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Review

A Review of Green Hydrogen Technologies and Their Role in Enabling Sustainable Energy Access in Remote and Off-Grid Areas Within Sub-Saharan Africa

by
Nkanyiso Msweli
*,
Gideon Ude Nnachi
* and
Coneth Graham Richards
*
Department of Electrical Engineering, Faculty of Engineering and the Built Environment, Tshwane University of Technology, Pretoria Campus, Staatsartillerie Road, Pretoria West, X680, Pretoria 0001, South Africa
*
Authors to whom correspondence should be addressed.
Energies 2025, 18(18), 5035; https://doi.org/10.3390/en18185035
Submission received: 20 August 2025 / Revised: 14 September 2025 / Accepted: 15 September 2025 / Published: 22 September 2025
(This article belongs to the Section A: Sustainable Energy)
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Abstract

Electricity access deficits remain acute in Sub-Saharan Africa (SSA), where more than 600 million people lack reliable supply. Green hydrogen, produced through renewable-powered electrolysis, is increasingly recognized as a transformative energy carrier for decentralized systems due to its capacity for long-duration storage, sector coupling, and near-zero carbon emissions. This review adheres strictly to the PRISMA 2020 methodology, examining 190 records and synthesizing 80 peer-reviewed articles and industry reports released from 2010 to 2025. The review covers hydrogen production processes, hybrid renewable integration, techno-economic analysis, environmental compromises, global feasibility, and enabling policy incentives. The findings show that Alkaline (AEL) and PEM electrolyzers are immediately suitable for off-grid scenarios, whereas Solid Oxide (SOEC) and Anion Exchange Membrane (AEM) electrolyzers present high potential for future deployment. For Sub-Saharan Africa (SSA), the levelized costs of hydrogen (LCOH) are in the range of EUR5.0–7.7/kg. Nonetheless, estimates from the learning curve indicate that these costs could fall to between EUR1.0 and EUR1.5 per kg by 2050, assuming there is (i) continued public support for the technology innovation, (ii) appropriate, flexible, and predictable regulation, (iii) increased demand for hydrogen, and (iv) a stable and long-term policy framework. Environmental life-cycle assessments indicate that emissions are nearly zero, but they also highlight serious concerns regarding freshwater usage, land occupation, and dependence on platinum group metals. Namibia, South Africa, and Kenya exhibit considerable promise in the early stages of development, while Niger demonstrates the feasibility of deploying modular, community-scale systems in challenging conditions. The study concludes that green hydrogen cannot be treated as an integrated solution but needs to be regarded as part of blended off-grid systems. To improve its role, targeted material innovation, blended finance, and policies bridging export-oriented applications to community-scale access must be established. It will then be feasible to ensure that hydrogen contributes meaningfully to the attainment of Sustainable Development Goal 7 in SSA.

1. Introduction

Electricity access to clean, affordable, and dependable energy continues to be a pressing global challenge, particularly for remote and off-grid areas of Sub-Saharan Africa (SSA), where millions of people remain without a reliable supply [1]. In these contexts, households and communities still depend heavily on biomass and diesel generators, which are carbon-intensive, costly, and environmentally damaging. Biomass contributes to indoor air pollution, with major health risks, while diesel-based systems face high fuel costs (USD 0.40 to 0.60/kWh) and vulnerability to supply chain disruptions [2,3]. Despite the rapid growth of decentralized technologies like solar photovoltaics (PV), small-scale wind, and hybrid mini-grids in the past several years, their effectiveness is hindered by intermittency, short-duration storage, and insufficient funding for sparsely populated rural regions [4].
Green hydrogen has surfaced as a potential solution to address these limitations. Hydrogen produced via electrolysis using renewable electricity is an energy carrier that can be stored, used flexibly, and emits no CO2. The advantage of hydrogen compared to batteries that can store energy for a few hours to days is that it can store energy for days to seasons, offering the possibility to delink production from utilization [5]. This renders it especially advantageous for rural or weak-grid regions, where the reliability of solar and wind energy supply is diminished and demand patterns are irregular.
Electrolysis technologies exhibit distinct performance and cost profiles. Alkaline Electrolyzers (AEL) are the most established and more economical, with investment costs ranging between EUR500 and 800 per kW; however, they exhibit low current density (<0.5 A/cm2) and inadequate dynamic response to variable renewable energy sources [6]. Proton Exchange Membrane (PEM) electrolyzers attain higher current densities (>2.0 A/cm2) and enhanced load-following capabilities, rendering them suitable for intermittent photovoltaic and wind energy, although their capital costs are elevated at EUR1000–1500/kW due to reliance on iridium and platinum catalysts [7]. Proton Exchange Membrane (PEM) electrolyzers attain higher current densities (>2.0 A/cm2) and enhanced load-following capabilities, rendering them suitable for intermittent photovoltaic and wind energy, although their capital costs are elevated at EUR1000–1500/kW due to reliance on iridium and platinum catalysts [8].
From an economic perspective, the Levelized Cost of Hydrogen (LCOH) of green hydrogen is currently estimated to be in the range of EUR3.5 to 6.0/kg, depending on technology and location, compared to EUR1.0–1.8/kg for grey and EUR2.0–2.5/kg for blue hydrogen [9]. It is estimated that with ideal sun and wind conditions, LCOH for green hydrogen could drop to EUR1.0–1.5/kg by 2050, primarily due to lower electrolyzer capital costs and increased efficiency, as well as declining costs for renewable generation [10]. This shift would render green hydrogen competitive with fossil-based counterparts, enabling deployment in industrial decarbonization and rural electrification applications.
Environmental assessments indicate that green hydrogen can attain almost zero lifecycle CO2 emissions when generated from renewable sources; however, limitations remain regarding freshwater needs, land utilization, and material supply. Conventional electrolysis makes use of up to 9–12 L of deionized water per kg of hydrogen produced, which is an insurmountable deficit in arid regions in the Sub-Saharan part of Africa, such as Namibia and Niger [11]. Integrating electrolysis with seawater desalination results in an increase in USD 0.05–0.07/kg H2 in production costs, leading to a 5–12% rise in Levelized Cost of Hydrogen (LCOH), contingent upon the scale of the plant [12]. The dependence of PEM systems on iridium presents issues related to material scarcity and long-term scalability [13].
Regionally, SSA countries are beginning to position themselves within the global hydrogen economy. Namibia has initiated extensive export-driven initiatives, most notably the Hyphen project, which integrates desert solar resources with seawater distillation [14]. The Republic of South Africa has outlined its Hydrogen Society Roadmap, utilizing platinum reserves for the development of PEM electrolyzers and aiming at both home and international markets [15]. Kenya is advancing geothermal-powered hydrogen production at the Olkaria field, potentially decreasing freshwater demand while supplying low-carbon baseload energy [16]. Notwithstanding these advancements, most national programmes prioritize export and industrial decarbonization, but community-scale hydrogen uses for rural electrification are mostly unexamined.
Existing reviews have addressed hydrogen production technologies [6,8,17], hybrid renewable hydrogen integration [17], and environmental life-cycle assessments [11,12,18]. However, they are typically fragmented, focusing on specific technologies, economic pathways, or policy environments in isolation. Few have synthesized these perspectives to evaluate how hydrogen can directly enable sustainable energy access in remote and off-grid areas, particularly in SSA, where energy poverty remains most acute.
This review differs from prior overviews by centering remote and off-grid Sub-Saharan Africa (SSA), where energy poverty is acute; applying PRISMA 2020 for transparent evidence selection; integrating techno-economic trajectories, environmental trade-offs, and financing/policy frictions specific to high-WACC environments; and adding a materials forward synthesis and technology readiness comparison across incumbent and emerging electrolysis pathways.

2. Materials and Methods

The Preferred Reporting Items for Systematic Reviews and Meta-Analyses (PRISMA) 2020 protocol was applied. Studies were retrieved from Scopus, Web of Science, policy reports, portals, conference proceedings, and IEEE Xplore databases using search terms “green hydrogen”, “electrolysis”, “hybrid renewable”, “remote energy”, “Africa”, and “techno-economic assessment”. Inclusion was limited to peer-reviewed publications and reputable industry reports from 2010 to 2025. A total of 190 studies were identified; after removing duplicates and screening titles and abstracts, 80 remained. Following a full text assessment, 80 studies met the inclusion criteria. Figure 1, presenting the PRISMA 2020 flow diagram, provides the systematic literature review process applied in this review.

3. Hydrogen Production Technologies

Production technologies for hydrogen are defined by the source of energy and carbon intensity, with often related colour coding. The classification reflects the environmental integrity and maturity of the technology, key features for the sustainable energy vision, especially for remote and off-grid applications where decarbonization and resource efficiency are necessary.
Most commonly produced today is grey hydrogen, generated predominantly by steam methane reforming (SMR) of natural gas. The technology for producing grey hydrogen is well-established, featuring good infrastructure, low production costs, and high scalability; however, it remains the most carbon-intensive method, generating approximately 9–12 kg of CO2 per kilogram of hydrogen produced, making it the largest contributor to worldwide greenhouse gas (GHG) emissions [9,19].
Blue hydrogen aims to decouple the emissions of grey hydrogen by applying carbon capture and storage (CCS) technologies to the SMR process. Blue hydrogen presents moderate net CO2 emission reductions while maintaining the maturity, scalability, and low cost of grey hydrogen [20]. Its environmental success, however, relies heavily on the success and longevity of CO2 capture, and it remains vulnerable to upstream methane leakage during natural gas extraction and transportation [21].
Green hydrogen is produced by renewable energy-driven water electrolysis, usually solar or wind, or other renewable energy sources. It emits no direct GHG emissions where it is produced and is considered the most sustainable solution. Green hydrogen has distinct prospects for off-grid circumstances where renewable energy or water is readily accessible, hence improving energy independence [11,22]. Despite its numerous advantages, its technology remains less developed than that of the grey or blue variants, exhibiting a higher levelized cost of hydrogen (LCOH) of EUR3.5–6.0/kg [9]. Subsequent technological advancements, together with falling renewable energy costs, will probably make green hydrogen more equivalent to other alternatives by 2050. That it depends on rare, expensive materials, such as iridium and platinum, for the proton exchange membrane (PEM) electrolyzers presents issues for long-term circularity and sustainability of resources [12,14].
Aqua hydrogen is a new generation of non-oxidizing technologies to produce hydrogen, including plasma pyrolysis and photonic water splitting [23]. The technologies hold the promise of being able to abolish the emission of CO2 altogether without the exploitation of strategic raw materials. Aqua hydrogen has significant potential for low-footprint, decentralized hydrogen generation, suitable for future off-grid applications. The technologies, however, are still in the nascent stage of R&D, with low commercial maturity and small-scale production capacity [11,24].
Table 1 illustrates the comparative characteristics of the four main electrolysis technologies for green hydrogen production. Alkaline electrolyzers (AEL) are the most mature and lowest cost (EUR500–800/kW), though limited by low current density (<0.5 A/cm2) and poor response to variable renewable energy (VRE) [9,25]. Proton Exchange Membrane (PEM) electrolyzers achieve high current densities (>2.0 A/cm2) and dynamic load-following, making them highly suited to off-grid PV–wind hybrid systems, but depend on scarce iridium and platinum, raising costs to EUR1000–1500/kW [12,26,27]. Solid Oxide Electrolysis Cells (SOEC) show high efficiency (75–85%) when operated with Concentrated Solar Power (CSP) or industrial waste heat but have limited durability and high capital intensity [28,29]. Anion Exchange Membrane (AEM) electrolyzers use low-cost and non-noble metal catalysts (such as Ni, Co, and Fe), which possess the advantages of AEL and PEM electrolyzers but are still in premature development with poor long-term stability [12,30,31].

4. Electrolysis Technologies for Green Hydrogen Production

Electrolysis enables the production of green hydrogen from water by splitting it into hydrogen and oxygen using an electric current. It is carbon-free if it is powered by renewable energy. It determines the system technology used to a significant extent with respect to performance, cost, and applicability for off-grid applications. Four major electrolysis technologies being researched and commercially implemented are:
Alkaline Electrolyzers (AEL): The most mature and developed among these categories are the AELs, with the characteristic of the usage of a liquid alkaline electrolyte (commonly KOH or NaOH) and the provision of low cost and operating strength. However, low operating current density, together with slow dynamics for these electrolyzers’ response, hinders integration with intermittent renewable energy sources [9,25,32].
PEM Electrolyzers: PEM electrolyzers possess high efficiency, high current density, quick startup, and high purity gaseous hydrogen output. PEM electrolyzers are applicable for variable renewable energy inputs. The disadvantage of PEM electrolyzers is dependence on expensive rare materials such as platinum and iridium, which leads to shortage issues and supply constraints [12,26,27].
Solid Oxide Electrolysis Cells: SOECs rely heavily on heat and electricity to generate hydrogen with high efficiency at high temperatures; the temperature ranges from 500 to 850 °C. Performance of SOECs is high when combined with concentrated solar power or industrial waste heat sources, as this decreases the electrical energy needed for electrolysis. Common use has been limited by challenges including material degradation from extended high-temperature operation and the complexities associated with thermal management systems [28,29].
Anion Exchange Membrane (AEM) Electrolyzers: The AEM electrolyzers incorporate aspects of the AEL alongside the PEM technologies. The AEM has non-noble metal catalysts, presenting a potential pathway for reducing costs. Though not yet fully developed, the systems of AEM possess potential for future deployment on a large scale [12,28,30,31].
Table 2 illustrates the comparative characteristics of the four main electrolyzer technologies for green hydrogen production. AEL is the most mature technology, with low capital cost (500–800 EUR/kW) and available materials (Ni, Fe, Co). But they have a limited range of low current densities (below 0.5 A/cm2) and poor flexibility regarding the variable renewable energy (VRE) [9,25]. Although proton exchange membrane (PEM) electrolyzers have a high efficiency (60–70%) and a fast response, with current densities exceeding 2.0 A/cm2 that enable optimal integration with solar photovoltaic and wind energy, their capital expenditures (EUR1000–1500/kW) and reliance on iridium and platinum present challenges for scaling up [12,26,27].
Solid Oxide Electrolysis Cells (SOEC) function at elevated temperatures (500–850 °C) and attain exceptional efficiency (75–85%) when integrated with concentrated solar power (CSP) or industrial waste heat; however, they are plagued by durability challenges, thermal cycling stress, and substantial prices (EUR1200–2000/kW) [28,29]. Anion Exchange Membrane (AEM) electrolyzers, which utilize non-noble catalysts such as Ni, Co, and Fe, are a developing alternative priced between EUR600 and EUR1000/kW. They demonstrate potential for off-grid applications; however, their long-term chemical stability and commercial viability are still being evaluated [12,30,31].

5. Emerging Technologies and Material Innovation

Technological advancement is crucial in the progression of catalytic and integrated hydrogen technologies. Table 3 provides examples of new technologies that enable advancements in catalytic, membrane, and storage systems for hydrogen. Replacement of platinum group metals (PGMs) with non-precious metal catalysts such as Ni, Fe, and Co could substantially lower the overall cost of the MEA while maintaining similar electrochemical performance; however, the stability at high current densities remains an issue [33,34]. Annular catalysts and high entropy materials (HEMs) improve durability and provide tunable surface properties, reducing the extent of decay that often limits long-term electrolysis service [35,36].
The advent of anion-exchange membranes (AEMs) presents the opportunity to substitute expensive proton exchange membranes (PEMs) in alkaline environments, thereby decreasing system costs and minimizing ohmic losses [37]. However, their chemical stability under prolonged operation is still under investigation. Composite PEMs, by contrast, have shown improvements in corrosion and gas crossover resistance, which directly enhances efficiency and system lifetime [38]. Complementary to electrolysis membranes, hydrogen-selective nanocomposite separation membranes are improving purification and lowering the balance of plant penalties [39].
Material science is equally disruptive in the storage space. Metal hydrides have much higher volumetric density as well as an intrinsic safety advantage over the compressed gas, but sluggish kinetics and weight are still the bottleneck for scaling up [40]. Porous carbons, metal–organic frameworks (MOFs), and covalent-organic frameworks (COFs) offer lightweight and adjustable adsorption capacities; however, producing them on a large scale still faces significant challenges [41]. These material advances influence the techno-economics of hydrogen production, storage, and utilization by reducing system costs and improving performance and sustainability. They illustrate that advancements at the material level result in comprehensive enhancements in efficiency and cost competitiveness, underscoring the pivotal role of material science in advancing the hydrogen economy.

6. Hydrogen Storage and Transport Technologies

Hydrogen storage and transportation technologies are essential facilitators of green hydrogen implementation, particularly in remote and off-grid areas [42]. Compressed hydrogen gas (350–700 bar) is the most commercially developed method, providing convenience but with the drawbacks of low volumetric density and elevated energy demands for compression [43]. Liquid hydrogen storage attains superior energy density; yet, it entails considerable cryogenic energy penalties (3–40% of energy content) and boil-off losses [44].
Solid-state storage technologies, such as metal hydrides, carbon adsorbents, and liquid organic hydrogen carriers (LOHCs), offer safer and potentially more energy-dense alternatives. However, challenges related to weight, kinetics, and scalability of the required processes persist [44]. Pipelines provide a cost-effective solution for long-distance transportation in infrastructure sectors; however, utilizing trucks to transport compressed or liquefied hydrogen may adequately serve small-scale or remote applications [44,45]. Transporting hydrogen in the form of ammonia or methanol is becoming a cost-efficient long-distance method, complemented by the advantage of existing handling infrastructure [46]. For remote and off-grid regions, modular storage solutions such as compressed tanks and LOHCs may offer the best balance of safety, cost, and practicality [44,47].
Table 4 illustrates that the hydrogen storage and transportation system must reconcile multiple trade-offs that affect its appropriateness for remote and off-grid environments. The most advanced and adaptable option is compressed hydrogen (350–700 bar), although it is impeded by low volumetric density and significant energy costs associated with compression. Liquid hydrogen provides a higher energy density of 8–9 MJ/L; however, it is associated with considerable liquefaction and boil-off losses. Solid-state systems, including metal hydrides and liquid organic hydrogen carriers (LOHCs), provide improved safety and compactness, but they encounter issues related to weight, cost, and kinetics. The LOHC option is particularly appealing because of its compatibility with current infrastructure. Pipes are economically viable for transportation only where existing infrastructure is present, while the delivery of compressed or liquefied hydrogen by truck is flexible but costly for lesser supply volumes. Chemical carriers such as ammonia and methanol facilitate efficient long-distance trade through established networks; however, the process of reconversion diminishes overall efficiency. Compressed storage and LOHCs are optimal for decentralized mini grids, whereas liquid hydrogen and chemical vectors are essential for the expansion of regional and global hydrogen integration.

7. Renewable Integration and Hybrid Systems

The incorporation of green hydrogen production using renewable energy is crucial for achieving sustainable electrification in rural and isolated areas. Promoting the utilization of variable renewable energy (VRE) systems, including solar photovoltaic (PV), concentrated solar power (CSP), and wind turbines in conjunction with electrolyzers, hydrogen can offer long-term storage solutions that address the discrepancies between supply and demand, thereby mitigating the intermittency challenges currently encountered by mini-grids where such VRE is increasingly implemented [4,48,49,50]. In contrast to traditional batteries, primarily intended for short-term storage, hydrogen provides seasonal versatility and can fulfil various energy requirements, including electricity, heating, and the generation of clean cooking fuels essential for the sustainability of off-grid communities.
Case studies in regions with high solar irradiation, such as Sub-Saharan Africa and the Middle East, validate the viability of PV–hydrogen hybrid systems, particularly when Proton Exchange Membrane (PEM) electrolyzers function under optimal solar load-following circumstances [51,52,53]. The accurate sizing of photovoltaic capacity, electrolyzer specifications, and hydrogen storage capacity significantly impacts efficiency and economic feasibility, as demonstrated by studies from Sarker et al. [54] and Benghanem et al. [55], which indicate the presence of curtailment losses or underutilized resources due to oversizing or undersizing, respectively. Moreover, the incorporation of supplementary battery storage may enhance system stability by mitigating short-term fluctuations in variable renewable energy (VRE), while solid oxide electrolysis cells (SOECs) facilitate thermal integration with concentrated solar power (CSP) and industrial waste heat, thereby improving overall conversion efficiency [29,55].
Figure 2 illustrates an example hybrid system with solar arrays (PV), wind turbines (WT), PEM or SOEC electrolyzers (ELs), hydrogen storage (HSF), and fuel cells (FCs) control to provide flexibility and reliability. Hybrid systems are suitable for rural and weak grids, where modular and waterproof (off-the-shelf) configurations, incorporating solar and wind energy, can offer a scalable solution for community electricity. They advocate for energy self-sufficiency, diminish reliance on imported hydrocarbon fuels, and foster sustainable socio-economic growth. In accordance with global decarbonization objectives, renewable hydrogen hybrid systems provide a viable framework to guarantee universal access to energy services while maintaining environmental acceptability [53,56,57].

8. Techno-Economic and Environmental Assessments

Although green hydrogen has the potential to be a clean energy carrier, its large-scale application is currently hampered by technological, economic, and environmental constraints. The current Levelized Cost of Hydrogen (LCOH) illustrates the economic disparity between green and fossil-derived hydrogen. As shown in Figure 3, grey hydrogen produced from steam methane reforming (SMR) remains the cheapest option at EUR1.0–1.8/kg, while blue hydrogen with carbon capture and storage (CCS) costs EUR2.0–2.5/kg [11,19].
By contrast, green hydrogen remains the most expensive, with present LCOH ranging from EUR4.0–6.0/kg in low-resource contexts to EUR2.0–3.0/kg in high solar and wind regions [18,58]. Projections consistently indicate that costs could decline to EUR1.0–1.5/kg by 2050, driven by declining renewable electricity prices (already <EUR0.02/kWh in SSA projects), reductions in electrolyzer CAPEX from the current EUR800–1500/kW (PEM) to below EUR400/kW, and efficiency improvements in advanced electrolyzers such as PEM and SOEC [29,55].
Figure 3 highlights this transition, showing that, although green hydrogen currently costs more than twice as much as grey hydrogen, it is expected to reach cost parity within the next three decades. For off-grid Sub-Saharan Africa, this trajectory has two implications: in the near term, subsidies, concessional financing, or blended business models are required to make green hydrogen competitive with diesel (USD 0.40–0.60/kWh, equivalent to EUR8–10/kg H2 energy) [2,3]; in the long term, parity enables substitution of diesel with green hydrogen as the primary off-grid energy vector, offering multi-day storage, reliable electricity through fuel cells, and cross-sectoral applications such as clean cooking and transport.
From an environmental standpoint, green H2 has near-zero lifetime CO2 emissions when produced by renewable electricity, versus 9–12 kg CO2/kg H2 for grey H2 in this respect [13,19]. However, Figure 3 suggests that competitiveness is insufficient if the environmental trade-offs remain unresolved. Electrolysis requires 9–12 L of purified water per kg of hydrogen: an onerous burden in the water-sparse (“water-starved”) regions of SSA, while desalinating seawater costs EUR0.05–0.07/kg H2 [11,12]. In addition, PEM electrolyzers rely on scarce iridium and platinum, raising long-term scalability concerns [13]. These techno-economic and environmental insights reinforce that achieving the cost convergence shown in Figure 3 requires not only falling LCOH but also advances in water management, material substitution, and site-specific hybrid integration.
Figure 4 illustrates the anticipated progression of the Levelized Cost of Hydrogen (LCOH) across grey, blue, and green paths until 2050, highlighting regional variations and long-term convergence. Grey hydrogen is currently the most economical option, priced at approximately 1.0–1.8 euros per kilogram, owing to the existing SMR infrastructure; nevertheless, it is the least environmentally friendly, with lifetime emissions of 9–12 kg CO2 per kg H2 [19]. Blue hydrogen offers moderate pricing (EUR2.0 to EUR2.5/kg) and partial decarbonization; however, it is significantly affected by carbon capture efficiency (>90%) and upstream methane emissions, which diminish its environmental efficacy [59].
The current cost of green hydrogen is elevated (EUR3.5–6.5/kg globally); Namibia occupies the upper range (EUR6.0–7.7) due to nascent infrastructure and water scarcity, while Niger, South Africa, and Kenya are positioned in the mid-range (EUR5.0–6.5/kg) but exhibit greater competitiveness within Africa [11,22]. By contrast, optimized high-resource regions such as Chile and Morocco already achieve significantly lower values (EUR2.0–3.0/kg) due to exceptional solar-wind yields, integrated infrastructure, and favourable financing conditions [19]. Projections are always estimates, but they generally suggest that the falling price curve for renewable electricity (likely to fall below <EUR0.02/kWh in SSA), improved electrolysis efficiencies (both PEM and SOEC), and reduced CAPEX (expected to fall under <EUR400/kW by 2050) will reduce the cost of green hydrogen to EUR1.0–1.5/kg, make it cost-competitive with fossil-derived alternatives, and confirm it as the primary long-term decarbonization path [11,59].
From an environmental standpoint, Life Cycle Assessment (LCA) has emerged as a vital tool to quantify the environmental performance of various hydrogen production routes. The main findings of the latest LCA studies [11,19,22] are as follows:
  • Green hydrogen has the lowest carbon intensity, typically near zero when produced with fully renewable electricity;
  • Water demand is a critical consideration, particularly in dry regions where desalination is needed, increasing energy consumption and system complexity;
  • Scarce materials: The need for platinum group metals (PGMs) such as iridium and platinum in PEM electrolyzers, and rare earths for related power electronics, is increasing;
  • End-of-life management of system components, such as membrane recycling and safe disposal of catalysts, remains under-addressed in many studies.
Figure 5 provides a comparative radar analysis of the environmental impacts of grey, blue, and green hydrogen production technologies, using normalized life cycle assessment (LCA) scores where 0 represents the best performance and 5 the worst. Grey hydrogen, produced mainly via steam methane reforming, scores worst in terms of greenhouse gas emissions (9–12 kg CO2/kg H2) and air pollutants, though it performs impressively on land occupation and process efficiency due to its compact footprint [19]. Blue hydrogen functions at a moderate efficacy: it can significantly diminish emissions when carbon capture rates exceed 90% and methane leakage is limited, yet it still incurs drawbacks related to energy consumption for carbon capture and solvent management [60]. Green hydrogen is exclusively generated through renewable-driven electrolysis, resulting in near-zero CO2 emissions and negligible operational air pollutants, rendering it the optimal choice for climate and air quality. However, it entails adverse social trade-offs regarding water footprint (9–12 L/kg H2, increased when desalination is factored in arid regions), critical mineral requirements (with iridium and platinum being essential for PEM electrolyzers), and land utilization (for extensive solar and wind installations) [11,61,62]. The radar thus highlights the differentiated sustainability challenges of each pathway: grey is carbon-intensive, blue is transitional but leakage and capture dependent, while green is climate-optimal but constrained by resource intensity in water, land, and materials, particularly in Sub-Saharan African conditions.
A crucial element of hydrogen economics is the region-specific variability, since it profoundly influences the feasibility of output. In arid regions such as Niger and Namibia, the limited availability of freshwater exacerbates the environmental impact and financial burden associated with electrolysis, whether through water importation or desalination, both of which require significant energy expenditure [2]. Similarly, the implementation of desalination or direct seawater electrolysis, especially by coastal nations like Morocco and South Africa, may alleviate scarcity issues, albeit at the cost of increased operational expenses [63].
In contrast, places rich in solar and wind resources exhibit lower levelized hydrogen prices compared to those reliant on biomass and hydropower [64]. These trends underscore that a universal evaluation is inadequate; techno-economic frameworks must be customized to local resource availability, water scarcity, infrastructure development, and policy contexts [60]. Table 5 provides a comparative overview of selected case regions, demonstrating how water availability, renewable resources, and infrastructure limitations affect the region-specific implications on the levelized cost of hydrogen (LCOH).

9. Regional Feasibility in Sub-Saharan Africa

Sub-Saharan Africa (SSA) has enormous potential for the use of green hydrogen due to its abundant renewable resources, increasing demand for energy, and developing interest in low-carbon production. High solar irradiation, reliable wind patterns, and endless stretches of unutilized land make many countries across Sub-Saharan Africa’s total land area the perfect location for large-scale electrolyzers powered by renewable energy. But feasibility differs throughout the region depending on infrastructural preparedness, water availability, legal-related issues, and investment regimes.
The first frontrunners comprise Namibia and South Africa, both of which have implemented national plans and pilot initiatives. Namibia, via the Green Hydrogen Council and partnerships with Germany, aims to utilize its desert solar resources and desalinated seawater to develop an export-focused hydrogen industry. The Hyphen Hydrogen Energy initiative embodies similar aspirations, aiming for an eventual electrolysis capacity of 300,000 MW, bolstered by substantial foreign funding. Namibia’s estimated Levelized Cost of Hydrogen (LCOH) ranges from EUR6.0 to EUR7.7 per kilogram, which is relatively costly; however, this is mitigated by scalability and strong policy alignment [12,61,62].
South Africa, using its established industrial infrastructure, platinum supplies for PEM electrolysis, and significant renewable energy potential, has developed a detailed Hydrogen Society Roadmap. Projects in the Northern Cape and Western Cape provinces establish South Africa as a continental leader. With a planned capacity of 200,000 MW—150,000 MW of which is already under active development—South Africa has an estimated LCOH of EUR5.0–6.5/kg, making it regionally competitive and globally relevant [61,62].
Other Sub-Saharan African (SSA) nations are advancing their hydrogen production through various methods. Kenya is utilizing its geothermal resources at Olkaria to pursue a distinctive approach to hydrogen production powered by geothermal energy. Kenya has the potential to become a niche producer of low-carbon hydrogen, with a projected capacity of 120,000 MW (40,000 MW currently under development) and a levelized cost of hydrogen (LCOH) ranging from EUR5.0 to EUR6.0 per kilogram [61,64,65]. Niger, with less infrastructure development, has also expressed interest in hydrogen for rural energy access. The capacity at the feasibility stage is expected to be 80,000 MW, with LCOH at EUR5.5–EUR6.5 per kilogram. Its potential, however, is water-constrained and transmission constrained; nevertheless, international support and inclusion of photovoltaic electrolysis could improve its economic viability [61,66].
Outside of SSA, Mauritania, Morocco, and Egypt are establishing hydrogen clusters to supply European demand, capitalizing on their strategic port access. As illustrated in Sub-Saharan Africa, countries such as Ethiopia and Angola are undertaking feasibility studies, exploring opportunities for cross-border trade in hydrogen-derived products and renewable electricity [12].
The regional perspective holds significant potential; however, it is constrained by systemic issues such as financing arrangements, skills development, water resource management, and policy harmonization. Aligning renewable resources, political commitment, and international alliances could enable Sub-Saharan Africa to sustainably fulfil local energy requirements while competitively engaging in the burgeoning global hydrogen economy.
Figure 6 shows a qualitative comparison of green hydrogen feasibility in SSA countries, in which renewable energy resources, water management approaches, policy frameworks, and the role for international cooperation are included. Namibia boasts excellent solar and wind; however, the country faces severe water scarcity, and desalination is, thus, needed [61,62]. South Africa displays balanced feasibility through the provision of a mature Hydrogen Society Roadmap, reserves of platinum for PEM electrolyzers, and a manufacturing base [60,62]. Kenya uses geothermal power from Olkaria to help with the shortage of freshwater, and there is a difference, as their policy structure is not as integrated [65]. Niger, despite its significant solar potential, scores lower overall due to severe water scarcity, inadequate infrastructure, and little institutional capability, underscoring its reliance on foreign collaborations [66].
Figure 7 illustrates the green hydrogen development in leading African countries. Namibia dominates with export-oriented projects like the Hyphen initiative (≈300,000 MW planned), underpinned by German and EU investment [61]. South Africa ranks next, with more than 150,000 MW currently in development and a robust status as both a regional hub and exporter [60,62]. Kenya progresses in geothermal-powered hydrogen (about 120,000 MW potential), diversifying beyond solar and wind while mitigating water scarcity [65]. Niger is currently in the feasibility phase (about 80,000 MW), focusing on rural electrification projects, although impeded by financial and infrastructural deficiencies [66]. Together, Figure 6 and Figure 7 show that while Namibia and South Africa lead export-oriented megaprojects, Kenya and Niger are pursuing resource-driven, context-specific pathways, underscoring that SSA’s hydrogen transition is heterogeneous and shaped by resource endowment, governance capacity, and strategic partnerships.

10. Policy, Financing, and Social Considerations

The effectiveness of green hydrogen in promoting energy access across sub-Saharan Africa (SSA) primarily relates to harmonizing legal frameworks, financing mechanisms, and community acceptance, rather than focusing on technology improvements. Despite their large renewable bases, most of the existing national hydrogen policies in Sub-Saharan Africa tend to focus more on exports and industrial-scale projects to serve European or Asian markets. This bias is reflected in the Green Hydrogen and Derivatives Strategy of Namibia and the Hydrogen Society Roadmap of South Africa [60,67]. While these efforts provide geo-positioning, they under-represent decentralized systems such as mini-grids and nanogrids and community-scale projects, which are critical for achieving universal access in rural Sub-Saharan Africa. Without recalibration, the region is facing two significant changes: one characterized by increasingly busy shipping lanes and the other by ongoing local poverty affecting energy opportunities.
A central cross-cutting issue in SSA is the water-energy nexus. Electrolysis consumes approximately 9 L of deionized water per kg of H2 produced, and this demand becomes material in arid zones such as Namibia’s Karas region or northern Kenya, where annual freshwater availability is <500 m3 per capita [68]. In these contexts, coupling hydrogen systems with desalination or wastewater recycling is not optional but a prerequisite. Studies suggest that desalination adds USD 0.05–0.07/kg H2, translating into a 5–12% increase in LCOH for off-grid systems [69]. Absent clear regulatory frameworks governing water rights and abstraction, hydrogen development risks generating new conflicts over scarce water resources. Policies in SSA must therefore integrate water governance explicitly into hydrogen planning, an area currently underdeveloped in national strategies [60].
The financial terrain is the central determinant of hydrogen viability in SSA. In Africa, the weighted average cost of capital (WACC) of renewable ventures is 10–12%, which is twice the 4–6% in OECD countries [70]. Addressing this gap requires holistic financial tools, such as sovereign guarantees, soft loan facilities, and de-risking methods through the African Development Bank’s Sustainable Energy Fund for Africa (SEFA) and international climate funds [71,72]. Supporting policies, including results-based finance and participation in carbon price mechanisms (range USD 40–80/tCO2), could enhance profitability of projects [73,74]. Community cooperatives and microfinance models that have been successful in solar mini-grids in East Africa can add bankability at smaller scales, especially when they include profitable uses such as cold storage for fisheries in Namibia or agro-processing centres in Kenya [67,75].
Recognition by society is equally important in Sub-Saharan Africa. Assessments of public opinion in Kenya and South Africa reveal that over 60% of respondents associate hydrogen with explosive risks, underscoring a deficiency in knowledge and adverse views of industrial incidents [13]. These assumptions can impede uptake unless countered by safety training, explicit risk benefit communication, and development of local technicians’ skills. On the other hand, hydrogen systems provide many development benefits, such as providing reliable electricity for health centres, schools, and irrigation; enabling rural cold chains for agriculture and fisheries; and strengthening resilience in grid-infeasible areas [76]. Employment generators possess substantial importance. Decentralized hydrogen systems create approximately 30 to 40 jobs in installation, operation, maintenance, and productive use industries for every megawatt produced (IRENA) [60]. To fully capitalize on these advantages, SSA countries must deliberately craft hydrogen policies that connect export-oriented investments with local socio-economic advancement.
Equity and gender inclusion are important factors in Sub-Saharan Africa, where women are disproportionately affected by energy poverty. The collection of biomass for cooking fuels (and even heating) alone at as much as 3–5 h per day for women has negative impacts on their educational, health, and economic activities [77]. Hydrogen-based electrification addresses this issue by providing accessible clean cooking solutions and ensuring reliable household energy access. An empirical study conducted in Kenya demonstrates that the involvement of women in community energy cooperatives improves adoption, governance, and sustainability outcomes [78]. The integration of gender-responsive funding mechanisms, such as targeted grants, women’s cooperative quotas, and training programmes, in hydrogen policy frameworks can also help in achieving a fair share of the benefits [79].
Ultimately, hydrogen should be incorporated into complex governance systems throughout Sub-Saharan Africa. Incorporating hydrogen into electrification initiatives and Nationally Determined Contributions (NDCs) at the national level will facilitate access to international climate finance [60]. Regional centres for hydrogen could provide balancing, seasonal storage, and black start services to the Southern African Power Pool (SAPP) and East African Power Pool (EAPP), directly linking hydrogen to regional energy security. At the level of international exports, export corridors such as Namibia-Europe may be incentivized, but with domestic access obligations, local content requirements, and water protection to avoid enclaves. A just transition in Sub-Saharan Africa requires policy regimes that are geared towards global competitiveness, regional integration, and rural electrification simultaneously [80]. Neglecting any of these dimensions would undermine the credibility and persistence of hydrogen as a tool for inclusive development.

11. Conclusions

This review synthesized technological, economic, environmental, and policy dimensions of green hydrogen as an enabler of sustainable energy access in remote and off-grid regions of Sub-Saharan Africa (SSA). Applying the PRISMA 2020 methodology to evaluate 80 peer-reviewed papers and reports, the results indicate that hydrogen distinctly overcomes the constraints of traditional storage by offering long-term to seasonal storage buffering, sector integration, and significant carbon emission reduction potential.
Electrolysis methods demonstrate a range of preparedness. Alkaline (AEL) and Proton Exchange Membrane (PEM) electrolyzers are readily available, while Solid Oxide Electrolysis Cells (SOEC) and Anion Exchange Membrane (AEM) electrolyzers are longer-term options that depend on advancements in efficiency, durability, and material innovations. Currently, the levelized costs of hydrogen (LCOH) in Sub-Saharan Africa range from EUR5.0 to EUR7.7 per kilogram, which is relatively high. Nevertheless, the costs for hydrogen production based on learning curves are suggested to meet those of hydrogen from fossil fuel, EUR1.0–1.5/kg, if the best landscape scenarios (for insolation and wind power) for PV and wind energy use already take place in 2050. Environmental life cycle assessments reconfirm that green hydrogen has near-zero carbon emissions but also stress limitations regarding freshwater use (≈9–12 L/kg H2), land area, and the dependence on PGMs.
The feasibility varies regionally. In Namibia and South Africa, the focus is on leadership and large-scale, export-capable developments. In Kenya, geothermal potential meets the demand for water to produce hydrogen. Conversely, in Niger, structural barriers exist, making modular community-scale solutions potentially more suitable.
Overall, green hydrogen should be regarded as a reinforcing, supplementary component, a complement inside hybrid arrangements rather than an independent solution. Realizing its potential requires material innovation, water-secure system design, concessional finance, and policies that link export ambitions to domestic access mandates. Future reviews should prioritize pilot-scale hybrid mini-grids in SSA, material thrifting and recycling strategies for electrolyzers, integrated water-energy planning, and frameworks that evaluate the socio-economic impacts of hydrogen adoption at the community level.

Author Contributions

Conceptualization, N.M., G.U.N. and C.G.R.; methodology, N.M.; software, No Software used; validation, N.M., G.U.N. and C.G.R.; formal analysis, N.M.; investigation, N.M.; resources, N.M.; data curation, N.M.; writing—original draft preparation, N.M.; writing—review and editing, N.M., G.U.N. and C.G.R.; visualization, N.M.; supervision, C.G.R.; project administration, N.M.; funding acquisition, C.G.R. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Conflicts of Interest

The authors declare no conflict of interest.

Abbreviations

The following abbreviations are used in this manuscript:
AELAlkaline Electrolyzer
AEM/AEMs Anion Exchange Membrane/Anion Exchange Membranes
CAPEX Capital Expenditure
CCS Carbon Capture and Storage
CO2Carbon Dioxide
COF/COFs Covalent-Organic Framework/Covalent-Organic Frameworks
CSP Concentrated Solar Power
EAPP East African Power Pool
EPC Engineering, Procurement and Construction
GHG Greenhouse Gas
H2 Hydrogen
HEM/HEMsHigh-Entropy Material/High-Entropy Materials
IRENAInternational Renewable Energy Agency
LCALife Cycle Assessment
LCOHLevelized Cost of Hydrogen
LOHC/LOHCsLiquid Organic Hydrogen Carrier/Liquid Organic Hydrogen Carriers
MOF/MOFs Metal–Organic Framework/Metal-Organic Frameworks
NDCs Nationally Determined Contributions
OECD Organization for Economic Co-operation and Development
O&M Operations and Maintenance
PEM Proton Exchange Membrane
PGM/PGMs Platinum Group Metal/Platinum Group Metals
PVPhotovoltaic
R&DResearch and Development
SAPPSouthern African Power Pool
SDG/SDG 7Sustainable Development Goal/Sustainable Development Goal 7
SMR Steam Methane Reforming
SOEC/SOECs Solid Oxide Electrolysis Cell/Cells
SSASub-Saharan Africa
USDUnited States Dollar
VRE Variable Renewable Energy
WACC Weighted Average Cost of Capital
SEFA Sustainable Energy Fund for Africa

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Figure 1. PRISMA2020 Diagram.
Figure 1. PRISMA2020 Diagram.
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Figure 2. Hybrid System Designs [12].
Figure 2. Hybrid System Designs [12].
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Figure 3. Current Levelized Cost of Hydrogen (LCOH) Comparison.
Figure 3. Current Levelized Cost of Hydrogen (LCOH) Comparison.
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Figure 4. Projection of Levelized Cost of Hydrogen Production Methods.
Figure 4. Projection of Levelized Cost of Hydrogen Production Methods.
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Figure 5. Environmental Impact of Hydrogen production Methods.
Figure 5. Environmental Impact of Hydrogen production Methods.
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Figure 6. Green Hydrogen Feasibility Indicators is SSA.
Figure 6. Green Hydrogen Feasibility Indicators is SSA.
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Figure 7. Green Hydrogen Development in leading African Countries.
Figure 7. Green Hydrogen Development in leading African Countries.
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Table 1. Comparative overview of hydrogen production technologies.
Table 1. Comparative overview of hydrogen production technologies.
TechnologyPrimary SourceCO2 Emissions (kg CO2/kg H2)LCOH (€/kg)MaturityOff-Grid SuitabilityKey Challenges
GreyNatural gas (SMR)9–121.0–1.8High (commercial, global)Very LowHigh emissions, fossil dependence
BlueNatural gas (SMR + CCS)2–4 (depends on CCS)2.0–2.5Moderate (pilot/commercial)LowMethane leakage, CCS permanence
GreenRenewables (electrolysis)≈0 (with renewables)3.5–6.0 (1.0–1.5 by 2050)Growing (demo & pilot plants)High (renewables integration)High cost, scarce PGMs, water demand
AquaPlasma pyrolysis/photonic water splitting≈0 (emerging R&D)High/not commercialLow (laboratory stage)Promising (future potential)Immature, scalability unproven
Table 2. Electrolyzer Technologies Comparative Characteristics [9,12,28].
Table 2. Electrolyzer Technologies Comparative Characteristics [9,12,28].
TechnologyEfficiency (%)Capital Cost (€/kW)Current Density (A/cm2)Dynamic ResponseMaterial RequirementsOff-Grid Suitability
Alkaline (AEL)55–65500–800<0.5SlowAbundant (Ni, Fe, Co)Low (poor flexibility)
PEM60–701000–1500>2.0FastHigh (Ir, Pt, Ti)High (excellent with VRE)
SOEC75–851200–20001.0–1.5ModerateHigh-temp ceramics, NiLow–Moderate (needs heat)
AEM55–65600–10000.5–1.0Moderate–FastNon-noble (Ni, Co, Fe)Promising (immature)
Table 3. Emerging Technologies application, Benefits, and challenges.
Table 3. Emerging Technologies application, Benefits, and challenges.
Material InnovationApplicationKey BenefitsChallenges
Ni, Fe, Co-based catalystsElectrolysis (OER, HER)Lower cost vs. PGM, good activityStability under high current density
Nanostructured catalystsElectrolysisHigh surface area, enhanced kineticsComplex synthesis, scalability
High-Entropy Materials (HEMs)Catalysis, electrodesDurability, resistance to degradationEarly-stage development
Hybrid compositesElectrodesSynergistic properties, improved efficiencyCost and reproducibility
AEMsElectrolysis membranesLower cost, reduced ohmic lossesChemical stability in alkaline media
Composite PEMsFuel cells, electrolysisCorrosion/crossover resistanceManufacturing complexity
Metal hydridesSolid-state storageHigh volumetric density, safetySlow kinetics, weight
Porous carbons (MOFs, COFs)StorageLightweight, tunable adsorptionLimited large-scale feasibility
Table 4. Comparative Review of hydrogen storage and transport methods for green hydrogen application in remote and off-grid regions.
Table 4. Comparative Review of hydrogen storage and transport methods for green hydrogen application in remote and off-grid regions.
Storage/Transport MethodEnergy Density (MJ/L)Efficiency (%)AdvantagesChallengesSuitability (Remote)
Compressed H2 (350–700 bar)5–8≈85Mature, simpleLow density, saferHigh (small scale)
Liquid H2 (LH2)8–1060–70High densityCryogenic loss, costlyLow
Metal Hydrides1–370–80Safe, compactHeavy, slow kineticsMedium (stationary)
LOHCs (e.g., toluene)6–765–75Liquid at ambient, safeEnergy-intensive releaseMedium
Ammonia as carrier12–1355–65Easy shipping, existing infraToxicity, conversion lossesLow–Medium
Pipelines–>90Cost-effective (large scale)High CAPEX, fixed routesLow (remote)
Table 5. Regional Factors Influencing Hydrogen Production Costs.
Table 5. Regional Factors Influencing Hydrogen Production Costs.
Region/CountryWater AvailabilityPrimary Renewable ResourcesKey ChallengesRelative LCOH (Levelized Cost of H2) Impact
Niger (Arid Interior)Very limited freshwaterHigh solar, limited windWater import/desalination, weak gridHigher costs due to water scarcity
Namibia (Arid Coastal)Limited freshwater, coastal accessExcellent solar & windDesalination costs, infrastructure gapsModerate, improving with export projects
Morocco (Coastal)Seawater available (desalination feasible)Strong solar & windDesalination energy demandLower costs due to renewables, moderate water costs
South Africa (Coastal & Inland)Mix of freshwater stress & coastal desalinationSolar, wind, coal infrastructureTransitioning from fossil fuels, water stress inlandModerate, improving with policy support
Hydropower-Reliant Nations (e.g., Ethiopia)High water availabilityHydropower, limited solarSeasonal variability, infrastructureVariable, depends on hydropower reliability
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Msweli, N.; Nnachi, G.U.; Richards, C.G. A Review of Green Hydrogen Technologies and Their Role in Enabling Sustainable Energy Access in Remote and Off-Grid Areas Within Sub-Saharan Africa. Energies 2025, 18, 5035. https://doi.org/10.3390/en18185035

AMA Style

Msweli N, Nnachi GU, Richards CG. A Review of Green Hydrogen Technologies and Their Role in Enabling Sustainable Energy Access in Remote and Off-Grid Areas Within Sub-Saharan Africa. Energies. 2025; 18(18):5035. https://doi.org/10.3390/en18185035

Chicago/Turabian Style

Msweli, Nkanyiso, Gideon Ude Nnachi, and Coneth Graham Richards. 2025. "A Review of Green Hydrogen Technologies and Their Role in Enabling Sustainable Energy Access in Remote and Off-Grid Areas Within Sub-Saharan Africa" Energies 18, no. 18: 5035. https://doi.org/10.3390/en18185035

APA Style

Msweli, N., Nnachi, G. U., & Richards, C. G. (2025). A Review of Green Hydrogen Technologies and Their Role in Enabling Sustainable Energy Access in Remote and Off-Grid Areas Within Sub-Saharan Africa. Energies, 18(18), 5035. https://doi.org/10.3390/en18185035

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