The hydrogen challenge: addressing storage, safety, and environmental concerns in hydrogen economy Ifeanyi Michael Smarte Anekwe a,* , Sherif Ishola Mustapha a,d, Stephen Okiemute Akpasi b, Emmanuel Kweinor Tetteh b, Atuman Samaila Joel a,c, Yusuf Makarfi Isa a a School of Chemical and Metallurgical Engineering, University of the Witwatersrand, Johannesburg, 2050, South Africa b Green Engineering Research Group, Department of Chemical Engineering, Faculty of Engineering & the Built Environment, Durban University of Technology, Durban, 4000, South Africa c Department of Chemical Engineering, Faculty of Engineering, Abubakar Tafawa Balewa University Bauchi, Nigeria d Department of Chemical Engineering, University of Ilorin, P.M.B. 1515, Ilorin, Nigeria A R T I C L E I N F O Handling Editor: Dr Mehran Rezaei Keywords: Electrolysis Environmental assessment Hydrogen Life cycle assessment (LCA) Policy framework Public perception Storage Safety Steam methane reforming (SMR) A B S T R A C T As part of global decarbonization efforts, hydrogen has emerged as a key energy carrier that can achieve deep emission reductions in various sectors. This review critically assesses the role of hydrogen in the low-carbon energy transition and highlights the interlinked challenges within the Techno-Enviro-Socio-Political (TESP) framework. It examines key aspects of deployment, including production, storage, safety, environmental impacts and socio-political factors, to present an integrated view of the opportunities and barriers to large-scale adoption. Despite growing global interest, over 90 % of the current global hydrogen production originated from fossil- based processes, resulting in around 920 Mt of CO2 emissions, two-thirds of which were attributable to fossil fuels. The Life Cycle Assessment (LCA) shows that coal-based electrolysis resulted in the highest GHG emission (144 - 1033 g CO2-eq/MJ) and an energy consumption (1.55–10.33 MJ/MJ H2). Without a switch to low-carbon electricity, electrolysis, cannot deliver significant climate benefits. Conversely, methanol steam reforming based on renewable feedstock offered the lowest GHG intensity (23.17 g CO2-eq/MJ) and energy demand (0.23 MJ/ MJ), while biogas reforming proved to be a practical short-term option with moderate emissions (51.5 g CO2-eq/ MJ) and favourable energy figures. Catalytic ammonia cracking, which is suitable for long-distance transport, represents a compromise between low energy consumption (2.93 MJ/MJ) and high water intensity (8.34 L/km). The thermophysical properties of hydrogen, including its low molecular weight, high diffusivity and easy flammability, lead to significant safety risks during storage and distribution, which are exacerbated by its sensitivity to ignition and jet pulse effects. The findings show that a viable hydrogen economy requires integrated strategies that combine decarbonised production, scalable storage, harmonised safety protocols and cross-sector stakeholder engagement for better public acceptance. This review sets out a multi-dimensional approach to guide technological innovation, policy adaptation and infrastructure readiness to support a scalable and environ- mentally sustainable hydrogen economy. 1. Introduction Driven by the increasing urgency of the climate crisis, a growing number of countries have set net-zero emissions targets, reflecting a global shift towards climate action. In April 2022, 131 countries, ac- counting for 88 % of global greenhouse gas emissions, had announced commitments to achieve net zero emissions. Human-induced emissions have already led to a global temperature increase of 1.1 ◦C above pre- industrial levels and there is a broad consensus that achieving net zero emissions by 2050 is essential to limit warming to 1.5 ◦C [1]. To achieve this goal, emissions must be reduced in all sectors. While strategies such as energy efficiency, electrification and renewables can deliver around 70 % of the required reductions, hydrogen will play a crucial role in decarbonising sectors where alternatives are currently limited or economically unviable, e.g. heavy industry, long-distance transport and seasonal storage. In this context, hydrogen is expected to contribute around 10 % of the emission reductions required under the International Renewable Energy Agency’s (IRENA) 1.5 ◦C scenario and 12 % of total final energy demand [1,2]. * Corresponding author. E-mail address: anekwesmarte@gmail.com (I.M.S. Anekwe). Contents lists available at ScienceDirect International Journal of Hydrogen Energy journal homepage: www.elsevier.com/locate/he https://doi.org/10.1016/j.ijhydene.2025.150952 Received 6 June 2025; Received in revised form 22 July 2025; Accepted 11 August 2025 International Journal of Hydrogen Energy 167 (2025) 150952 Available online 20 August 2025 0360-3199/© 2025 The Authors. Published by Elsevier Ltd on behalf of Hydrogen Energy Publications LLC. This is an open access article under the CC BY license ( http://creativecommons.org/licenses/by/4.0/ ). https://orcid.org/0000-0001-8582-5869 https://orcid.org/0000-0001-8582-5869 mailto:anekwesmarte@gmail.com www.sciencedirect.com/science/journal/03603199 https://www.elsevier.com/locate/he https://doi.org/10.1016/j.ijhydene.2025.150952 https://doi.org/10.1016/j.ijhydene.2025.150952 http://crossmark.crossref.org/dialog/?doi=10.1016/j.ijhydene.2025.150952&domain=pdf http://creativecommons.org/licenses/by/4.0/ In response to rising global temperatures, increasing energy demand and growing concerns over fossil fuel depletion, the search for sustain- able alternatives has become increasingly urgent. Hydrogen (H2) has gained attention as a viable energy carrier due to its high specific energy, elevated combustion temperature, and substantial storage capacity, of- fering a clean, emission-free option [3,4]. It is being integrated into national and international energy strategies and adopted across sectors such as manufacturing and transportation [5]. Despite its potential, the environmental sustainability of hydrogen remains contested. Never- theless, as a carbon-free molecule with the highest energy content per unit mass, hydrogen is positioned to play a pivotal role in future low-carbon energy systems and the realisation of a hydrogen economy [6]. Its high energy density and clean combustion enhance its appeal for applications in transportation, power generation, and industrial pro- cesses. Moreover, its lightweight nature and availability in both gaseous and liquid forms make it especially advantageous for weight-sensitive transport modes. The renewed interest in hydrogen reflects its stra- tegic importance in decarbonization and the advancement of technolo- gies aimed at unlocking its full potential. Furthermore, hydrogen fuel cells generate electricity with high ef- ficiency, emitting only water vapor as a byproduct, making them a sustainable energy solution [7–9]. Given its versatility and unique characteristics, hydrogen is poised to become a cornerstone of future global energy landscape. However, due to its broad flammability range and high explosive potential (4–74 % in air), hydrogen poses substantial safety hazards during production, storage, transportation, and use. Even a minimal energy input is sufficient to ignite hydrogen, which increases the risk of accidental combustion or explosions [10]. These challenges are further amplified under cryogenic conditions, as hydrogen must be stored at extremely low temperatures (− 253 ◦C) to remain in liquid form, complicating containment and handling procedures [11,12]. Although hydrogen oxidation yields only water, making it an environmentally clean fuel, the element’s low volumetric energy density even in its liquid state limits its storage efficiency relative to conven- tional hydrocarbon-based transportation fuels [7–9,13]. Despite its high gravimetric energy density, the energy content per unit volume remains a key barrier to large-scale deployment. These physical and chemical limitations must be addressed through technological innovations to ensure hydrogen’s safe integration into a sustainable and resilient en- ergy system. Assessing the long-term sustainability of hydrogen production and utilization requires systematically evaluating various production path- ways and their environmental implications. Hence, the holistic assess- ment must consider hydrogen’s entire life cycle, including production, storage, distribution, and end-use. Life cycle assessment (LCA), as pro- posed by Osman et al. [14] and Weidner et al. [15], provides a sys- tematic approach to evaluating hydrogen’s environmental footprint. This methodology enables a deeper understanding of different hydrogen production pathways, associated life cycle inventories, and potential environmental consequences. Beyond production, LCA also examines storage and distribution methods, assessing infrastructure requirements, energy inputs, and environmental trade-offs. Furthermore, evaluating the environmental impact of hydrogen across various applications, including power generation and transportation, is essential for deter- mining its role in a sustainable energy future. Transitioning to a hydrogen economy has the potential to signifi- cantly reduce CO2 emissions and support global energy sustainability goals [16]. Conducting environmental assessment enables researchers and relevant stakeholders to link a system’s elementary flows to its environmental burdens, facilitating a more accurate evaluation of sus- tainability [17,18]. Numerous studies have explored various hydrogen production methods, including conventional steam methane reforming (SMR) [19], renewable alternatives [20], and emerging production routes [21]. Research has also extensively analysed hydrogen storage List of acronyms AG2S Acid Gas to Syngas process ALK Alkaline Electrolysis ATR Autothermal Reforming BEV Battery Electric Vehicle CCS Carbon Capture and Storage CGH2 Compressed Gaseous Hydrogen COG Coke Oven Gas COP26 26th UN Climate Change Conference of the Parties DBDE Dichlorobenzene Equivalent (used in toxicity metrics) ESG Environmental, Social, and Governance EU27 European Union (27 member states) FCEV Fuel Cell Electric Vehicle FCV Fuel Cell Vehicle GEP Green Energy Park GH2 Green Hydrogen GHG Greenhouse Gas GREET Greenhouse gases, Regulated Emissions, and Energy use in Technologies H2 Hydrogen H2-DRI Hydrogen-based Direct Reduced Iron HFC Hydrogen Fuel Cell HFCEV Hydrogen Fuel Cell Electric Vehicle HFCHEV Hydrogen Fuel Cell Hybrid Electric Vehicle HRS Hydrogen Refuelling Station ICEV(s) Internal Combustion Engine Vehicle(s) IEC International Electrotechnical Commission IEA International Energy Agency IPCC AR6 Intergovernmental Panel on Climate Change Sixth Assessment Report IPP Independent Power Producer IRENA International Renewable Energy Agency ISO International Organization for Standardization LAC Latin America and Caribbean LCA Life Cycle Assessment LCC Life Cycle Cost Assessment LH2 Liquid Hydrogen LOHC Liquid Organic Hydrogen Carrier MJ Megajoule MOF Metal–Organic Framework Mt Million Tonnes MTPA Million Tonnes Per Annum NA Not Available NH3 Ammonia NZE Net Zero Emissions PEM Proton Exchange Membrane PEMFC Proton Exchange Membrane Fuel Cell PV Photovoltaic SCZONE Suez Canal Economic Zone SDG Sustainable Development Goals SPIC State Power Investment Corporation SMR Steam Methane Reforming SOEC Solid Oxide Electrolysis Cell SSHS Solid-State Hydrogen Storage SWOT Strengths, Weaknesses, Opportunities, and Threats TTW Tank-to-Wheel UGS Underground Gas Storage WTW Well-to-Wheel I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 2 and transportation challenges [22]. Key topics in the hydrogen research landscape include technological barriers, recent advancements, safety considerations, and the reliability of hydrogen technologies, with stor- age being a particularly critical area of focus. While technical efficiency and economic feasibility assessments are well established, environ- mental sustainability evaluations require further refinement. However, it is worth noting that hydrogen production pathways evaluated in these studies often focus primarily on environmental impacts, with safety considerations rarely included in the analysis. This review provides a timely and multidimensional reassessment of the global hydrogen energy system by examining not only the techno- logical and environmental challenges, but also the interplay of pro- duction pathways, storage modalities, safety risks and sustainability metrics. In contrast to previous studies that focus narrowly on individual components such as hydrogen production technologies or life cycle emissions [15,23–32], this work adopts a system-oriented synthesis that situates hydrogen deployment within a broader Techno-Enviro-Socio-Political (TESP) framework. The TESP framework is a comprehensive, interdisciplinary approach to assessing complex energy systems that incorporates technological, environmental, social and political dimensions. This framework is particularly well suited for analysing sustainable energy transitions, where decision-making must go beyond technical performance and cost considerations and consider public acceptance, regulatory alignment, geopolitical dynamics and environmental impacts. By applying the TESP perspective, this study captures the interdependencies and trade-offs associated with large-scale hydrogen deployment, providing a more holistic basis for strategic planning and policy design. Through its integrative approach, the review provides a basis for assessing the overall sustainability and long-term viability of hydrogen. It advances the discourse by proposing multi-level strategies that balance technological innovation with policy structures and stakeholder engagement, providing a holistic roadmap for a climate and socially responsible hydrogen deployment. Given the increase in global hydrogen production from 85 Mt in 2016 to 97 Mt in 2023 [33][34], predominantly from fossil sources, the study underlines the urgency of transitioning to harmonised, sustainability-focused en- ergy systems. 1.1. Hydrogen colour spectrum: production pathways and environmental implications Hydrogen is classified into various “colours” based on its production method and environmental impact (Fig. 1). Grey hydrogen is the most common and carbon-intensive form, produced via steam methane reforming (SMR) or coal gasification, where methane or coal is con- verted into hydrogen without capturing the carbon dioxide (CO2) emissions. Blue hydrogen is produced using the same SMR or gasification methods but incorporates carbon capture and storage (CCS) technologies to trap 85–95 % of the CO2, making it less harmful to the environment. Turquoise hydrogen, an emerging decarbonization option, is produced through methane pyrolysis, which thermally splits methane into hydrogen and solid carbon rather than CO2, offering a potentially lower-emission route if powered by clean energy. Green hydrogen is the most sustainable option, generated via electrolysis of water using renewable electricity such as solar or wind, resulting in zero greenhouse gas emissions [35–38]. While grey and blue hydrogen depend on fossil fuels like methane or coal, turquoise hydrogen provides a cleaner alternative with manageable solid carbon byproducts. Green hydrogen, however, is central to future decarbonization strategies due to its alignment with renewable energy (RE) use and climate goals. Like electricity, hydrogen is an energy carrier rather than a direct energy source. Its ability to be stored, transported, and utilized effi- ciently makes it an essential component in renewable energy storage, minimizing waste during periods of low energy demand. However, the conventional colour-based (grey, blue, turquoise, and green) classifica- tion of hydrogen production oversimplifies its environmental impact [39]. Most of the global hydrogen is derived from fossil fuels, with 76 % obtained via steam methane reforming (SMR) of natural gas and 22 % through coal gasification. Only about 2 % is produced through water electrolysis [40], highlighting a major sustainability challenge. Fossil fuel-based hydrogen production contributes significantly to greenhouse gas emissions, particularly CO2, and has other detrimental environ- mental effects, making grey hydrogen the least sustainable option. Among the various hydrogen production methods, green hydrogen-generated through water electrolysis powered by renewable energy and blue hydrogen produced via steam methane reforming (SMR) with carbon capture are gaining momentum in the transition toward sustainable and energy-efficient hydrogen production. Green hydrogen, in particular, is at the forefront of large-scale renewable en- ergy projects [41,42], while blue hydrogen serves as an interim solution bridging the gap between fossil fuel dependency and a hydrogen-based economy. While green hydrogen is generally considered the cleanest option, its carbon footprint can vary, particularly when biomass feedstocks or thermochemical conversion processes are involved. Additionally, despite public concerns regarding its safety, blue hydrogen undergoes carbon capture and storage (CCS), significantly reducing its emissions. It is also important to recognise that renewable energy technologies, such as photovoltaic (PV) panels essential for green hydrogen production, have environmental drawbacks. Manufacturing PV panels involves resource extraction, energy-intensive production, and hazardous waste generation, contributing to their overall carbon footprint. Moreover, solar panels have an operational lifespan of approximately 30 years, after which they require specialised waste management and disposal Fig. 1. Various hydrogen production methods and their environmental impacts. Adapted from Ref. [37]. I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 3 [14]. Although green and the emerging turquoise hydrogen is expected to dominate future sustainable energy systems, blue hydrogen remains a crucial transitional energy source facilitating a smoother shift toward sustainability [42]. Achieving a sustainable hydrogen economy requires a comprehensive evaluation of hydrogen’s environmental impact and long-term viability. 2. Overview of global hydrogen market Hydrogen production is transforming significantly as nations strive for cleaner energy solutions. While fossil fuel-based hydrogen still dominates, advancements in electrolysis and renewable energy inte- gration accelerate the shift toward low-carbon and green hydrogen. In 2023, global hydrogen production totalled 97 million tonnes (Mt), with low-emissions hydrogen accounting for less than 1 % of that volume. However, if current project announcements are realized, the output of low-emissions hydrogen could grow to 49 million tonnes per year by 2030, an increase from the 38 Mtpa projected in the Global Hydrogen Review 2023 IEA [34]. Policy support, technological innovations, and investment initiatives drive global hydrogen expansion (Fig. 2). This progress positions hydrogen as a key enabler of the energy transition and decarbonization efforts. 2.1. Hydrogen demand and consumption The COVID-19 pandemic caused a global decline in hydrogen de- mand in 2020, primarily due to reduced transportation activities and lower refinery and fertilizer production [44]. Despite this setback, the long-term outlook for hydrogen remains strong, driven by climate change concerns and supportive government policies aimed at scaling up decarbonized hydrogen production. Blue hydrogen, derived from fossil fuels with carbon capture, and green hydrogen, produced via water electrolysis using renewable energy, are gaining traction. Hydrogen demand is expected to grow at a ~5 % CAGR between 2016 and 2025, driven by fuel cell vehicles, refineries, and ammonia pro- duction. North America currently leads the hydrogen market due to its robust petrochemical and ammonia sectors, while Asia led by China, Japan, India, and South Korea is rapidly advancing through technolog- ical innovation and infrastructure development [45] (Fig. 3a). Europe, including Germany, France, the UK, and others, also remains a signifi- cant player, with emerging markets like Saudi Arabia, Brazil, South Africa, and Argentina showing potential. Globally, the hydrogen generation market is projected to grow from USD 135.5 billion in 2018 to USD 199.1 billion by 2023, with the Asia-Pacific region leading this growth [44]. China’s investment in hydrogen cities and refuelling sta- tions, and the leadership of Japan and South Korea in fuel cell vehicle (FCEV) development with 60 % of global FCEV sales from South Korea highlight the growing global push toward a low-carbon hydrogen economy. As the energy landscape evolves, global hydrogen demand is ex- pected to reach around 660 million tonnes by 2050, according to the IEA’s Net Zero Emissions (NZE) scenario, which models a pathway consistent with limiting global warming to 1.5 ◦C [46–49]. This pro- jection assumes widespread electrification, rapid deployment of low-emission hydrogen technologies, and stringent policy interventions to phase out unabated fossil fuels. The Sixth Assessment Report of the International Panel on Climate Change (IPCC AR6) pathways similarly emphasise the role of hydrogen in decarbonising sectors where direct electrification is a challenge, including heavy industry and long-distance transport, and other key industries serving as a feedstock in sectors such as food processing, glass, fertilizer, and steel production [50]. It will also be vital for producing synthetic fuels used in maritime and aviation transport, for backup power generation, and for enabling clean mobility through its use in heavy-duty vehicles, long-range passenger transport, and trains (Fig. 3b). Additionally, hydrogen will support high-temperature industrial heating applications [3,47,51]. According to International Renewable Energy Agency (IRENA), hydrogen could meet up to 12 % of global final energy demand by mid-century, with a quarter of this demand being met through international trade, if costs are reduced, and infrastructure is developed. These scenarios highlight the strategic importance of hydrogen in creating a zero-emission energy system, while emphasising the need for coordinated global action to scale up the production and distribution of clean hydrogen. Fig. 4 shows the overview of different methods of hydrogen pro- duction, distribution, and storage; different energy supply by sources and hydrogen applications and utilisations based on sectors (Fig. 4a–d). 2.2. Current development and status of global hydrogen production Hydrogen has emerged as a pivotal driver in global energy transition efforts, increasingly recognized for its strategic role in advancing decarbonization across multiple sectors. As of 2023, worldwide hydrogen production reached approximately 97 million tonnes, yet the vast majority of over 99 % was derived from fossil fuel-based methods, Fig. 2. Chronological overview of notable developments in the hydrogen energy sector, compiled from publicly accessible sources (reproduced from Ref. [43] with permission from Springer Nature, copyright 2025). The growth of the hydrogen industry has experienced fluctuating levels of enthusiasm, with projections and strategic goals differing significantly across regions. (CCS - carbon capture and storage, FCEV - fuel cell electric vehicle, and GHG - greenhouse gas. I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 4 primarily through steam methane reforming [34]. This underscores the pressing need for a shift toward cleaner alternatives. On the develop- ment front, countries and regions are actively investing in low-emission hydrogen technologies, including green hydrogen via electrolysis and turquoise hydrogen through methane pyrolysis. The ongoing, announced and proposed hydrogen projects in Table 1 indicate that low-emission hydrogen capacity could rise to 49 million tonnes per year by 2030, marking a substantial increase from previous estimates. This global surge in development highlights a growing recognition of hy- drogen’s role in decarbonizing hard-to-abate sectors such as industry and heavy transport [34]. Green hydrogen is expected to play a crucial role in achieving these objectives. It is primarily produced via electrol- ysis using renewable energy sources such as solar, wind, hydropower, and biomass gasification. This method provides sustainable, emission-free alternatives to fossil fuels, making green hydrogen a key component in transition to a low-carbon economy [52]. 2.2.1. North America North America is poised to lead the global hydrogen economy, with projections suggesting the market could exceed $140 billion annually by 2030. By 2022, the region had 33 green hydrogen plants with a com- bined capacity of 691,000 tons annually [53]. The U.S. produces around 10 million metric tons (MMT) of hydrogen annually, mainly for petro- leum refining and ammonia production. However, barriers such as high production costs, infrastructure limitations, and low demand incentives hinder progress. Reducing costs through better electricity pricing, enhanced electrolyser performance, and longer equipment lifespans is crucial for scaling up blue and green hydrogen, enabling the shift from pilot to commercial projects [53]. North America benefits from a robust oil and gas industry, rich energy resources, and a diverse demand base. Unlike other regions focusing solely on green hydrogen, North America is developing both blue and green hydrogen infrastructure. The U.S. leads in hydrogen pipeline infrastructure, especially along the Gulf Coast, while Canada hosts the world’s two largest hydrogen projects, totalling 86 MTPA, accounting for 88 % of the region’s planned capacity. Still, over 95 % of U.S. hydrogen is grey, emitting ten times more CO2 per unit of hydrogen [54]. Canada’s Hydrogen Strategy of 2020 targets supplying 30 % of its energy demand with hydrogen by 2050, aiming to be among the top three clean hydrogen producers [55]. Environmental concerns play a central role in Canada’s energy policies. The country ratified the Kyoto Protocol in 2002, but after the election of Prime Minister Stephen Harper in 2006, emissions reduction efforts stalled. Despite its innovation and R&D leadership, Canada’s fragmented policy landscape exacerbated by its withdrawal from the Kyoto Protocol in 2012 has slowed cohesive progress [56]. Significant policy coordination and investment are essential for this region to achieve hydrogen sector leadership. 2.2.2. European Union (EU) Hydrogen is integral to Europe’s transition to clean energy, net-zero targets, and broader sustainability objectives. The EU aims to reduce Liquefied Natural Gas (LNG) imports by expanding hydrogen market. In 2022, hydrogen contributed to less than 2 % of Europe’s total energy use, primarily serving as a raw material for chemical industries such as plastics and fertilizer production. However, 96 % of this hydrogen originated from natural gas, resulting in significant CO2 emissions [57]. To counter this, the REPowerEU Strategy of 2022 set an ambitious goal: by 2030, the EU aims to generate 10 million tonnes of renewable hydrogen domestically while importing an additional 10 million tonnes. In view of its far-reaching potential, almost all EU member states have recognized green hydrogen as an important component of their energy and climate strategies. The EU has set itself the target of installing at least 6 GW (GW) of renewable hydrogen electrolyser capacity by 2024 and increasing this to 40 GW by 2030 [58]. In 2025, EU plans to deploy 17.5 GW of electrolyser capacity to produce 10 million tonnes of renewable hydrogen per year, with a further 10 million tonnes to be imported by 2030, bringing the planned total use to 20 million tonnes per year [58,59]. Looking ahead to 2050, renewable hydrogen is ex- pected to supply roughly 10 % of the EU’s energy needs, crucial in reducing emissions from energy-intensive sectors and transportation [57]. Hydrogen is integral to Europe’s transition to clean energy, net-zero targets, and broader sustainability objectives. The EU’s hydrogen policy framework was introduced in July 2021 as part of the Fit-for-55 package, establishing legally binding targets for adopting renewable hydrogen in industry and transport by 2030 [57]. The EU Clean Hydrogen Partnership (2021–2027) and the European Clean Hydrogen Alliance support the large-scale deployment of hydrogen under Horizon Europe and the EU Hydrogen Strategy. With six thematic roundtables and a project pipeline published in 2021, major efforts such as the Electrolyser Partnership are targeting an annual production ca- pacity of 17.5 GW by 2025. These initiatives reflect the EU’s strong commitment to hydrogen as a cornerstone of the clean energy transition and its potential to decarbonise industry and transport [57]. Europe is the world leader in planned hydrogen investments and in the number of announced projects covering the entire hydrogen value chain. 2.2.3. Asia Pacific In Asia, China leads in hydrogen production, generating Fig. 3. (a). Regional overview of the global hydrogen market (b) Sectoral demand for hydrogen: end users, modified from Ref. Ref. [4,44] respectively. I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 5 approximately 34.1 million tons in 2020, a 2 % increase from 33.4 million tons in 2019. However, the vast majority, 96 % of hydrogen production is derived from fossil fuels such as coal, natural gas, and oil. Electrolysis, including chlor-alkali by-production and water electrolysis, accounts for just 4 % of national output [60]. Coal remains the dominant feedstock for hydrogen production in China, with coal gasification contributing 14.4 million tons, coke production yielding 10.4 million tons, and chlor-alkali manufacturing providing 1.0 million tons in 2020 [60]. Renewable hydrogen production via water electrolysis in remains limited, with only 510 thousand tons annually generated from demon- stration projects and 925 thousand tons from chlor-alkali by-production [60]. On the demand side, the ammonia industry is China’s largest hydrogen consumer, followed by methanol synthesis, petroleum refining, and chlor-alkali manufacturing. These industries often utilize hydrogen as feedstock or process heat. A production-consumption gap of 4.5 million tons per year leads to hydrogen waste, as some hydrogen-rich gases, such as coke oven gases and coal gasifier synthesis gases, are combusted onsite or vented due to economic constraints [60]. Fig. 4. (a) Outlines the primary methods of hydrogen production, distribution, and storage, along with notable applications. (b) Presents a breakdown of global primary energy supply by source, the total hydrogen output from all production methods, and the global final energy demand by sector as of 2022. (c) Shows the global distribution of hydrogen production sources, with color coding corresponding to the supply categories shown in part (b). (d) Illustrates the proportion of hydrogen consumption across end-use sectors, again color-matched to the energy demand in part (b), emphasising that industrial applications currently dominate hydrogen use. Reproduced from Ref. [43] with permission from Springer Nature, copyright 2025. Hydrogen serves as a flexible energy carrier with multiple pathways for production and utilization, yet it remains a minor contributor to the global energy mix and is still predominantly derived from fossil fuel sources. CCS (carbon capture and storage) is a key technology associated with reducing emissions from fossil-based hydrogen production. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 6 Table 1 Some notable global hydrogen projects showing the production capacity and technologies. Project name/Ownership/Partnership Countries Start/announced or commission date Technologies/Energy sources Estimated NH3 or H2 Production Capacity (tons/ year) Refs. North America Air Products and AES Corporation’s Green Hydrogen Facility United States 2027 Electrolysis (Solar & Wind) 57,476.46 [53] Advanced Clean Energy Storage Project United States 2025 Renewable energy 28,734.57 [53] Vallera Renewables Hydrogen Plant United States 2025 Electrolysis 22,943.52 [53] The Wind-to-Hydrogen Project United States 2026 Wind 20,070.84 [53] ZIP Hydrogen facility, phase 1 United States 2017 PEM 350.40 [69,70] SunLine Transit Agency, Palm Springs United States 2018 PEM 324.12 [69–71] NEL - Nikola United States 2020 NA 174,060.20 [70,71] Nikola United States 2020 ALK 359.16 [69–71] Naval Facilities Engineering Command, Engineering and Expeditionary Warfare Centre United State 2016 SOEC 10.95 [69–71] Lake Charles Methanol United States 2022 Fossil 198,873.36 [70,72] Submarines United States ​ PEM ​ [69–71] St. Gabriel Green Hydrogen Plant (Hidrogenii) United States 2025 Renewable energy 182,500 [53] Kingsland Green Hydrogen Plan United States 2025 Renewable energy 4303.47 [53] Casa Grande Green Hydrogen Plant United States ​ Renewable energy 2866.47 [53] Donaldsonville Green Hydrogen Project United States 2025 Alkaline H2O Electrolysis 5,723,179.20 [53] Sauk Valley Green Hydrogen Plant by Invenergy United state 2025 Electrolysis (Solar) 18,980 [53] Enbridge P2G Toronto Canada 2017 PEM 327.63 [70,73] Markham Energy Storage, Ontario Canada 2018 PEM 409.98 [70,71, 74] Northwest Sturgeon refinery Canada 2019 Fossil 133,764.96 [69–71] Nutrien (former Agrium) fertilizer Canada 2019 Fossil 33,228.88 [69–71] Air Liquide Becancour Canada 2020 PEM 3279.19 [70,71, 75] Asia Pacific 2 Yanqing Renewable Energy Hydrogen Production Project - State Power Investment Corporation (SPIC) China 2022 Wind, Solar & Hydro 980 [60] Yumen Oilfield 160 MW Renewables Hydrogen Production Demonstration Project China 2023 Solar 7000 [60] Zhangjiakou Green Hydrogen Energy Integration Demonstration Base Project China 2022 Wind 2800 [60] Huajiu Rooftop Solar PV Power to Hydrogen Project - Huajiu Hydrogen Energy (Henan) China 2023 Solar 153 [60] Henan Pingmei Shenma Group Kaifeng Dongda Chemical 16 MW Solar to Hydrogen Demonstration Project China 2023 Solar 2157 [60] Sinopec Ordos Green Power Hydrogen Production Project - Sinopec China 2023 Solar & Wind 10,000 [60] Narisong Solar to Hydrogen Industrial Demonstration Project China 2023 Wind 10,000 [60] ABC Cleantech – Green Hydrogen and Ammonia India 2022 Solar & Wind 200,000 [76] ACME - Green Hydrogen and Green Ammonia Plant Rajasthan India 2022 Solar 314 [76] ACME- IHI Corporation Green H2 and Ammonia Facility India 2024 Renewable energy 229,600 [76] AVAADA & Tata Steel Special Economic Zone Ltd (TSSEZL) India 2023 Solar 130,000 [76] BPCL - Electrolyser and Blending India 2021 Electrolysis 785 [76] GAIL- GH2 Project India 2024 PEM electrolyser 1570.542 [76] Greenko - Green Hydrogen Production Plans India 2025 Renewable energy 540,000 [76] HLC - Himachal Green Hydrogen and Ammonia Plant India ​ Renewable energy 300,000 [76] HPCL - Andhra Pradesh Green Hydrogen Project India 2023 Renewable energy 7300 [76] Samcheok Green Hydrogen Plant South Korea 2021 Electrolysis - Renewable energy ~365 [77] North Gyeongsang Nuclear H2 Project South Korea 2024 SMR + Nuclear ~10,000 [78] ENEOS Hydrogen Project Japan 2020 Electrolysis (Solar- powered) ~10,000 [79] African Region Mauritania’s AMAN project Mauritania 2022–2029 Solar & Wind 1,700,000 [80] Nour Electrolyser Project Mauritania 2024 Electrolysis 1,200,000 [80] Masdar-Infinity-Conjuncta green hydrogen project Mauritania 2023 Electrolysis 1,360,000 [80] Tsau Khaeb project Namibia 2021–2026 Solar & Wind 300,000 [80] Daures Green Hydrogen Village Nambia 2022 - Renewable energy 31 [80] Swakopmund project Nambia 2022–2025 Solar PV & Electrolysis 1400 [80] Green Ammonia Plant by Hive Hydrogen South Africa 2021–2028 Electrolysis - Renewable energy 300,000 [80] IPM/NCP H2 Refuelling Stations deployment South Africa 2025 Renewable energy 2500 [81] (continued on next page) I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 7 Table 1 (continued ) Project name/Ownership/Partnership Countries Start/announced or commission date Technologies/Energy sources Estimated NH3 or H2 Production Capacity (tons/ year) Refs. HySHiFT Secunda South Africa 2026 Renewable energy 16,400 [81] Ubuntu Green H2: Phase 1 South Africa 2026 Renewable energy 7000 [81] Atlanthia Green NH3/H2: Phase 1 South Africa 2027 Solar and wind 7300 [81] Electrolyser plant at the Suez Canal Economic Zone (SCZONE) by Masdar & Hassan Allam Holding Group Egypt 2022 Electrolysis - Renewable energy 890,000 [80] Fortescue-Egypt-gH2 project Egypt 2022 Electrolysis 300,000 [80] Ain Sokhna Green Hydrogen Plant Egypt 2026 Solar and Wind 100,000 [82] ACME green ammonia project Egypt 2023 Renewable energy 400,000 [80] Amun project by CWP Global and engineering Morocco 2019–2025 Solar & Wind 900,000 [80] Independent power producer (IPP) Total Eren - green hydrogen project Morocco 2024 Solar & Wind 710,000 [80] Hevo Ammonia Morocco project Morocco 2021 Renewable energy 31,000 [80] Masen Green Hydrogen project Morocco 2020 Electrolysis - Renewable energy 8400 [80] Ben Guerir project. Morocco 2017 Solar & Wind 125 [80] Green hydrogen hub by CWP Global Djibouti 2022 Solar & Wind 300 [80] Europe HyDeal Ambition Spain France 2030 Solar PV & electrolyser 3600 [83] Cerulean Winds - North Sea UK 2024 Offshore Wind 259.88 [83] Sines refinery (phase 2) Portugal 2025 Electrolysis 155.93 [83] SALCOS - first expansion Germany 2025 NA 136 [83] Deltaurus 3 Netherlands 2027 NA 121.28 [83] HySynergy, phase 3 Denmark 2030 NA 121.28 [83] Sreen Hydrogen Hub, phase 2 Germany Denmark 2031 NA 121.28 [83] SravitHy France 2027 NA 120.00 [83] IPCEI Black Horse (40 electrolysis production sites) Poland Czech Republic Slovakia Hungary 2030 NA 116.80 [83] Westkuste l00 (Phase 2) Germany 2028 NA 116.08 [83] NortH2, phase l Netherlands 2027 Offshore Wind 173.25 [83] Esbjerg green ammonia plant Denmark 2027 NA 173.25 [83] Iberdrola - H2 Sreen Steel Spain 2026 NA 173.25 [83] NeptHyne, phase 2 Poland 2030 NA 173.08 [83] Solar PV Plant port of Sines Portugal 2030 Solar PV 171.52 [83] Dylan, phase 2 UK 2030 NA 121.28 [83] Deltaurus 3 Netherlands 2027 NA 121.28 [83] HySynergy, phase 3 Denmark 2030 NA 121.28 [83] Green Hydrogen Hub, phase 2 Germany Denmark 2031 NA 121.28 [83] SravitHy France 2027 NA 120.00 [83] IPCEI Black Horse (40 electrolysis production sites) Poland Czech Republic Slovakia Hungary 2030 NA 116.80 [83] Westkuste l00 (Phase 2) Sermany 2028 NA 116.08 [83] Herning Electrolyser Plant Denmark 2023–2025 Electrolysis - Renewable energy 15.0 [84] Belfort Alkaline Electrolyser Gigafactory France 2023–2024 Alkaline Electrolysis 30 [84] Blanquefort Hydrogen Fuel Cell Manufacturing Facility France 2023–2023 Solar & Wind 3.0 [84] Lysekil Green Hydrogen Plant Sweden 2023–2024 Electrolysis - Renewable energy 15.0 [84] Stuttgart-Münster Hydrogen Power Plant Germany 2023–2026 Gas turbine 1.5 [84] Latin America and Caribbean (LAC) Cerro Pabellón Chile 2017 PEM electrolyser 10 [85] Haru Oni, HIF’s operational pilot project Chile 2021 Electrolysis, Wind NA [85,86] Anglo American pilot project Chile 2021 Renewable energy 0.73 [85,87] Ecopetrol’s Cartagena refinery Colombia 2018 PEM electrolyser 7.3 [85] Promigas pilot project Colombia 2019 PEM electrolyser 1.5 [85] Ad Astra Pilot Project Costa Rica 2013 PEM electrolyser 0.8 [85] Helax-Isthmus Facility Mexico 2026 Solar & Wind 900,000 [88] French Developer HDF Projects Mexico 2024 Renewable energy– solar PV 5700 [89] Vale and Green Energy Park (GEP) Partnership Brazil 2024 Renewable energy Not specified [90] Unigel Green Hydrogen Plant Brazil 2023 Renewable energy 100,000 [91] Middle East Region NEOM Green Hydrogen Project Saudi Arabia 2022/2026 Electrolysis (Solar & Wind) 1,200,000 [65] Saudi Aramco Blue NH3 Saudi Arabia 2022–2030 SMR + CCUS 11,000,000 [92] Ruwais Blue Ammonia Plant UAE 2027 SMR + CCUS 1,000,000 [93] Dubai Green Hydrogen Project UAE 2021 Electrolysis (Solar) ~90 [94] Masdar Green Hydrogen UAE 2025 Electrolysis - Renewable energy 1,000,000 [82,95] Green Energy Oman (GEO) Oman 2021–2032 Electrolysis (Solar & Wind) 1,800,000 [96] (continued on next page) I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 8 Optimizing the supply chain could significantly enhance hydrogen ef- ficiency in China. Additionally, Japan aims to consume 3 million tons annually by 2030 and 20 million tons by 2050 to advance a hydrogen- and ammonia-based economy [61]. India has set ambitious energy tar- gets, aiming for energy independence by 2047 and net-zero emissions (NZE) by 2070 [52]. Green hydrogen, produced via renewable-powered electrolysis and biomass gasification, is key to India’s low-carbon future. These methods offer clean alternatives to fossil fuels, advancing national decarbonization goals [52]. 2.2.4. Latin America and caribbean (LAC) (south and central America) LAC has strong potential for low-emission hydrogen production, benefiting from abundant renewable energy and a largely decarbonized electricity mix. In 2023, hydrogen demand reached 4 Mt, mainly for refining and chemicals, but 90 % was produced from natural gas, increasing reliance on imports. The region imports 80 % of its nitrogen- based fertilizers, contributing to a trade deficit of up to 0.4 % of GDP. Expanding domestic low-emission ammonia production could reduce costs, enhance energy security, and stabilize prices. LAC also holds 20 % of the world’s iron ore reserves, with high-grade ores suited for hydrogen-based direct reduced iron (H2-DRI), which could lower reduced iron production costs for importers by nearly 30 %. Opportu- nities vary by country. Mexico and Colombia could leverage existing refinery demand, Chile’s mining sector could adopt hydrogen for decarbonization, and Brazil, responsible for 90 % of LAC’s iron ore trade, could lead in H2-DRI production. Panama, targeting 5 % hydrogen-based shipping fuel by 2030, aims to become a regional fuel hub. Despite potential 7 Mtpa hydrogen production by 2030, only 0.1 % of projects are operational. High capital costs and the need for a 140 % increase in renewable capacity pose challenges. Immediate action is needed to scale production, reduce imports, and develop hydrogen hubs to position LAC in the global hydrogen economy [62]. 2.2.5. African region Africa faces significant energy challenges, with approximately 600 million people lacking access to electricity [63]. The continent’s antic- ipated population and economic growth will require substantial energy expansion. By utilizing renewable resources for green hydrogen pro- duction, African nations can meet this demand sustainably. Addition- ally, the continent holds vast reserves of critical minerals, such as platinum and platinum group metals, essential for fuel cells and next-generation hydrogen technologies. Africa has substantial export potential for green hydrogen. The European Investment Bank estimates that the continent’s green hydrogen production capacity could surpass 50 million tons per annum by 2035, with production costs projected at just €2 per kilogram, making it competitive with global oil prices of approximately €90 per barrel [63]. Proximity to Europe allows Morocco, Mauritania, and Egypt to integrate production into the European Hydrogen Backbone initiative. Other African nations can leverage existing maritime infrastructure to export derivative products such as green ammonia, further enhancing Africa’s role in the global hydrogen economy [63]. 2.2.6. Middle East region The Middle East is rapidly emerging as a global hub for low-carbon hydrogen production, leveraging its abundant renewable resources, strategic export positioning, and substantial capital investment. As of 2025, countries such as Saudi Arabia, the United Arab Emirates (UAE), Oman, and Egypt have announced giga-scale projects aimed at pro- ducing green and blue hydrogen for both domestic use and international export. Saudi Arabia’s NEOM Green Hydrogen Company is constructing a 4 GW renewable energy facility targeting 1.2 million tonnes per annum (Mtpa) of green ammonia by 2026, while the UAE’s Masdar aims to produce 1 Mtpa of low-carbon hydrogen by 2030 [64,65]. As part of its Hydrom initiative, Oman has allocated land for projects aimed at achieving the 2030 target of producing up to 1.5 million tonnes of green hydrogen (gH2) per year (Mtpa) [66]. These developments are sup- ported by regional roadmaps such as the World Economic Forum’s “Enabling Measures for Low-Carbon Hydrogen in MENA,” which iden- tifies key policy enablers and infrastructure priorities [64]. The region’s focus spans export-oriented strategies, decarbonization of existing in- dustrial uses, and novel applications in green steel, sustainable aviation fuel, and maritime shipping. With over 23.5 Mtpa of hydrogen pipeline capacity planned across the Middle East and Africa1, the region is strategically positioned to supply Europe and Asia with competitively priced clean hydrogen, reinforcing its role in the global energy transition [67]. It can be inferred that there are clear regional differences in the development of hydrogen production, characterised by different project deployment and preferred technologies (Table 1). These differences are driven by factors such as resource availability, energy market structures, infrastructure maturity, policy incentives and national decarbonization priorities. In 2023, hydrogen production remains largely fossil, with 4687.3 kt of blue hydrogen from natural gas with carbon capture, compared to only 147.6 kt of green hydrogen from electrolysis with renewables (Fig. 5). North America and the Asia-Pacific region led the way in blue hydrogen production with over 2000 kt each, while the Middle East produced 621.9 kt, almost exclusively from non-renewable sources. In contrast, green hydrogen production was minimal in most regions, with Asia-Pacific leading the way with 93.6 kt, followed by Europe with 31.6 kt. Africa and South America produced negligible amounts of green hydrogen, highlighting the regional disparities in clean energy infrastructure [68]. The dominance of blue hydrogen re- flects the continued dependence on existing natural gas networks and the cost advantages of fossil fuel production. However, this trend un- derscores the urgent need to accelerate investment in renewable energy and electrolyser deployment to meet decarbonization goals. Without a significant shift toward green hydrogen, the climate benefits of hydrogen as an energy carrier remain limited. 3. Environmental assessment of hydrogen The integration of hydrogen into clean energy systems is acceler- ating, driven by its versatility and decarbonization potential. As its role expands, evaluating the environmental sustainability of both its pro- duction, utilization and storage becomes increasingly critical, particu- larly given the wide range of pathways from fossil-based to renewable sources. Green hydrogen, produced via electrolysis using renewable energy, offers the lowest environmental footprint. Storage and trans- portation, however, pose challenges due to hydrogen’s low density and Table 1 (continued ) Project name/Ownership/Partnership Countries Start/announced or commission date Technologies/Energy sources Estimated NH3 or H2 Production Capacity (tons/ year) Refs. Hydrom Block Allocations Oman 2023–2030 Electrolysis (Solar & Wind) 1,500,000 [66] AMEA Power Hydrogen Project Jordan 2022 Electrolysis - Renewable energy 40,000 [82] PEM: Proton Exchange Membrane, PEM: Proton Exchange Membrane, ALK: Alkaline, SOEC: Solid Oxide Electrolysis Cell, NA: Not Available, RE: Renewable Energy. I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 9 high diffusivity. These stages can introduce energy losses and safety concerns, impacting overall sustainability. A holistic environmental analysis is essential to guide policy and investment in a hydrogen economy. 3.1. Life cycle assessment (LCA) of hydrogen production The sustainability of hydrogen energy is influenced by substrate type, processing technology, energy source, and end-use. This sustain- ability is often assessed using tools like LCA and life cycle cost assess- ment (LCC) [97]. LCA evaluates the environmental impacts and resource usage throughout a product’s lifecycle [98]. Its significance spans various aspects of hydrogen, from production and storage to applica- tions, with a particular emphasis on fuel cell-based electric vehicles. This comprehensive view of environmental impacts enables stakeholders to make well-informed decisions [99]. Although hydrogen vehicles emit no pollutants during operation, their lifecycle emissions can exceed those of internal combustion vehicles, depending on the hydrogen production method, prompting extensive LCA research [100]. LCA offers detailed insights into how each stage of the hydrogen fuel cycle contributes to emissions [101]. The environmental impacts during hydrogen utilization largely depend on the application’s efficiency and emissions. Identifying significant environmental impact stages allows LCA to develop strategies to mitigate these impacts, improve efficiency, and enhance hydrogen’s overall sustainability as an energy source [102]. Furthermore, LCA can pinpoint key process steps where changes could significantly reduce environmental impacts [103]. This compre- hensive approach prevents suboptimization by focusing on all processes, enabling the comparison of potential ecological impacts of different alternatives [104]. This information is crucial for creating strategies to enhance the sustainability of hydrogen as an energy source, ensuring it supports global efforts to combat climate change and reduce environ- mental degradation, particularly in its use in fuel cell-based vehicles. To achieve timely decarbonization of the transport sector, evaluating the environmental performance of hydrogen-fuelled cell vehicles (HFCVs) through LCA is crucial. Candelaresi et al. [105] analysed the LCA profiles of hydrogen fuel cell electric vehicles (HFCEVs), hybrid electric vehicles, internal combustion engine cars, and vehicles using hydrogen mixed with natural gas or gasoline. Their results demonstrate that pure hydrogen vehicles are highly effective for achieving decar- bonization. However, further development of more durable fuel cells, optimized engines, and improved hydrogen storage systems is necessary to enhance hydrogen vehicles’ environmental and technical performance and support their broader adoption. Wang et al. [106] observed that HFCEVs powered by hydrogen from coal gasification have slightly higher well-to-wheel (WTW) GHG emis- sions than gasoline internal combustion engine vehicles (ICEVs). Addi- tionally, HFCEVs using grid electricity for on-site water electrolysis exhibit 2.3 times higher emissions than battery electric vehicles (BEVs) and 1.4 times higher than gasoline ICEVs. For gasoline internal com- bustion engine vehicles (ICEVs), the tank-to-wheel (TTW) phase is responsible for about 80 % of well-to-wheel (WTW) greenhouse gas emissions. In contrast, for hydrogen fuel cell electric vehicles (HFCEVs), 63–80 % of WTW GHG emissions are associated with the hydrogen production and transportation stages. Nguyen et al. [107] compared the well-to-wheel (WTW) greenhouse gas (GHG) emissions of hydrogen fuel cell electric vehicles (HFCEVs), plug-in hybrid vehicles, battery electric vehicles (BEVs), and gasoline internal combustion engine vehicles (ICEVs). The found that wind energy-powered hydrogen fuel cell electric vehicles (HFCEVs) produced the lowest emissions, followed by those using biomass, natural gas, and those with carbon capture and storage (CCS). Wong et al. [108] deter- mined that gasoline internal combustion engine vehicles (ICEVs) had 49.5 % lower well-to-tank (WTT) CO2 emissions compared to hydrogen fuel cell electric vehicles (HFCEVs) using natural gas reforming. How- ever, the WTT CO2 emissions for gasoline ICEVs were 200 % higher than those for HFCEVs using renewable electricity for electrolysis. Well-to-wheel (WTW) CO2 emissions for gasoline internal combustion engine vehicles (ICEVs) were found to be 3.37 to 20 times greater than those for hydrogen fuel cell electric vehicles (HFCEVs), depending on the specific hydrogen production method. A Chinese study found that HFCEVs using solar-powered electrolysis reduced CO2 emissions by 76.4 % compared to steam reforming, while electrolysis with China’s grid mix increased global warming potential by 158.3 % [109]. Liu et al. [110] discovered that heavy-duty trucks fuelled by hydrogen produced via renewable energy sources (such as solar and wind) and steam methane reforming had lower greenhouse gas emissions per kilometre than diesel trucks. In contrast, trucks running on hydrogen from grid electricity and coal gasification exhibited substantially higher emissions. Elsewhere, Colella et al. [111] conducted an LCA to compare the greenhouse gas emissions and energy consumption of hydrogen fuel cell vehicles (FCVs) and gasoline-powered vehicles. The study considered hydrogen production via steam methane reforming, coal gasification, and water electrolysis. The results indicated that transitioning to a hydrogen FCV fleet would substantially reduce air pollutant emissions. The life cycle emissions of internal combustion engines, fuel cells, and Fig. 5. Global hydrogen production by region in 2023 totalled approximately 4834.9 kilotons, comprising 4687.3 kt from blue hydrogen (SMR + CCUS) and 147.6 kt from green hydrogen (produced via electrolysis powered by RE). (1000 kt = 1 ton). Adapted from Ref. [68]. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 10 electric vehicles in China were assessed by Yang et al. [112]. Their findings indicated that fuel cell vehicles using hydrogen from electrol- ysis powered by abandoned hydropower and coke oven gas out- performed other options in terms of greenhouse gas emissions and energy consumption, particularly beyond 75,000 km. This highlights the importance of selecting the appropriate vehicle and fuel scenario for optimal sustainability. Joseck et al. [113] examined the well-to-wheel (WTW) emissions of hydrogen fuel cell hybrid electric vehicles (HFCHEVs) utilizing hydrogen sourced from coke oven gas (COG) and compared them with HFCHEVs using hydrogen derived from natural gas with carbon capture and storage (CCS), as well as gasoline and diesel vehicles. Their analysis revealed that HFCHEVs powered by hydrogen from COG produced the lowest emissions at 0.08 gCO2/mi. This was followed by HFCHEVs using hydrogen from CCS at 12 gCO2/mi, natural gas at 26 gCO2/mi, diesel hybrids at 29 gCO2/mi, gasoline hybrids at 34 gCO2/mi, and gasoline vehicles at 47 gCO2/mi. Table 2 shows the emission overview of hydrogen production and consumption in 2023, highlighting different aspects contributing to the emission. 3.1.1. Limitations and gaps in current LCA studies on hydrogen production Despite the increasing number of research papers applying LCA to hydrogen production and utilization systems, there are still several methodological limitations and inconsistencies in the literature that can affect the comparability and reliability of the results of different studies. One of the most notable limitations is the lack of uniformity of system boundaries and functional units, which significantly affects the inter- pretation of results. For example, while some studies use a "well-to- wheel" (WTW) boundary that includes fuel production, distribution, and vehicle operation [106–108], other studies use a narrower scope (e.g., "well-to-tank" or "tank-to-wheel"), which limits holistic environmental comparisons across all fuel pathways [115]. The variability of the data is another major limitation. Many LCA models rely on regional or outdated data sets that may not accurately reflect current technologies or geographic conditions. For example, the carbon intensity of grid electricity used for hydrogen production by electrolysis varies significantly by country and even by region, leading to significant uncertainties in the results [101,116–118]. In addition, LCA inputs such as emission factors for hydrogen production, especially for new or site-specific technologies such as biomass gasification or solar-powered electrolysis, often have insufficient or inconsistent pri- mary data, leading to high sensitivity of results [119,120]. Geographical and temporal inconsistencies also impair comparability. Most LCA studies are context-specific and reflect localized energy mixes, transport infrastructures, and policy scenarios. However, this context dependency makes generalization and benchmarking difficult. For example, while electrolysis using surplus hydropower in Canada shows excellent per- formance [101], similar plants may not be feasible in regions without abundant renewable energy, limiting the reproducibility of results worldwide [118,121]. In addition, the methodologies used to allocate by-products used in hydrogen production, especially in multi-output processes such as methane steam reforming (SMR) with carbon cap- ture or biomass gasification, often vary between energy-based, mass-- based, or economic allocation approaches, contributing to different LCA results [113,116]. This methodological heterogeneity limits the har- monisation of results from different studies and makes it difficult to conduct robust meta-analyses. Another limitation is that some assessments do not consider infrastructure-related impacts. Several studies focus exclusively on operational emissions and disregard the life cycle impacts associated with the construction of hydrogen refuelling stations, pipelines, or electrolysis units, which can be significant, especially in the early stages of deployment [101,122]. Furthermore, temporal dynamics and tech- nological learning curves are rarely considered in LCA models. Most assessments assume static efficiencies and emission factors, although hydrogen technologies, especially electrolysers, storage systems, and fuel cells, are developing rapidly. Ignoring these advances can lead to outdated or pessimistic estimates of environmental impacts [117,119, 122]. Finally, water consumption and land use change, although recognized as critical sustainability metrics, are often under-reported or assessed only qualitatively. However, they are of crucial importance for the assessment of hydrogen production through water electrolysis or biomass-based pathways, especially in water-scarce or land-constrained regions [116,118]. Although life cycle assessment (LCA) is a powerful tool for assessing the environmental impacts of hydrogen production and use, these gaps highlight the need for standardized LCA frameworks, regionally adapted data inputs, and transparent methodological reporting to improve the robustness and policy relevance of LCA in hydrogen research. Address- ing these limitations requires improved and harmonised data collection with transparent reporting of assumptions and uncertainties, the inclu- sion of regional specificities through adaptable LCA frameworks, the inclusion of new technologies and comprehensive system boundaries, and the development of standardized protocols for hydrogen LCA. Future work should also emphasise dynamic LCA modelling, integration with techno-economic assessments (TEA), and the inclusion of wider social and environmental indicators such as water stress, land use, and resource depletion to support informed decision making for large-scale hydrogen deployment. Such advances will improve the robustness and applicability of LCAs and thus support more informed decisions on the role of hydrogen in the sustainable energy transition. 3.2. Environmental assessment of hydrogen utilization Hydrogen’s distinctive physical and chemical characteristics make it ideal for energy storage, transportation, and utilization, although its high flammability poses considerable fire and explosion risks [123]. Currently, hydrogen is mainly produced from fossil fuels through pro- cesses such as coal gasification and natural gas steam reforming [124]. However, future demand is expected to be met by low-carbon alterna- tives like water electrolysis powered by low-carbon electricity, biomass gasification, and fossil fuels combined with carbon capture and storage. Hydrogen finds applications in steel production, biofuel processing, oil sands enhancement, high-temperature processes, welding, Table 2 Aspect Details Total Emissions (2023) 920 Mt CO2 globally from hydrogen production Production Sources ~ 66 % from unabated natural gas (10–12 kg CO2- eq/kg H2) ~ 20 % from unabated coal (22–26 kg CO2-eq/kg H2) Emission Location 75–95 % of emissions occur at the point of production Carbon Capture Potential CCUS can reduce emissions at source Abatement costs (natural gas SMR): ↳ USD 60–85/t CO2 (55–70 % capture) ↳ USD 85–110/t CO2 (>90 % capture) Electrolytic Hydrogen - Emissions-free at production point - Depends on electricity emissions intensity: ↳ Must be < 200–240 g CO2/kWh to be better than SMR ↳ Embedded emissions (construction, etc.): 0.4–2.7 kg CO2-eq/kg H2 Losses due to conversion to Transport carrier - Energy loss: 45–70 % during carrier conversion - Emissions multiply by 2–3 times if grid electricity is used - Lowest emissions: Liquid hydrogen (efficiency >50 %) Hydrogen-Derived Fuels - CO2 source should be biogenic or from air - Electricity intensity thresholds for lower emissions: ↳ Synthetic methanol: <160–190 g CO2/kWh ↳ Synthetic methane/kerosene: <95–140 g CO2/ kWh Accounting Considerations - Emissions depend on how CO2 is allocated across supply chain steps, especially in combustion I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 11 hydrogenation, superconductivity, and rocket engines [102]. More recently, hydrogen is being utilized in fuel cells for electricity genera- tion, in combustion engines for transportation, and as a feedstock in industrial processes [100]. The anticipated growth of fuel cell vehicles (FCVs) is expected to boost hydrogen demand and accelerate the industry’s development. However, the widespread adoption of hydrogen technologies ne- cessitates a comprehensive environmental assessment to evaluate po- tential impacts on ecosystems, water resources, and air quality. Current assessments of conventional hydrogen technologies often fail to account for hydrogen emissions and their immediate warming effects, which occur because the atmospheric oxidation of hydrogen raises the levels of other short-lived greenhouse gases like methane, stratospheric water vapor, and tropospheric ozone [125]. While FCVs are promoted as a crucial solution for reducing pollutant emissions in road transport and energy consumption, their overall greenhouse gas (GHG) emissions can be higher than conventional vehicles if the hydrogen generation path- ways are not sufficiently clean [116]. Major considerations encompass life cycle assessment (LCA), greenhouse gas emissions, impacts on air quality, water and land utilization, efficient use of energy, effects on biodiversity, and waste generation. By evaluating these factors, it is possible to identify the most sustainable production methods, optimize the environmental benefits of hydrogen, and mitigate potential negative impacts. This holistic approach ensures that the transition to hydrogen energy contributes to broader environmental goals, such as reducing global warming, improving air quality, and conserving natural resources. Additionally, the ecological evaluation process guarantees that projects are environmentally viable by promoting comprehensive planning and design, enhancing environmental protection, improving government coordination and accountability, and easing the processes of permitting and regulatory approval. Table 3 compares various hydrogen production methods for fuel cell electric vehicles (FCEVs), focusing on critical environmental metrics such as greenhouse gas (GHG) emissions, energy consumption, and water usage. The assessment is based on a Well-to-Wheel (WTW) anal- ysis of both energy use and GHG emissions using the GREET model (Greenhouse gases, Regulated Emissions, and Energy use in Technolo- gies), developed by Argonne National Laboratory. The GREET model is a widely recognized tool for modelling the full life cycle impacts of transportation fuels and technologies [126]. The analysis indicates that hydrogen produced through electrolysis using renewable energy sources has the lowest GHG emissions, making it the most environmentally friendly option. Conversely, hydrogen generation from non-renewable energy sources, whether through coal-powered electrolysis or steam methane reforming (SMR), is less sustainable due to higher emissions and energy consumption. Hydrogen consumption in vehicles results only in water vapor as a byproduct, enabling zero CO2 emissions during driving. The entire lifecycle can achieve very low carbon emissions when hydrogen is entirely sourced from renewable energy like wind, solar, or biomass [127,128]. To better understand the trade-offs and synergies among key life cycle metrics for various hydrogen production pathways, a radar plot (Fig. 6) was developed using normalized data for greenhouse gas (GHG) emissions, energy intensity, and water consumption. This multi-metric visualization offers a clear comparative perspective across the eight hydrogen pathways presented in Table 3, standardizing values on a 0–5 scale relative to the highest observed value within each metric. The radar plot reveals that electrolysis using coal-dominated grid electricity exhibits the widest environmental footprint, characterized by extremely high GHG emissions (normalized to 5.0), despite low water usage [116]. This finding reinforces concerns raised in prior literature regarding the environmental inefficiency of hydrogen derived from fossil-intensive electricity grids, where thermal power still dominates the energy mix [117]. Thus, deploying electrolysis without decarbon- izing the electricity sector undermines the climate benefits of hydrogen. In contrast, methanol steam reforming and steam methane reforming (SMR) using pipeline methane display more compact profiles, suggest- ing a lower cumulative burden across all three impact categories [116]. Methanol reforming demonstrated the lowest energy intensity (0.23 MJ/MJ H2) and GHG emissions (23.17 g CO2-eq/MJ) among all evalu- ated pathways. However, its performance is highly dependent on the sustainability of upstream methanol feedstock, which must be sourced renewably to maintain these advantages. Biomass gasification and biogas reforming offer favourable GHG profiles but incur higher energy consumption, with normalized values approaching or exceeding 3.0. This highlights the thermochemical complexity and lower conversion efficiencies typically associated with solid biomass feedstocks [118]. Notably, biogas reforming outperforms biomass gasification in both energy and water metrics, supporting its viability as a near-term renewable hydrogen source with fewer process penalties [118]. Catalytic ammonia decomposition, though increasingly recognized for its potential in long-distance hydrogen storage and transport, exhibits a distinct environmental trade-off: it ranks among the lowest in energy intensity but shows the highest water use (8.34 L/km), likely due to intensive process cooling and ammonia handling re- quirements [116]. This highlights the need to couple ammonia cracking with low-carbon ammonia synthesis and water-recycling strategies to mitigate its environmental load. The radar plot emphasises the critical role of the electricity source in shaping the sustainability of hydrogen. Photovoltaic or hydropower- based electrolysis, though not explicitly separated in this dataset, has consistently shown in prior studies to offer substantially reduced GHG emissions when compared to fossil-based pathways [101,119]. From a system optimization perspective, pathways located closer to the centre of the radar plot represent more balanced environmental performance, while those extending along one or more axes indicate trade-offs that may require mitigation through policy, technology improvements, or supply chain decarbonization. Such visual tools are thus invaluable for informing multi-criteria decision-making in hydrogen strategy devel- opment, particularly as countries aim to align their hydrogen roadmaps with both climate and resource conservation goals. 3.3. Safety and environmental impact of hydrogen handling The flammability and ignition properties of hydrogen pose a signif- icant safety and environmental risk during storage, transport and use. Its exceptionally wide flammability range in air (4–75 by volume) and extremely low minimum ignition energy (~0.017 mJ) make it highly susceptible to ignition by static discharge or small electrical sparks [132, 133]. In contrast to methane or petrol vapours, hydrogen flames emit only limited radiant heat (17–25 %) and are almost invisible in daylight, which makes fire detection considerably more difficult and increases the probability of undetected combustion (Table 4). The high flame speed (2.88 m/s) and high auto-ignition temperature (~585 ◦C) allow the flame to spread rapidly after ignition, especially in enclosed or poorly ventilated spaces, where the risk of deflagration and detonation is increased [133–135]. Compared to methane (5–17 vol% flammability range, 0.28 mJ ignition energy) and gasoline vapours (1.4–7.6 vol%, ~0.24 mJ), the ignition sensitivity and detonation potential of hydrogen (0.8 g tetryl equivalent) require enhanced engineering controls, including flame sensors, optical detection systems, antistatic protocols and advanced ventilation strategies to protect both personnel and sur- rounding ecosystems. The dangers associated with storage add to the complexity of hydrogen. Compressed gaseous hydrogen (CGH2) is typically stored at pressures of up to 700 bar, which requires reinforced containment ves- sels with multi-layered composite structures and active pressure relief systems [136]. If these containers are damaged, due to the low density of hydrogen (~0.0827 kg/m3) and high sonic speed (~1294 m/s), large volumes of gas can be released with high jet impulse, leading to rapid volumetric dispersion and overpressure scenarios. Liquid hydrogen I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 12 Table 3 Comparison of Life Cycle Assessment (LCA) of hydrogen utilization in Fuel Cell Electric Vehicles (FCEVs). Hydrogen Production Method Energy Source GHG Emissions Energy Consumption Water Usage Key Findings Ref SMR Natural Gas 52.91–81.77 g CO2 e/ MJ H2 (15 %–45 % lower than gasoline ICEV) 0.87–1.24 MJ/MJ H2 (5 %–33 % lower than gasoline ICEV) – • HFCEVs have lower WTW GHG emissions and fossil energy use than gasoline ICEVs, even when hydrogen is produced via fossil-based SMR. • Emissions from HFCEVs are influenced by the electricity source used for hydrogen compression or liquefaction, affecting overall environmental performance. [129] SMR Natural Gas 48.10 g CO2 e/MJ H2 (50 % of ICEV) 0.65 MJ/MJ H2 (50 % of ICEV) – • Coal-based electrolysis produces the highest GHG emissions and energy consumption among hydrogen production methods. • Electrolysis powered by nuclear energy and natural gas reforming have similar energy demands. • Nuclear-powered electrolysis results in significantly lower emissions compared to natural gas reforming. • Minimizing coal-based hydrogen pro- duction is essential for hydrogen to be a sustainable primary transport fuel [117] Electrolysis Coal 144.30 g CO2 e/MJ H2 (50 % higher than ICEV) 1.55 MJ/MJ H2 (19 % higher than ICEV) – Electrolysis Nuclear power 12.51 g CO2 e/MJ H2 (87 % lower than ICEV) 0.65 MJ/MJ H2 (50 % lower than ICEV) – SMR Natural Gas 117.10 g CO2 e/MJ H2 20.10 MJ/km H2 (~10.5 MJ/MJ H2) 0.86 L/km • Hydrogen from biomass gasification accounts for ~88 % of the total life cycle energy load. • Hydrogen from the steam reforming of maize silage biogas contributes ~83 % of the total energy load. • Both pathways highlight the energy- intensive nature of hydrogen production for bus applications. • Biogas reforming is approximately 32 % less energy demanding than solid biomass gasification among renewable hydrogen production methods. [118] Biomass Gasification Biomass 43.90 g CO2 e/MJ H2 34.50 MJ/km H2 (~17.9 MJ/MJ H2) 4.50 L/km Water Electrolysis Grid electricity, Argentina 201.90 g CO2 e/MJ H2 19.60 MJ/km H2 (~10.2 MJ/MJ H2) 1.04 L/km Biogas Reforming Biogas 51.50 g CO2 e/MJ H2 23.50 MJ/km H2 (~12.2 MJ/MJ H2) 0.92 L/km Water Electrolysis Grid electricity (comprises 88 % hydroelectric power, 11 % thermal power, and 1 % other renewable power plants) 26.94 g CO2 e/MJ H2 (72 % reduction compared to gasoline ICEV) 1.57 MJ/MJ H2 (21 % higher than gasoline ICEV) – • 72 % reduction in total GHG emissions when switching from gasoline vehicles to HFCVs. • 21 % increase in life cycle energy use for HFCVs, mainly due to energy-intensive hydrogen production, distribution, dispensing, and vehicle material requirements. [101] Methanol Steam Reforming Methanol 2780 kg CO2-eq/1000 Nm3 H2 (~23.17 g CO2- eq/MJ H2) 27900 MJ/1000 Nm3 H2 (~0.2325 MJ/MJ H2 30 tonnes/ 1000 Nm3 H2 (~3.34 L/km • Electrolysis has the highest environmental impact among the four common hydrogen production methods in China. • Methanol steam reforming shows the lowest environmental impact, at only 2.24 % of that of electrolysis. • Electrolysis causes a significantly greater global warming impact, mainly due to China’s coal-dominated power grid. • Even with a reduced thermal power share (from 71.6 % to 41.6 %), electrolysis still exhibits higher environmental burdens than other methods. • Electrolysis has the highest fossil energy consumption among the hydrogen production methods studied (44.4 times more than methanol steam reforming, 3.2 times more than steam methane reforming, and 3.5 times more than catalytic ammonia decomposition) • Without major breakthroughs in upstream energy sources or technology, electrolysis is unlikely to be a sustainable first choice for hydrogen production in China. [116] SMR Methane 4580 kg CO2-eq/1000 Nm3 H2 (~38.17 g CO2- eq/MJ H2) 385000 MJ/1000 Nm3 H2 (~3.21 MJ/ MJ H2) 28.67 tonnes/ 1000 Nm3 H2 (~3.19 L/km Electrolysis Grid electricity (China coal- heavy grid) 124000 kg CO2-eq/1000 Nm3 H2 (~1033.33 g CO2-eq/MJ H2) 1240000 MJ/1000 Nm3 H2 (~10.33 MJ/MJ H2 820 kg/1000 Nm3 H2 (~0.091 L/ km Catalytic Ammonia Decomposition Ammonia 36600 kg CO2-eq/1000 Nm3 H2 (~305 g CO2- eq/MJ H2) 352000 MJ/1000 Nm3 H2 (~2.93 MJ/ MJ H2) 75 tonnes/ 1000 Nm3 H2 (~8.34 L/km Polymer Electrolyte Membrane Fuel Cell (PEMFC) Natural gas 132 kg CO2/GJ (132 g CO2-eq/MJ H2) 770 MJ/GJ H2 (0.77 MJ/MJ H2) – • Hydrogen fuel cycle results in higher energy consumption and GHG emissions compared to the gasoline fuel cycle. [122] (continued on next page) I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 13 Table 3 (continued ) Hydrogen Production Method Energy Source GHG Emissions Energy Consumption Water Usage Key Findings Ref • During the vehicle operation phase, ICEVs have higher energy consumption and GHG emissions than PEMFC. Electrolysis Hydropower and Nuclear power 61–130 g CO2-eq/km (50.83–108.33 g CO2- eq/MJ H2) 0.48–0.94 MJ/MJ H2 – • Hydropower- and nuclear-based hydrogen pathways show the lowest energy consumption, approximately 0.48–0.94 MJ/MJ H2. • Natural gas, coal, and grid-based hydrogen pathways do not offer energy or emission advantages over direct fossil fuel use. • FCVs using grid power-based hydrogen exhibit 2–3 times higher life-cycle GHG emissions than ICEVs. [121] Electrolysis Natural gas, Coal and Grid power 187–235 g CO2-eq/km (155.83–195.83 g CO2- eq/MJ H2) – – SMR Natural Gas 0.15 kg CO2-eq/km (~125 g CO2-eq/MJ H2) 2.5 MJ/km (~2.08 MJ/MJ H2) – • Hydrogen fuel from SMR plays a dominant role in overall environmental and energy impacts. • Renewable hydrogen (from biomass gasification and wind electrolysis) contributes less significantly to the system’s footprint. • SMR-based hydrogen has the highest energy footprint among the options evaluated. • Renewable hydrogen sources demonstrate a lower energy and carbon footprint, highlighting their importance in sustainable energy systems. • Substituting SMR hydrogen with renewable hydrogen is crucial for achieving low-carbon, low-energy hydrogen systems. [120] Biomass Gasification Biomass 0.06 kg CO2-eq/km (~50 g CO2-eq/MJ H2) 1.1 MJ/km (~0.917 MJ/MJ H2) – Electrolysis Wind Power 0.065 kg CO2-eq/km (~54.17 g CO2-eq/MJ H2) 0.9 MJ/km (~0.75 MJ/MJ H2) – Steam Reforming Natural Gas 15 kg CO2-eq/kg H2 (~125 g CO2-eq/MJ H2) 93 MJ/kg H2 (~0.775 MJ/MJ H2) – • Grid electricity-based water electrolysis for hydrogen production has the highest energy consumption and produces the largest GHG emissions among the three pathways. • PV electrolysis for hydrogen production has the lowest total energy consumption and generates the least GHG emissions. [119] Water Electrolysis Grid Electricity 40 kg CO2-eq/kg H2 (~333 g CO2-eq/MJ H2) 359 MJ/kg H2 (~2.99 MJ/MJ H2) – Water Electrolysis Photovoltaic (PV) Electricity 0.2 kg CO2-eq/kg H2 (~1.67 g CO2-eq/MJ H2) 70 MJ/kg H2 (~0.583 MJ/MJ H2) – WTW GHG Emission for gasoline = 96.2 g CO2 e/MJ H2 [126,130]; WTW energy use for gasoline = 1.3 MJ/MJ H2 [130,131], (MJ/MJ H2 ≈ 0.52*MJ/km H2). Fig. 6. Radar chart comparing the life cycle assessment (LCA) metrics of key hydrogen production pathways. I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 14 (LH2) held at cryogenic temperatures (− 253 ◦C) has an extreme phase change expansion ratio of approximately 1:848, which poses a serious over-pressurisation risk in the event of boil-off events or venting errors [137],. Improper venting can lead to container rupture and the uncon- trolled release of hydrogen clouds, which can displace ambient oxygen and cause asphyxiation hazards. Material degradation due to hydrogen embrittlement, particularly in metal storage systems, further increases the risk of leakage and structural failure, necessitating the use of hydrogen-compatible alloys and long-term integrity monitoring [133]. In contrast, methane and gasoline have different but similarly serious safety profiles. The higher ignition energy and narrower flammability range of methane reduce the risk of spontaneous combustion, but the spread of methane is heavier than air and increases the formation of pools near the ground and the persistence of flammable clouds. Gasoline vapours with high radiant heat output (33–42 %) and low auto-ignition temperature (~280 ◦C) are particularly susceptible to ignition near hot surfaces and open flames. These safety differences highlight the unique challenges of hydrogen and the need for specialised infrastructure, monitoring technologies and regulatory frameworks to effectively mitigate the risks. 3.4. Environmental impact assessment of hydrogen storage and transportation Hydrogen storage technologies span physical, chemical and geolog- ical domains, each with different trade-offs in terms of performance, Table 4 Safety properties of hydrogen, methane, and gasoline: a comparative analysis Properties H2 CH4 (LNG) Gasoline Implications for Safety and Handling Gas density at NTP (kg/m3) 0.0827 0.659 ~3.2 Hydrogen rises rapidly; gasoline vapours sink and pool, increasing fire risk near ground. Flammability range (25 ◦C, 101.3 KPa) (vol%) 4–75 5–17 1.4–7.6 Hydrogen has an extremely wide flammability range, leaks are more easily ignitable. Autoignition temperature (◦C) ~585 ~537 ~280 Gasoline ignites easily near hot surfaces; hydrogen needs higher temperature but ignites more readily due to low energy threshold. Amount of energy, heat of combustion (lower heating value, LHV) (kJ/g) 120 50 ~44 Under identical conditions of pressure and nozzle size, hydrogen releases approximately 85 % of the discharge energy (per gram) compared to methane during high-pressure gas outflow. Minimum ignition Energy (mJ) ~0.017 ~0.28 ~0.24 Hydrogen is extremely sensitive to sparks and static discharge compared to methane and gasoline Boiling Point (◦C) − 253 − 161 38–204 Hydrogen demands cryogenic conditions, raising complexity and material risks; gasoline is volatile at ambient temperatures. Maximum burning Velocity in NTP air (cm/s) ~265–325 ~37–45 ~35–45 Hydrogen’s fast flame speed raises explosion severity in confined environments. Adiabatic flame temperature (oC) 2045 1875 2045K Hydrogen flames can be hotter Speed of sound at NTP (m/s) 1294 446 446 Hydrogen’s low density and high sound speed increase leak volume but result in similar jet momentum to methane at equal pressure and nozzle size. Laminar diffusion coefficient at NTP (cm2/s) 0.16 0.16 0.05–0.2 Dispersion is mainly driven by turbulence; hydrogen’s flow speed and low density are more critical, leading to extended momentum jets. Detonability measured in minimum mass of tetryl (%) 0.8 16000 50 Hydrogen’s easily denotable in confined mixtures demands stringent leak detection and ventilation controls. Radiant heat from flame to surroundings (%) 17–25 23–33 35–40 Hydrogen fires may go unnoticed without proper sensors; gasoline flames radiate intensely. Compressibility factor Z average 0 to 300 barg 0.1 Jan 0.9 – Non-ideal gas effects slightly lower the hydrogen mass leak rate compared to ideal gas predictions, with the discrepancy increasing at higher pressures. Joule-Thomson effect when pressure is relieved Causes a small temperature increase Causes a temperature decrease Causes a temperature decrease Hydrogen’s minimal temperature rise during filling has little effect. However, heat buildup in compressed hydrogen (CH2) tanks limits filling speed, especially during bunkering. Values for H2 an CH4: adapted from Ref. [135]. Gasoline values: adapted from Refs. [138–150] respectively. Table 5 Environmental implications of different hydrogen storage methods. Storage method Key features Application area Technical/safety challenges Environmental implications Ref. Compressed Gas (CGH2) Hydrogen stored at 350–700 bar in high-strength pressure vessels Cylinders, mobile/stationary systems, aircraft, fuel cell vehicles Low volumetric density, energy- intensive compression, safety risks (leaks/explosions) Moderate lifecycle emissions due to energy use; recyclable vessel materials [151, 157] Liquid Hydrogen (LH2) Stored at − 253 ◦C in cryogenic tanks Space propulsion, long-distance transport, aerospace High energy demand for liquefaction, boil-off losses, complex insulation Significant energy input; potential for GHG emissions if powered by non-renewables [151, 152] Cryo-compressed (CcH2) Combines high pressure and cryogenic temperature Heavy-duty vehicles, fuel cell buses, backup power, stationary storage Thermal management during filling, boil-off, material integrity, denotation Lower boil-off than LH2; still energy-intensive [151, 158] Metal Hydrides Hydrogen absorbed into metal lattices (e.g., Mg-based alloys) Submarines, rail/marine transport, portable devices, home energy systems Heavy system weight, slow kinetics, degradation over cycles Safer storage, mining and disposal of metals pose environmental concerns [151, 159] Chemical Carriers Hydrogen stored in compounds (e.g., ammonia borane, LOHCs) Long-range shipping, ammonia- based fuel systems, LOHCs for stationary/mobile use Irreversible reactions, regeneration complexity, catalyst needs Potential toxicity, handling risks, and recycling challenges [151, 160] Solid-State H2 Storage (SSHS) Hydrogen adsorbed on nanomaterials (e.g., MOFs, graphene) Small-scale transport, FCVs, portable electronics, stationary systems Low uptake at ambient conditions, costly synthesis, energy intensive, immature technology, high temp. Low emissions, material production may involve hazardous chemicals [151, 155] Underground Storage (UGS) Hydrogen stored in salt caverns or porous formations Seasonal grid storage, large- scale energy buffering Geological integrity, microbial conversion, leakage risks, site selection Minimal surface footprint; potential subsurface contamination [151, 156] I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 15 safety and environmental impact (Table 5). Compressed gas systems offer ease of operation and rapid refuelling but are limited by low volumetric energy density and high energy requirements for pressur- isation. Liquid hydrogen (LH2) achieves a higher storage density and is well suited for aerospace and long-range applications. However, its dependence on cryogenic infrastructure and susceptibility to boil-off losses limit its feasibility for decentralised energy systems. Cryo- compressed hydrogen represents a bridge between these approaches and seeks to combine high pressure and low temperatures to increase density [151,152]. In contrast, metal hydrides and chemical carriers offer compact and inherently safer alternatives, especially for stationary ap- plications [151,153,154]. However, their benefits are offset by issues such as the large mass of the system, slow kinetics and the challenges of material regeneration and reversibility. Emerging solid-state adsorption methods including those based on organometallic frameworks and nanostructured materials offer high gravimetric densities and pres- sureless storage with favourable safety profiles, but require break- throughs in ambient temperature uptake and cost-effective synthesis for scalability [151,152,155]. Underground hydrogen storage (UHS) in salt caverns or porous geological formations promises a large and seasonal capacity with minimal above-ground space requirements. However, long-term success depends on overcoming the challenges associated with geological integrity, hydrogen loss through microbial transformation and geochemical interactions that can compromise containment [151,152, 156]. From an environmental perspective, the life cycle emissions and resource requirements of each method are primarily determined by the energy source used for compression, liquefaction or chemical conver- sion. Material-based options may entail risks associated with mining, processing and end-of-life disposal, while underground storage requires rigorous geotechnical assessment to prevent subsurface contamination. The choice of an optimal hydrogen storage strategy therefore depends on balancing energy performance, safety criteria, infrastructure compatibility and environmental responsibility. 3.4.1. LCA of hydrogen storage and transportation The hydrogen produced is subsequently stored and distributed to various end-use sites, including industrial facilities, fuelling stations, and other demand centres. Various hydrogen storage and transportation methods have been investigated, with LCA typically concentrating on the most widely adopted pathways. These include. • storage and pipeline transport of compressed hydrogen gas, • storage and over-the-road transport of gaseous hydrogen using tube trailers, • road transport of liquid hydrogen via cryogenic tankers, and • rail transport of liquid hydrogen. To conduct the LCA, several key assumptions were made concerning the storage and transport of hydrogen in its gaseous and liquid forms [161]. For gaseous hydrogen storage, it was assumed that the hydrogen is stored in subterranean salt caverns, involving only compression and drying stages. In the case of gaseous hydrogen transport via pipelines, it was assumed that additional compression is required to achieve a de- livery pressure of 100 bar. Specifically, electricity consumption for compressing hydrogen from 30 to 100 bar is estimated at 1.05 kWh/kg H2 [162], or 0.48 kWh/kg H2 when compressing from 50 to 100 bar [163], based on pipeline distances of 100 km. For extended pipeline transport, recompression is necessary at defined intervals to maintain pressure. If recompression is performed every 250 km, the energy con- sumption increases to 0.6 kWh/kg H2 [164]; for recompression every 100 km, the requirement is reduced to approximately 0.02 kWh/kg H2 [165]. In the case of tube trailer transport, hydrogen must be com- pressed to pressures ranging between 200 and 500 bar, with an associ- ated energy consumption of approximately 1.36 kWh/kg H2 [162]. Trailers are assumed to transport up to 1100 kg of hydrogen and are powered by EUR6 diesel-fuelled trucks with a total carrying capacity of 32 tonnes [164]. For the distribution of liquid hydrogen, transport by both road and rail was considered. Hydrogen is first compressed and then liquefied to − 253 ◦C. Liquefaction requirements for both transport methods were assumed to be equivalent, with rail transport consuming 1.1 kWh/km [166]. Cryogenic tanks are employed, with road tankers capable of carrying 4200 kg of liquid hydrogen and rail wagons up to 8000 kg [137]. Across all four scenarios (Table 6), a uniform hydrogen loss rate of 4 % was incorporated to reflect typical operational losses [167]. The transportation and storage calculations were conducted using a functional unit of 1 tonne of hydrogen transported over 100 km. In the analysis, the COP26 and EU27 electricity scenarios [168,169], were selected, representing the lowest and highest environmental impacts respectively. The storage and transport options were assessed based on their greenhouse gas emissions, energy consumption and impacts in terms of acidification, eutrophication and human toxicity. Each storage and transport pathway were evaluated against a comprehensive set of environmental impact indicators, including greenhouse gas (GHG) emissions, cumulative energy demand, acidification potential, eutro- phication potential, and human toxicity potential. The key outcomes of this assessment are summarized in Table 6 (adapted and modified from Ref. [161]), offering a comparative insight into the environmental im- plications of different hydrogen logistics configurations under varying energy supply conditions. The findings reveal that the pipeline-based transportation of gaseous hydrogen presents the lowest environmental burden among the assessed storage and transport pathways, particularly when the COP26 electricity mix is applied. This outcome aligns with prior studies such as that by Akhtar et al. [164], which identified pipeline transport as having the lowest greenhouse gas (GHG) emissions and environmental impact po- tentials. Similarly, Wang et al. [170] reported emission and cost ad- vantages of pipeline transport, exceeding 50 % reduction compared to rail and barge - albeit in the context of oil logistics. However, under the EU27 electricity scenario, the environmental impacts rise markedly due to the mix’s reliance on fossil fuels for electricity generation. Electricity-intensive processes, notably hydrogen compression and liquefaction, significantly contribute to the environmental footprint. Transporting hydrogen via pipelines (compressed to 100 bar), high-pressure storage tanks (up to 500 bar), or in liquefied form (at 700 bar) all require considerable energy input, with environmental burdens escalating with increasing compression levels. Liquefied hydrogen transport demonstrates the highest environmental impact due to the substantial energy demand of the liquefaction process. Among liquid hydrogen delivery options, road transport has a slightly greater impact than rail, attributed to diesel-fuelled trucks versus electrically powered trains, which offer greater energy efficiency per unit of transport. Rail thus emerges as a more sustainable option, even over relatively short distances such as 100 km. Future research should prioritize optimizing hydrogen logistics through energy-efficient transport solutions, sup- ported by advanced modelling tools, to address the sector’s significant contribution to climate change as highlighted by Lee et al. [171]. 3.4.2. Comparative analysis of the environmental impacts of hydrogen production, storage, and transport To assess the effect of electricity gen1eeeration sources on the environmental performance of different hydrogen production processes, the analysis considered several electricity supply options, each charac- terised by different environmental trade-offs [161]. Four electricity supply scenarios were analysed: the average Slovenian electricity mix, the average EU27 electricity mix [168], the Slovenian electricity mix aligned with the Glasgow COP26 guidelines in 2021 [169] and a sce- nario using 100 % biomass-based electricity. The biomass scenario, which includes only renewable fuels, was considered due to the exten- sive forest coverage in countries such as Finland (73.7 %), Sweden (68.7 %), Japan (68.4 %) and South Korea (64.5 %) [172]. However, recent I.M.S. Anekwe et al. International Journal of Hydrogen Energy 167 (2025) 150952 16 political developments may have changed some of these figures. The comparative analysis of the GHG footprints of hydrogen- producing technologies shows that T8 (water electrolysis) has the highest emissions when fuelled by the EU27 electricity mix, which relies heavily on fossil fuels (43.6 %) (Fig. 7). However, when applying the COP26 electricity scenario, which is characterised by a cleaner energy mix, the GHG footprint of T8 decreases significantly, underlining the crucial influence of the electricity source on electrolysis-based hydrogen. Also, T11 (iron-based chemical looping) and T9 (aluminium process) show increased GHG emissions due to their high electricity demand for feedstock preparation, pyrolysis and separation processes. In contrast, T1 (methane steam reforming) and T7 (conversion of acid gas to synthesis gas, AG2S) are less electricity-intensive but still have high GHG footprints, primarily due to steam generation, which accounts for 44 % and 85 % of the respective emissions. For T1, natural gas combustion accounts for an additional 27 % of the footprint. These re- sults are consistent with previous studies by Bauer et al. [173] and Cetinkaya et al. [25] that reported comparable or higher emissions from SMR, especially when infrastructure and non-renewable energy sources are considered. Biomass-ba