to ensure uninterrupted, zero emission urban transport service. The installation will likewise refuel the operational vehicles of Hiperbaric and Desmasa, used by both entities for project related activities requiring reliable access to hydrogen mobility. To efficiently manage these different user profiles, the station incorporates an integrated control and monitoring system that coordinates dispenser sequencing, regulates pressure and temperature parameters during filling, and optimises compressor performance. This system, jointly developed by the project’s technological partners Beroil, Hiperbaric, Aciturri, and Desmasa, ensures that each vehicle receives the appropriate refuelling conditions while maintaining the overall stability and performance of the installation.

Leading the way in energy sovereignty

Castilla y León offers ideal conditions: abundant natural resources, strategic logistics corridors connecting central Spain with Europe, and a solid foundation for industrial innovation. CyLH2Valley is a prime example of how a region can lead the way in energy sovereignty. By demonstrating the successful integration of large scale chemical production with a high-pressure, high-flow supply network, the project is not only decarbonising the region but also setting an industry standard that can serve as a model for other European regions.

Chloe Tindale, Air Products, UK, explores real-world deployments of hydrogen in transport and infrastructure projects, highlighting how policy frameworks can support its scale up.

ydrogen occupies a complex position in the global energy transition. Its role in decarbonising industry, heavy transport, and distributed energy systems is widely acknowledged, yet discussion around readiness often remains polarised. Headlines frequently focus on long-term future markets, large scale infrastructure plans, or the pace of government funding programmes such as the UK’s Hydrogen Allocation Rounds (HAR).

Alongside these discussions, an important but less visible story noise is that hydrogen is already being deployed today – safely, reliably, and at meaningful scale – in UK and European industrial operations, transport hubs, and innovation-led projects. Fleets are refuelling daily, assets are running to defined duty cycles, and operators are gaining practical experience that cannot be replicated through modelling alone. Governments recognise that it is important to back the hydrogen sector in order for it to scale up. Schemes and incentives across transport sectors have been created to encourage new hydrogen technology developments. Additionally, the UK’s HAR rounds aim to support the establishment and growth of a hydrogen market to meet long-term decarbonisation targets. However, hydrogen project developers and end-users frequently report that timelines and complex regulatory requirements involved can hinder progress, slowing down demand development and contributing to investment uncertainty. Experience to date suggests that one of the most practical routes to national hydrogen progress may be a blended approach: enabling the deployment of solutions that can operate effectively today, while also progressing long-term, strategic infrastructure, and scale-up projects. Maintaining diversity across hydrogen production, routes, delivery models, and end-use applications helps build resilience into the market – and resilience can accelerate adoption.

Hydrogen already in use and scaling

Globally, hydrogen has been widely used for decades across refining, chemicals processing, electronics manufacturing, and the space industry. What is newer is its growing role in decarbonisation focused applications, particularly in transport and power, where hydrogen is increasingly moving from concept to deployment. Across the UK and Europe, the established hydrogen supply assets and operational expertise already support trials as well as early full scale deployments. Operators are integrating hydrogen into existing systems where electrification is not always practical. The result is steady, incremental progress driven less by headlines and more by assets performing in the field.

Figure 1. Air Products’ station at Metrobus, Crawley.

GlobalHydrogenReview.com

Summer 2026

Hydrogen for bus and coach transport: lessons from deployment

In heavy duty mobility, particularly buses, coaches, and municipal service vehicles, hydrogen has emerged as a credible option, particularly where duty cycles are intense and vehicle uptime is critical. Its value is clearest in applications that require long daily range, fast refuelling, and predictable performance across passenger loads and operating conditions. Experience from operational bus fleets highlights several recurring considerations: y Range and uptime: hydrogen buses can support high daily mileage, even on highly topographical routes, without impacting passenger capacity or requiring mid-day charging. y Refuelling patterns: average refuelling cycles of under 10 minutes mirror conventional diesel operations and enable 24/7 service schedules. y Depot constraints: hydrogen, and in particular liquid hydrogen, refuelling infrastructure optimises space and can be integrated into existing depots without the need for extensive electrical upgrades, charging infrastructure, or excess fleet vehicles for rotation. y Operational consistency: operators require predictable energy performance across seasons and temperatures which hydrogen refuelling technology delivers. y Grid connection restrictions: in many locations, electrical grid constraints, connection delays, and upgrade costs limit the feasibility of full electrification. For many fleet operators, these factors influence technology choices as much as emission targets do. Hydrogen is not a one-size-fits all solution, but it is ideally suited for fleets in demanding operational requirements.

Metrobus, Crawley: hydrogen in routine service

Metrobus’ hydrogen bus deployment at its depot in Crawley, UK, illustrates how hydrogen can move from demonstration into routine operation when infrastructure design matches operational needs. At the Crawley site, a liquid hydrogen-based refuelling station supplies a fleet of 54 fuel cell buses operating routes around Gatwick Airport, Crawley, and Horley. Air Products designed, constructed, and operates the UK’s first commercial scale liquid hydrogen refuelling station to serve the fleet. Renewable, RTFO-certified, liquid hydrogen is delivered to the depot in liquid form, stored on site, and vaporised for refuelling at 350 bar. The fleet operates on demanding schedules, with buses typically covering around 370 km/d on Fastway routes. The depot surpassed 10 000 refuelling events within the first year of full operation, reflecting sustained daily use rather than trial activity. Refuelling times are taking 6 - 8 mins on average, allowing the hydrogen buses to integrate into existing depot workflows without extended downtime. Liquid hydrogen plays a critical technical role in this deployment. Its significantly higher energy density compared with gaseous hydrogen enables large fleets to be fuelled reliably on a daily basis. It allows for a compact station footprint, reduced delivery frequency, and minimised on-site power demand which is associated with high compression

The World’s Largest Hydrogen Trade Fair 20,000+ ATTENDEES

1,000+ EXHIBITORS

6 EXPO HALLS

200+ SPEAKERS

2 CO-LOCATED EVENTS

Hydrogen Technology Expo World is the must-attend conference and exhibition that is exclusively dedicated to discussing advanced technologies for the hydrogen and fuel cell industry. The event will bring together the entire hydrogen value chain to focus on developing solutions and innovations for low-carbon hydrogen production, efficient storage and distribution as well as applications in a variety of stationary and mobile applications.

I N PA R T N E R S H I P W I T H :

hydrogen-worldexpo.com

FREE TO AT TEND REGISTER NOW

gaseous systems. At Crawley, Metrobus provides a practical example of how hydrogen supply mode and operational requirements interact to create successful real-world service. Crucially, experience from deployments such as this highlight the importance of collaboration. Close coordination between the operator, vehicle manufacturer, hydrogen supplier, and local authorities has been essential in translating engineering capability into reliable service. Rather than focusing on technology in isolation, the project demonstrates how aligning supply mode, infrastructure design, operational practice, and funding support can enable hydrogen to perform effectively at depot scale.

Policy frameworks and near-term economics

Policy remains a critical enabler of hydrogen market growth in both the EU and the UK. Effective demand-side measures are essential, alongside targeted supply-side support, to successfully seed a viable hydrogen economy. On the supply side, support is primarily delivered through capital subsidies in the EU, while the UK’s HAR are intended to provide revenue support for low-carbon hydrogen production projects. These mechanisms help bridge the cost gap between hydrogen and incumbent fuels across end-use markets. However, such programmes are often complex, highly prescriptive, and slow to implement. As a result, they are not always aligned with the immediate needs of producers or end users and ultimately rely on voluntary decarbonisation decisions. In transport, the UK Renewable Transport Fuel Obligation (RTFO) and the EU’s Renewable Fuels of Non-Biological Origin (RFNBO) provide demand-based measures. Under these schemes, retailers of transport fossil fuels are required to decarbonise a percentage of the volume they sell. Suppliers of renewable fuels can help meet this obligation by supplying qualifying fuels and, in return, receive revenue from the obligated parties for supporting their decarbonisation requirements. For hydrogen used in transport applications, these mechanisms can help enable positive project economics, enabling operators to switch to hydrogen. Strengthening these already functioning RTFO and RFNBO incentives through clear zero-emission bus and HGV mandates, with defined timelines, would give operators, local authorities and hydrogen suppliers the certainty needed to invest and decarbonise with confidence.

Hydrogen supporting transport infrastructure power

Beyond vehicles, hydrogen is also being used to support transport-related infrastructure through low emission power solutions. Construction sites, depots, and transport hubs increasingly face grid constraints, local air quality requirements, and noise restrictions, particularly during infrastructure upgrades or temporary works. Hydrogen-fuelled generators and power systems can provide reliable, rapidly deployable power while reducing local emissions. As decarbonisation targets across construction and infrastructure projects are becoming more prominent, conventional diesel generators are increasingly

GlobalHydrogenReview.com

Summer 2026

What operational projects are teaching the market

Taken together, these deployments point to a consistent theme: hydrogen adoption is driven as much by operational fit as by technology maturity. Successful projects tend to share several characteristics: y Clear alignment between hydrogen supply mode and operational requirements and constraints. y Collaboration across operators, OEMs, infrastructure providers, and hydrogen suppliers. y Policy mechanisms that reward actual deployment, not just future capacity. These lessons are emerging from assets in service, not from roadmaps alone.

less attractive. Demonstrations on live sites have shown that hydrogen-powered generators can be integrated safely and operated under real load conditions, helping build confidence among operators and project partners. In November 2025, Hitachi Energy powered a construction site in Rugeley, Staffordshire, for four weeks using its HyFlex hydrogen powered generator supplied with renewable hydrogen by Air Products. The project is estimated to have avoided around 5 t of CO2 emissions compared with conventional diesel generators. It demonstrates how hydrogen can provide a flexible, low emission power solution for temporary or transitional applications. While hydrogen does not replace the need for long-term grid investment, it can complement existing infrastructure by providing reliable power in locations where grid connectivity is unavailable or not yet implemented. This includes remote or temporary sites where no grid connection exists or is planned, such as isolated construction projects. Hydrogen-powered generators can also provide power to sites awaiting permanent grid connections such as ports, airports or depots during development or upgrade phases, enabling decarbonisation action today.

Conclusion: real progress requires operational focus and collaboration

Hydrogen’s long-term potential remains significant, but its present day role is equally important. Across bus depots, construction sites, and supporting infrastructure, hydrogen systems are already operating safely and reliably in commercial environments. Further progress will depend on continued investment in production and infrastructure, supported by policy certainty and reduced complexity. Yet experience from operational deployments shows that success is not determined by technology readiness alone. It depends on how well hydrogen solutions are chosen and integrated into real world operations. The opportunity, therefore, is twofold: continue building the future hydrogen system, while enabling solutions that can deliver emissions reductions and operational value today. Hydrogen is not only a future ambition; in the right applications, it is already part of the energy system in practice.

Tim Murray, HTEC Engineering Services, analyses the cost of hydrogen truck operations, identifying the use cases where hydrogen offers the best outcome.

he total cost of ownership (TCO) of hydrogen trucks remains one of the most closely scrutinised metrics in the hydrogen mobility landscape. While headline comparisons often position hydrogen fuel cell electric trucks (FCEVs) as more expensive than diesel or battery electric alternatives, these comparisons do not always reflect how freight operations function in practice.

Experience from recent projects with industrial and logistics stakeholders points to a consistent finding: hydrogen truck economics are highly application dependent. In high-utilisation, long-haul operations (typically above 100 000 - 140 000 km/yr) where range, refuelling speed, and payload capacity are important, hydrogen trucks can offer a compelling TCO pathway, even before full cost parity with diesel is achieved. This article breaks down hydrogen truck TCO, highlights the conditions under which it improves, and identifies the use cases where hydrogen delivers the strongest value, beyond fuel price alone.

Understanding TCO in a freight context

TCO is the full cost of owning or leasing and using a truck over its lifetime, including vehicle or lease costs, energy, maintenance, infrastructure, and the impact of utilisation and productivity. For freight operators, this extends well beyond vehicle purchase price and fuel cost. Hydrogen truck economics are shaped by the close relationship between fuel supply, infrastructure, and vehicle performance. Because of this, the TCO is best understood in the context of how and where vehicles are deployed. Approaches that treat hydrogen as a simple retail fuel without considering production pathways, infrastructure design, or utilisation may not fully capture the factors that influence overall cost and value.

Operational drivers of value in hydrogen trucking

While hydrogen and battery electric trucks are both zero-emission solutions, they are generally suited to different operating conditions. The economic case for hydrogen becomes clearer when considering the operational factors that influence TCO. Hydrogen’s high energy density supports long-range operation, typically between 500 and 750 km, allowing fleets to maintain established long-haul patterns without significant changes to routing or scheduling. This contributes to route

consistency and overall operational flexibility, enabling fleets to use the same trucks across long and short-haul routes and optimise utilisation. Performance in colder climates is an important consideration. While all vehicles may require heating to start in extreme conditions (e.g., below -20°C), fuel cell electric trucks (FCETs) tend to retain most of their range, typically experiencing minimal losses (0 - 15%). In contrast, battery electric trucks can see reductions of up to 15 - 40% under similar conditions, an important distinction in Canadian freight corridors, where long distances and cold-weather operations are common. Refuelling time is another key factor, particularly for fleets operating on tight schedules or using high-utilisation models such as slip-seating. Hydrogen trucks can typically refuel in under 20 minutes, helping maintain vehicle uptime and reduce dwell time. By comparison, battery electric trucks may require longer charging times depending on battery size and infrastructure availability, which can affect overall productivity. Payload capacity remains a critical factor in freight economics. Energy storage and propulsion systems inevitably add mass, and in long range applications battery electric powertrains have historically carried a notable weight penalty, which can reduce available payload or influence route planning. However, this gap is narrowing as newer battery electric truck platforms achieve lighter, more integrated designs, particularly for regional and urban duty cycles. Fuel cell electric trucks offer an alternative approach in which overall powertrain weight, rather than the fuel itself, becomes the primary consideration. Hydrogen fuel cell trucks can be close in weight to their diesel equivalents, though still marginally heavier once tanks, fuel cell stacks, and electric drivetrains are accounted for. Taken as a system, the fuel cell powertrain provides extended range with a relatively modest impact on payload, which can be advantageous in weight sensitive, longer haul freight operations. These factors tend to be most relevant in high-utilisation applications. In long-haul operations, higher upfront costs can be offset over greater mileage, while the operational characteristics of hydrogen are more fully utilised. In lower-utilisation or less demanding duty cycles, these advantages may be less pronounced, and other technologies may be more suitable.

Case study: real-world performance in British Columbia, Canada

Figure 1. Hyundai XCIENT (via Loblaw Companies Ltd trial) fuelling at the University of British Columbia Hydrogen Station, operated by HTEC.

GlobalHydrogenReview.com

Summer 2026

Canada is entering an early phase of commercial deployment for hydrogen fuel cell trucks, beginning to move beyond pilot projects toward real-world freight operations. In this context, British Columbia has emerged as one of the leading regions, with early initiatives providing initial insights into how hydrogen performs under practical operating conditions. This represents an important step toward building the data foundation required for broader commercial adoption. For example, as part of a commercial demonstration led by Loblaw Companies Ltd, and bringing together a broad partnership including HTEC, the Alberta Motor Transport Association (AMTA), the BC Trucking Association (BCTA), Deloitte, Transport Canada, the province of British Columbia, and Hyundai Motor Company, a Hyundai XCIENT Class 8 hydrogen fuel cell truck was deployed in day-to-day retail

Global Publication

ENERGY GL BAL

The premier information source for the renewable energy industry, covering solar, wind, bioenergy and storage. subscibe for free www.energyglobal.com/magazine

freight operations without requiring changes to routes, logistics, or the goods being hauled. Over more than 15 000 km of operation, the vehicle transported over 700 t of cargo while pulling typical loads without faults. The truck was deployed on corridors between Metro Vancouver, Whistler, and Merritt, routes that include steep grades, long distances, and demanding driving conditions, including the Coquihalla Highway, widely recognised as one of the most challenging freight corridors in North America. Some round trips exceeded 560 km, demonstrating both range capability and operational reliability. From a TCO perspective, this deployment highlights how operational continuity, high utilisation, and minimal disruption to existing logistics can translate directly into economic value. Maintaining standard duty cycles without additional downtime, route redesign, or payload loss supports higher asset productivity, helping to offset higher upfront vehicle and infrastructure costs. This type of deployment illustrates how hydrogen trucks can integrate into existing freight operations, supporting performance, reliability, and operational continuity in demanding real-world conditions. The use of hydrogen fuel cell trucks is also an important keystone in a fleet decarbonisation strategy. Over the span of 100 000 km, the use of an FCET Class 8 truck mitigates about 125 t of CO2-e, an important consideration in larger fleets targeting paths to net zero in the coming years. This is equivalent to removing 40 light duty vehicles from the road or fully decarbonising 55 homes.

Infrastructure and deployment approach

Infrastructure is often cited as a central challenge for hydrogen trucking, but outcomes depend heavily on how infrastructure is deployed and scaled. Hydrogen systems tend to function most effectively when developed at scale, where sufficient and predictable demand can support high asset utilisation and stronger economics. Rather than requiring fully built-out networks from the outset, scalable deployment models allow infrastructure to grow in step with fleet adoption. Early projects can focus on serving defined corridors or anchored fleets. This approach helps manage early stage risk while maintaining a clear pathway toward higher utilisation and improved performance. As deployments scale, infrastructure can evolve into more integrated, hub-based models that capture efficiencies across the system. In Vancouver, HTEC operates a hydrogen hub that integrates production, distribution, fuelling, and truck leasing within a coordinated framework. This structure enables real world fleet deployment while providing operational insight across the value chain. Through HTEC’s Vehicle Leasing Corp. (VLC), vehicle access is bundled with fuelling and maintenance, reducing upfront capital requirements for fleet operators and aligning costs more closely with actual operations. This model highlights the importance of coordinated regional ecosystems, where supply and demand are developed together rather than in isolation. Concentrating vehicles, fuelling, and services within defined regions creates a foundation for scale and improves the viability of early deployments. Over time, similar hubs can be replicated

GlobalHydrogenReview.com

Summer 2026

in additional regions and progressively linked, supporting network expansion. As utilisation increases, infrastructure economics improve through higher asset productivity, lower per unit costs, and more efficient operations. In this context, scale is not just an outcome of hydrogen trucking deployment, but a prerequisite for its long-term performance and competitiveness.

Hydrogen, BEV, and alternative pathways: choosing the right solution

The choice between hydrogen, battery electric, and other emerging powertrain options is less about technology preference and more about operational fit. Battery electric trucks are well suited to short-haul, depot-based operations with predictable routes and sufficient dwell time for charging. Hydrogen fuel cell trucks are better aligned with long-haul, high-utilisation, payload-sensitive, and time-critical applications where uptime and operational continuity are essential. Other pathways, such as dual-fuel systems and hydrogen internal combustion engines, offer transitional or emerging options with varying cost and performance profiles. In practice, the most effective decarbonisation strategy is portfolio-based, matching each technology to the duty cycle where it performs best.

The role of policy and market design

Policy frameworks influence the development of hydrogen trucking by shaping both costs and incentives. Mechanisms that support zero-emission operation, low-carbon fuels, and infrastructure investment can improve project economics and reduce risk. For example, British Columbia’s Low Carbon Fuel Standard has been essential in developing the province’s hydrogen ecosystem by providing upfront capital for project development through initiative agreements and lowering ongoing operating costs through credit generation tied to dispensed hydrogen. At the same time, policy structures can introduce variability, which needs to be considered in long-term planning. The elimination of the Carbon Tax had a significant and immediate effect in lowering diesel prices, thereby reducing the cost competitiveness of hydrogen and other low-carbon fuels in the transportation market. As a result, hydrogen TCO is shaped not only by technical performance, but also by regulatory and market conditions.

Conclusion

Hydrogen trucks are often evaluated against the benchmark of cost parity with diesel. While this remains an important consideration, it does not fully capture how value is created in freight operations. In applications where range, refuelling speed, payload capacity, and utilisation are key (and where infrastructure is deployed in a coordinated way), hydrogen trucks can offer a competitive and practical solution. The question is no longer whether hydrogen trucks can work. It is whether freight systems are being designed in a way that allows their operational advantages to translate into economic value.

Dr Jason Morgan, AvCarb, USA, outlines the steps for how a properly designed gas diffusion layer can remove bottlenecks and help keep up with a changing industry.

olymer electrolyte membrane fuel cells (PEMFCs) have emerged as a cornerstone technology in the global transition towards decarbonisation, offering high power density and efficiency for a variety of clean energy applications. As the PEMFC industry accelerates its transition from stationary and material handling applications to high-power, heavy-duty transport, and distributed power systems, the engineering focus has shifted towards a well-documented challenge. Consequential system failures frequently associated with the catalyst layer are now starting to appear in the porous transport layers and interfacial regions that surround it. At the centre of this challenge is the Gas Diffusion Layer (GDL), a component once treated as a commodity, is now recognised as a critical determinant of stack performance and lifetime. As OEMs push the boundaries of technology via thinner membrane electrode assemblies (MEAs), higher current densities, and extended target lifetimes, the limitations of conventional GDL designs have become well-documented performance bottlenecks, specifically in compressibility, electrical resistance, mechanical durability, and surface topology. This realisation has driven a shift toward

greater material engineering rigour, culminating in the development of the FLEX-GDLTM. By examining the specific mechanical and electrical failure modes of conventional GDLs in modern fuel cells, this article will outline the engineering approach to overcoming these failures, ultimately illustrating why this release represents the next evolution in fuel cell material science.

The failure cascade: why the GDL matters

Within a fuel cell the GDL must simultaneously manage reactant gas transport, water removal, electrical conduction, mechanical compliance, and heat dissipation. The failure of any single function creates a cascade effect that reduces the stack performance. For instance, a piece of GDL with high compressibility will easily conform around the plate during the stack build to help create the seal necessary for the fuel cell to work. However, if the GDL thickness is not uniform, both down-web and cross-web, then when compressed to a hard stop the pressure applied to individual GDL pieces may be different. This difference will impact the porosity of the GDL and thus the diffusion rate, perhaps creating additional mass transport loss or ‘low cells’

(individual cells in a stack that underperform due to localised transport restrictions). Even worse, if the GDL compressibility is inelastic then, as the membrane in the MEA swells and contracts against these thicker pieces during operation, the GDL thickness can creep lower, eventually becoming too thin to maintain the seal. This will cause a leak that compromises the entire stack for the thickness variation of a single piece of GDL. While the impact of GDL variations can be localised initially, these failures propagate stress to adjacent areas, reducing efficiency and ultimately compromising the performance of the entire stack. To mitigate these types of risks, the FLEX-GDL was engineered to address four critical failure points inherent in traditional designs.

Figure 1. Through-plane thickness as a function of compressive stress on FLEX-GDLTM. The material exhibits a dual-phase compression response with easy compression below 1 MPa for easy sealing and less compression at higher forces to prevent channel intrusion.

Step one: resolving the compressibility paradox

Conventional GDLs were designed with high compressibility to accommodate manufacturing tolerances in bipolar plates and other cell components. While this aided sealing, it introduced ‘silent efficiency killers’ such as channel intrusion (increasing pressure drop), permanent compression set (creep), and inconsistent contact pressure (increased resistance). Attempts to stiffen the material by increasing fibre density work, but often resulted in higher costs, reduced permeability, and increased risk of membrane damage. These solutions also limit the reduction in GDL thickness, preventing improvement in power density by reduction of cell pitch.

The engineering response

Figure 2. Mechanical strength comparison between MB-39 and FLEX-GDL.

Table 1. Physical property comparison between AvCarb MB-39

and AvCarb FLEX-GDL

Nominal properties

AvCarb MB-39

AvCarb FLEX-GDL

Thickness (μm)

195

150 ↓ 25%

Basis weight (g/m2)

50 ↓ 10%

Resistivity (mΩ·cm2)

5 ↓ 30%

Water vapour diffusivity (D/D0)

> 0.3

> 0.25

MPL surface roughness Ra (μm)

3 ↓ 60%

Metallic impurities (ppm)

< 20

10 ↓ 50%

80% reduction in PTFE content vs MB-39

2x improvement in GDL break strength vs MB-39

GlobalHydrogenReview.com

Summer 2026

Technologies like FLEX-GDL reimagine the binder distribution strategy. Rather than relying on dense inter-fibre webbing, the binder reinforces individual carbon fibre junctions, thereby preserving open pore pathways while building load-bearing capacity. The result is a non-linear compression profile as seen in Figure 1. The material compresses readily below 1 MPa to facilitate sealing, but exhibits near-elastic behaviour above 1 MPa, with less than 15 μm of thickness change between 1 and 2 MPa and a permanent compression set of only 10 μm after cycling to 3 MPa. This dual-phase behaviour prevents channel intrusion and creep, ensuring consistent interfacial contact throughout the stack’s operational life.

Step two: minimising Ohmic losses via advanced hydrophobicity Hydrophobic agents, typically polyterafluoroethylene (PTFE), are essential for water management and flood prevention. However, these agents act as electrical insulators. In standard GDLs, achieving the necessary hydrophobicity (contact angle �140°) often requires PTFE loadings that significantly increase Ohmic resistance, forcing operators to choose between water management efficiency and electrical conductivity.

The engineering response The new GDL design utilises a conformal coating process in which PTFE is deposited directly onto individual fibre surfaces rather than pooling at fibre junctions or

WHERE GLOBAL ENERGY SUPPLY MEETS DEMAND The world’s largest conference and exhibition for natural gas & LNG, electrification, low carbon solutions, hydrogen, and AI for energy. HOSTED BY

Join the Gastech Strategic Conference to hear from the leaders setting the critical agenda for secure, resilient and affordable energy.

CO-HOSTS

BOOK YOUR DELEGATE PASS

NATIONAL CONSORTIUM HOSTS

gastechevent.com @gastechevent #Gastech

Be part of the conversation shaping the future of energy.

brought to you by

the material sustains contact over 270° of arc around a 2 in. roller without web fracture, a geometry that would catastrophically fail most conventional carbon papers. Critically, the binder architecture that provides this flexibility also helps prevent fibre debonding under compression, eliminating the debris generation mechanism that puts ultra-thin membranes at risk during stack assembly.

Figure 3. Confocal laser microscope images of the FLEX-GDL MPL surface at nominal pressure (left) and at 2 MPa compressive load (right). Surface morphology is visually unchanged and measured average surface roughness (Ra) are identical at 2.4 and 2.35 μm respectively.

Step four: protecting the interface with a resilient MPL

With the advent of ultra-thin membranes (≤ 10 μm), the surface topology of the microporous layer (MPL) is critical. Traditional MPL designs lack inherent structural strength; under compression, they deform, allowing substrate fibres to penetrate the surface and increase roughness. This creates a hostile environment for delicate ultra-thin membranes.

The engineering response FLEX-GDL incorporates a high-modulus binder in the MPL formulation that maintains structural integrity under compressive load. Unlike conventional carbon black MPLs that utilise PTFE as an additional binder, this system resists lateral deformation, preventing substrate fibre protrusion through the MPL surface. Surface profilometry Figure 4. Three-dimensional CT reconstruction showing the layered data confirms the practical effect with average surface architecture of FLEX-GDL. The smooth, continuous MPL surface roughness (Ra) measured under compression utilising a (upper face) contrasts with the open fibrous substrate below, soft lithography method and finding an average of 2.4 μm illustrating the structural separation between the two functional layers. at nominal conditions (no compression) and 2.35 μm when compressed at 2 MPa. When compared to an average bridging pore throats. This approach achieves equivalent of 5 μm roughness found for the prior-generation baseline hydrophobicity (contact angle ≥ 140°) with an 80% reduction (MB-39), it is over a 50% improvement in surface smoothness in total PTFE content compared to conventional GDLs. The maintained under cell assembly loads (Figures 3 and 4). practical consequence is measurable: through-plane electrical This stable, smooth interface is a prerequisite for reliable resistivity is reduced from 7 mΩ·cm2 to 5 mΩ·cm2 at 1 MPa deployment of ultra-thin membranes below 10 μm, where (a 30% reduction vs the prior-generation baseline) while even modest fibre protrusion constitutes a shorting risk. water management performance is preserved. The result is a simultaneous improvement in electrical efficiency and material sustainability, without the traditional trade-off between hydrophobicity and conductivity. The transition from simple ‘black paper’ substrates to an engineered, high-performance graphitic substrate marks a new era in fuel cell technology. The release of a new generation of GDL technologies like the FLEX-GDL represents the next step in As GDLs have become thinner (≤ 200 μm) to meet increased GDL evolution, moving beyond simple substrate functionality power density targets, mechanical fragility has emerged as to become an active, tailored solution for the rigorous a significant manufacturing challenge. Thin carbon papers demands of heavy-duty transport. are susceptible to web tears and may crack under winding By systematically addressing the interrelated challenges of tension during MEA manufacturing. They can also shed compression set, electrical resistance, mechanical fragility, debris (e.g., broken fibres or loosened carbon particles, etc.) and surface topology, as described in Table 1, a new material particularly when compressed at or above 3 MPa in the with improved performance has been introduced. The highly system. This particulate contamination is a known risk factor graphitic substrate chemistry also enables compatibility for membrane pinhole formation and cell shorting. with both acidic and alkaline electrochemical environments, extending applicability beyond PEMFC into electrolyser and The advantage CO2 reduction platforms, an increasingly relevant requirement At a nominal thickness of 150 μm, the new GDL design as the hydrogen economy matures. As the industry moves achieves a machine direction (MD) break strength of toward higher power densities and longer target lifecycles, over 3000 N/m shown in Figure 2 (roughly double that of materials like FLEX-GDL illustrate how systematic GDL standard commercial papers like MB-39) and can be wound engineering can remove bottlenecks that have historically onto 3 in. cores for roll-to-roll processing. In bending trials, constrained the entire stack.

Conclusion: the next step in GDL evolution

Step three: enhancing mechanical robustness for manufacturability

GlobalHydrogenReview.com

Summer 2026

Edward Cubero, Amogy, USA, outlines how ammonia’s role as a hydrogen carrier can create opportunities for wide scale hydrogen adoption.

riven by both global decarbonisation goals and an increasing desire among energy-importing nations to diversify their fuel sources to improve their energy security, the hydrogen economy is quickly transitioning from conceptual planning to commercial deployment. But a critical challenge remains: how to store, transport, and deploy hydrogen efficiently at scale. Ammonia is emerging as the most practical carrier for hydrogen, positioning it at the core of the future hydrogen ecosystem. While long-term, high-volume demand is expected from sectors like maritime and heavy-duty transportation, power generation is driving near term growth. The power generation market is driven by both rising industrial electricity consumption from AI data centre buildouts and the need for zero-carbon, firm power, to ensure the reliability of decarbonised power generation. This will create a bridge to accelerate infrastructure development and ultimately support large scale adoption of hydrogen. One key component accelerating this shift is the increasing demand for distributed power generation. As industrial plants grow larger, their site power consumption increases, complicating grid connections and lengthening

the interconnection timeline. In some areas of the US, the process from concept to construction can take five or more years. Distributed power enables these plants to come online faster, which is particularly important for AI data centres and the industries supplying them with semiconductors and servers. In addition, certain countries, such as South Korea, are specifically incentivising distributed power to reduce strain on long-distance electricity transmission. Finally, distributed power gives the owner the ability to choose the power mix, as systems can include a mix of clean energy and fossil fuels, enabling organisations to balance operational demands with increasingly important environmental, social, and governance (ESG) goals, while also giving them control over the reliability of their power supply. Intermittent renewables, like solar and wind, while offering low-levelised electricity costs, require large land areas and cannot meet the 24/7 power requirements of industrial users such as AI data centres, semiconductor plants, large manufacturing plants, and petrochemical plants. With these barriers, hydrogen offers a compelling solution as a behind-the-meter, zero-carbon baseload power source. But it also presents significant logistical challenges.

Hydrogen production is not equally feasible worldwide. Most high-power-consuming regions and data hubs are located far from strong solar and wind resources. As hydrogen is expensive to compress and liquefy, its storage and transportation at scale remain complicated and insufficient. Enter ammonia: as a hydrogen carrier, ammonia provides a practical and scalable pathway for the hydrogen economy. It enables decarbonisation in sectors where batteries and direct hydrogen solutions fall short, while leveraging existing global transportation and storage infrastructure. Its higher volumetric energy density than hydrogen makes it more suitable for delivering clean, reliable energy to meet the grid’s complex, changing demands. And it is more than just an idea: it is already moving from research and development to commercial deployment.

Ammonia at scale: a present reality

As the second-most-produced chemical in the world, ammonia is already an established commodity. Approximately 200 million tpy of ammonia are produced, with 20 million tpy transported by sea, supported by roughly 8 million t of port storage capacity worldwide. Additionally, millions of tonnes are transported by barge and freight rail, with last-mile deliveries from terminals to small end users via tanker trucks. Ammonia also provides a significant energy advantage, with a volumetric energy density about 50% higher than that of liquid hydrogen, making it easier and more cost-effective to store and transport over long distances. These transportation options make it feasible for ammonia to be produced economically in regions with abundant renewable resources, such as China, India, and the Middle East, and shipped to high-demand, high-production cost markets, including Japan, South Korea, Singapore, Taiwan, and Europe. This global supply chain approach aligns well with the needs of distributed power users, who are often located far from low-cost production areas and require reliable energy solutions. The benefits of ammonia as an energy carrier and clean fuel are demonstrated by the growth of clean ammonia production globally. Today, over 200 million tpy of clean ammonia projects have been announced, and nearly 90% of all hydrogen

export projects will come in the form of ammonia. By 2030, 20 - 40 million tpy of clean ammonia production is expected to be operational, more than doubling the current export market, with the majority focused on export demand for new uses of ammonia as a fuel. In addition, 4 million t of new port storage capacity and 60+ newly built Very Large Ammonia Carriers (VLACs) for bulk ocean transport will come online by 2030, enabling increased ammonia trade. Ammonia also has a well-established history of safe handling. For more than a century, it is been widely used in fertilizer, chemical, and manufacturing applications, and its mature infrastructure and operational standards support its growth in commercial use and viability. As demand for new uses of it as an energy carrier and energy source grows, regulations are being updated to ensure the energy transition is safe. For example, the Port of Rotterdam, Europe’s largest port, is planning to expand its ammonia storage capacity from one terminal to six to support ammonia imports. To facilitate this growth, the Netherlands has developed new LNG-based rules for ammonia storage to enable the safe storage of larger volumes. These safety standards include full containment (inner steel tank + secondary containment + outer concrete walls), the movement of piping connections to the top of the tanks, and continuous monitoring (pressure, temperature, leaks), which provides a terminal-level safety scope rather than a tank-level scope.

Near-term drivers: AI as the catalyst

The AI boom is driving a rapidly increasing demand for power worldwide. AI data centres are becoming essential, but these power-hungry facilities often require exponentially more power than traditional data centres. While traditional data centres might require tens of megawatts, an AI data centre can require hundreds. These facilities operate around the clock – 24/7 – and require extremely high reliability. Given their operating profiles, thermal generation remains the only practical way to meet the power needs of data centres with behind-the-meter installations. However, hyperscalers and co-location providers are no strangers to the global net-zero initiatives and are actively working toward decarbonisation. This makes commitments to traditional thermal generation options much less attractive. Ammonia offers a strong solution for these providers because it is a widely available, zero-carbon, and energy-dense alternative to natural gas distributed power generation. Consequently, data centre developers are increasingly selecting new locations based on power availability. Favouring sites near ammonia storage or import infrastructure could help ensure reliable, cost-effective clean energy: an important strategic priority as developers plan for rapid data centre expansion.

How stationary power leads to mobility Figure 1. Amogy’s site in Houston, Texas, US – a facility dedicated to advancing and validating next generation ammonia cracking technology.

GlobalHydrogenReview.com

Summer 2026

Early demand for ammonia solutions will come from East Asia and Europe due to structural barriers, including limited solar and wind resources, the scarcity of land for large scale solar and wind projects, and dependence on imported energy, such as LNG.

Hydrocarbon Engineering

The leading magazine for the global downstream oil and gas sector Free trial subscription

www.hydrocarbonengineering.com

Many of these regions already have ambitious decarbonisation goals and national hydrogen strategies in place. Japan, for example, is targeting approximately 3 million tpy of hydrogen use by 2030, increasing to 12 million tpy by 2040 and nearly 20 million tpy by 2050. The EU, on the other hand, aims to supply 20 million tpy of hydrogen by 2030, with 10 million t domestically produced and 10 million t imported. This environment is ripe for ports with ammonia storage capacity to evolve into clean-energy import hubs. Data centres and other large industrial users can co-locate new buildings near ports or build power plants at ports with long-term power purchase agreements for clean power.

Unlocking ammonia’s maritime promise and beyond

The maritime industry is a major contributor to global emissions and has aggressive decarbonisation goals, with the International Maritime Organization (IMO) aiming to reach net zero greenhouse gas (GHG) emissions by 2050. Hydrogen and ammonia will be critical in achieving these goals, and while the industry has had some traction as an early adopter of ammonia, a major bottleneck remains: the limited availability of ammonia as a fuel, not cargo, at ports. Developing ammonia for stationary power directly addresses this constraint, driving import volumes and storage infrastructure. The pathway for adopting ammonia in maritime applications and beyond will happen in four steps: y Step one: ammonia-fuelled distributed power generation creates new demand for green ammonia production and transportation, reducing costs via economies of scale.

y Step two: efforts to decarbonise the clean ammonia supply chain will focus on using ammonia to power gas carriers and new terminals. y Step three: port equipment will be decarbonised using hydrogen cracked from imported ammonia (trucks, cranes, etc.). y Step four: with ample ammonia storage and now ample production, ammonia bunkering hubs at ports will be created, enabling vessels to switch to ammonia fuel. Maritime will serve as an example for other industries by providing regulatory clarity and real-world validation for using ammonia as a reliable, clean power source. It not only proves its commercial viability but also demonstrates its durability as a fuel source across heavy-duty sectors with significant carbon emissions, such as mining, trucking, and even locomotives. Stationary power is an important first market for using ammonia as a fuel and will play a crucial role in unlocking widespread adoption. By promoting infrastructure development and investment, establishing commercial viability, and shaping regulatory frameworks, distributed power applications will pave the way for a more robust global supply chain, making ammonia a more viable fuel for global shipping and other industries. Over time, this foundation will enable the transition of ammonia into other heavy-duty sectors, unlocking its full potential as a global clean energy solution.

Page Number Advertiser 27 ABB

15 KBC (A Yokogawa Company)

31 Black & Veatch

02 Mokveld Valves BV

OFC & 11 CASALE 35 Ebara Elliott Energy

OBC

Nextchem (MAIRE Sustainable Technology Solutions)

08, 47, 55, 63, IBC Palladian Publications

59 Gastech

07 T.D. Williamson

39 Greene Tweed

51 Hydrogen Technology World Expo

IFC Topsoe

Tecnimont (MAIRE Integrated E&C Solutions)

A podcast series for professionals in the downstream refining, petrochemical, and gas processing industries

LISTEN NOW

Has the turning point for CCS arrived?

Pedram Fainaloo, Director of the Low Carbon & CCS Segment – North America, Energy Systems at DNV, considers if the turning point for carbon capture and storage (CCS) has arrived and outlines some of the most viable CCS opportunities in downstream operations.

How to specify optimal coatings to combat an array of corrosion challenges

John Zimmerman, Key Account Manager for Sherwin‑Williams Protective & Marine, covers an array of common corrosion challenges energy producers face and how to specify the ideal coatings to mitigate those threats.

Why certification matters more than ever

A conversation about the growing importance of certification and competence in the downstream oil and gas industry. Featuring Andri Orphanides, Director of American Petroleum Institute’s (API) Individual Certification Programs (ICP).

Drones in tank storage: opportunity or threat?

Jay Cruz, Vice President of Government Affairs at the International Liquid Terminals Association (ILTA), explains how drone technology is offering new ways to improve safety, efficiency, and data insight in terminal operations.

Global Hydrogen Review - Summer 2026