Hydrogen Farms Baseline Economic Model

Electrolysers are the most capital-intensive component in hydrogen production systems due to their material complexity, engineering demands, and limited industrial scaling. High costs are driven by the use of expensive materials, such as platinum group metals in PEM electrolysers and corrosion-resistant components in alkaline types, as well as the lack of mass production, which results in expensive, customised large-scale units. In addition, electrolysers require a range of supporting systems, including power electronics, thermal management, and gas purification, further inflates capital costs. Efficiency requirements also increase expenses, as manufacturers invest in advanced materials and system controls to minimise energy losses, especially in electricity-constrained regions [29]. Factors That Could Drive Cost Reductions: Economies of Scale: As global hydrogen demand grows, larger production runs and standardised designs will lead to reduced per-unit costs. Gigawatt-scale projects planned in Europe, Asia, and MENA could catalyse this trend. Material Substitution and Catalyst Innovation: Research into alternative catalysts (e.g., non-platinum group metals), cheaper membranes, and advanced coatings could reduce costs without compromising performance. Manufacturing Automation: Automation in stack assembly, welding, and quality control could lower labour costs and improve consistency, particularly for PEM stacks. Integration and System Optimisation: Improvements in integrating electrolysers with renewable energy sources and better thermal/electrical management could reduce the need for oversized or redundant components, lowering both CAPEX and OPEX. Policy Support and Learning Curves: As with solar PV and wind turbines, policy incentives, learning by doing, and increased deployment will reduce costs through experience and innovation. Current projections suggest electrolyser costs could fall by 40–70% by 2030 under aggressive deployment scenarios.

9. Reasons for the High O&M Costs of PEM Compared to AWE

PEM electrolysers, while offering advanced performance features such as compact design and rapid response, incur higher operation and maintenance (O&M) costs than alkaline systems due to several interrelated factors. Their reliance on expensive, sensitive components, like platinum-group catalysts and polymer membranes, requires meticulous environmental control and more frequent part replacements. Unlike alkaline systems, PEM units demand ultra-pure deionised water, which adds the burden of maintaining water purification systems and monitoring water quality. Furthermore, their balance-of-plant components (e.g., power electronics, thermal control, and pressurisation) are more complex and require regular calibration and servicing. The shorter stack lifespan of PEM electrolysers, typically 40,000–60,000 h versus over 90,000 for alkaline, means more frequent and costly replacements over the project lifecycle [30]. Lastly, limited supply chain maturity and the need for specialised technical support, especially in emerging markets like Libya, further escalates service costs compared to the more established and widely supported alkaline technology. A detailed sensitivity analysis has already been conducted and is fully presented in our separate paper, titled “Techno-Economic Environmental Risk Analysis (TERA) in Hydrogen Farms”. This study specifically explores how variations in key parameters, such as electrolyser capital costs, electricity prices, electrolyser efficiency, and capacity factor, impact the overall project feasibility. The aim was to capture a comprehensive view of the economic uncertainties and risks associated with large-scale hydrogen deployment. By modelling 81 distinct scenarios, the TERA paper offers valuable insights into cost fluctuations. It identifies the most influential factors affecting long-term viability, thereby strengthening the robustness of our trillion-dollar cost estimates.

10. Total Expenditure Comparison Across Hydrogen Farms Scenarios

The comparison of the four hydrogen farm scenarios reveals clear cost differences depending on the type of electrolyser and the capacity of the turbines used, as shown in Figure 5. The Alkaline + 600 MW CCGT setup has a total cost of $1.2166 trillion, made up of $0.8156 trillion in capital investment and $0.401 trillion in operational and maintenance expenses. Switching to a larger 900 MW CCGT reduces the overall cost slightly to $1.2136 trillion, demonstrating how larger-scale turbines can lower costs through economies of scale. On the other hand, the PEM + 600 MW CCGT option is the most expensive, with total spending reaching $1.5214 trillion, mainly due to the higher costs of PEM equipment and maintenance. Upgrading this setup to 900 MW CCGTs reduces the total cost slightly to $1.519 trillion, again demonstrating how scaling up improves cost efficiency. In summary, while PEM technology provides advantages in terms of compact design and performance, it is noticeably more expensive than alkaline alternatives, and the benefits of scaling turbine capacity are evident across all configurations.

11. Comparative Visuals Illustrating Cost-Efficiency Trade-offs and Scaling Trends

Figure 6 illustrates the relationship between electrolyser efficiency and the total cost (CAPEX + O&M over 25 years) across four hydrogen farm configurations. Although PEM systems offer slightly higher efficiency (77%) than their alkaline counterparts (75%), they come with significantly higher total costs, approximately USD 1.52 trillion compared to around USD 1.21 trillion for alkaline systems. This trade-off highlights a critical decision-making factor: marginal gains in efficiency do not necessarily justify the steep increase in overall cost. The visual makes it evident that for contexts prioritising cost-effectiveness over compactness, such as Libya, alkaline systems are more economically viable despite their slightly lower efficiency. Figure 7 examines the response of total system costs to scaling from 600 MW to 900 MW of combined-cycle gas turbines (CCGTs) for both alkaline and PEM electrolyser technologies. The trend reveals a modest but consistent decrease in total cost with scale-up, demonstrating clear economies of scale. For alkaline systems, increasing turbine size reduces cost from USD 1.2166 to 1.2136 trillion, while PEM systems also show a slight cost reduction from USD 1.5214 to 1.519 trillion. This scaling insight is crucial for stakeholders seeking to minimise per-unit costs in large-scale deployments and confirms that larger systems offer enhanced financial efficiency regardless of technology type. Unlike previous techno-economic assessments that typically focus on static system modelling or high-level cost estimations, this study introduces a dynamic, modular framework specifically designed for ‘hydrogen farm’ configurations. It integrates plant-level scaling behaviours, site-specific load profiles, and adaptive infrastructure sizing—features that are often overlooked in earlier models. By incorporating parametric flexibility and aligning infrastructure with export contract timelines and renewable availability, this approach enables for more accurate optimisation of cost-to-output ratios across different deployment scales and regions.

12. Parametric Sensitivity Matrix (PSM)

A Parametric Sensitivity Matrix is a powerful extension to the scenario-based TERA approach, designed to systematically quantify how changes in each input parameter, such as CAPEX, efficiency, electricity cost, and capacity factor, affect the levelized cost of hydrogen (LCOH). This matrix format offers a comparative, at-a-glance overview of parameter weightings under different technology configurations (AWE vs. PEM), allowing researchers and investors to prioritise factors most critical to cost control. For instance, our study already identifies CAPEX and electrolyser efficiency as the dominant cost drivers. The PSM formally captures this influence numerically, as shown in the Table 11. By doing so, the methodology introduces a transparent, reproducible, and scalable evaluation tool for hydrogen system modelling—something rarely integrated into prior techno-economic assessments focused solely on point-based results or non-quantified sensitivities. Moreover, this structure supports adaptation to other regional contexts by updating the parameter ranges and weights, enhancing transferability.

13. Implications for Decision-Makers

The comparative analysis between alkaline electrolyser farms and PEM electrolyser farms provides key insights for energy sector decision-makers. This knowledge supports the adoption of diversified energy strategies, enabling a balanced approach that considers the advantages and limitations of each technology. Combining both AEW and PEM systems in hydrogen production enhances the overall resilience and reliability of hydrogen-based energy generation [31]. Recognising the technological maturity and innovation levels of hydrogen systems is essential for decision-makers to develop effective adoption strategies. Mature technologies, such as alkaline and PEM electrolysers, provide reliable, well-established solutions. This understanding supports risk mitigation by promoting diversification, reducing dependence on a single hydrogen source, and aligning energy strategies with long-term sustainability objectives [32]. This report further elucidates the potential avenues for economic development, wherein hydrogen farms exhibit significant promise for substantial local economic advancement and the generation of employment opportunities [33]. Decision-makers can amalgamate the energy strategy with regional economic imperatives, consequently facilitating the generation of employment opportunities and the advancement of community development. The process of financial planning is made more straightforward as insights into initial capital expenditures and recurring operational costs for each model enable decision-makers to allocate resources with greater efficiency. The research outcomes offer valuable insights into renewable energy sources characterised by diminished environmental repercussions for individuals engaged in decision-making processes aimed at mitigating greenhouse gas emissions. Policymakers may leverage this empirical data to formulate evidence-based energy policies that advocate for the judicious integration of diverse renewable energy sources. Regulatory frameworks have the potential to encourage the adoption of technologies that align with overarching sustainability objectives. The adaptability and expandability of each model are accentuated, enabling decision-makers to effectively respond to fluctuating hydrogen production requirements and administer its distribution according to regional demands or for export purposes. The involvement of the community is of paramount importance, and we underscore the imperative of tackling apprehensions regarding visual and auditory repercussions to foster robust relationships with the local populace. In conclusion, policymakers have the capacity to render enlightened decisions by evaluating the distinct ramifications associated with each hydrogen generation framework. This examination lays the groundwork for the development of holistic and robust methodological strategies that tackle environmental, economic, and technological aspects, thereby guaranteeing a sustainable and effective energy future.

14. Discussion

In this hydrogen farm economic model, land acquisition costs were intentionally excluded based on the assumption that development would occur on publicly owned land. This is particularly relevant to Libya, where vast areas of uninhabited desert, largely state-owned, are readily accessible for such infrastructure projects. While this assumption aligns well with Libyan conditions, it is critical to recognise how overlooking land costs can significantly distort economic viability assessments when applying the model to other global regions. In countries with dense populations, competitive land markets, or fragmented ownership structures, such as those found in Western Europe, Japan, or urban parts of China and India, land acquisition can be a major cost driver. Research shows that land-related expenses, including purchase or lease agreements, legal fees, environmental offsets, and compensation for displaced stakeholders, can constitute up to 10–20% of total capital expenditures (CAPEX) in renewable energy projects [34,35]. Moreover, land acquisition challenges, such as disputes, delays in permitting, or opposition from local communities, can lead to significant time and budget overruns, undermining project timelines and investor confidence. Such risks are often underappreciated in models that assume free or easily available land. Thus, while Libya offers a unique strategic advantage by minimising land-related barriers, it’s crucial to explicitly state that this is a context-specific benefit and may not generalise to other regions. 14.1. Justification for Scale and Key Assumptions To justify the large-scale deployment of electrolysers (510–519 GW), our model is grounded in Libya’s 2020 national energy export data, which quantified the total energy content of oil exports in petajoules. This figure was then converted into an equivalent hydrogen energy output, considering electrolyser efficiency (75% for alkaline and 77% for PEM), which directly led to the required electrolyser capacities. Additionally, a 20% capacity factor was used, reflecting expected performance in hybrid solar-wind conditions typical of North African deserts. The model assumes a 25-year lifespan with an O&M cost escalation of 2–3% annually, consistent with IEA standards; however, no further inflation adjustment was applied to capital costs. 14.2. Expanded Sustainability Assessment for Hydrogen Farms 14.2.1. Socio-Economic Impacts beyond General Employment Large-scale hydrogen infrastructure can generate both direct and indirect jobs across various sectors, including construction, operations, maintenance, and associated supply chains. For example, a recent analysis found that hydrogen investments in developing countries can create up to 30,000 jobs per gigawatt of electrolyser capacity over the plant’s life cycle [33]. However, specialised hydrogen technologies may create a mismatch between the labor needs and the existing local workforce’s skills. If unaddressed, this could exclude local populations from economic benefits. Bridging this gap would require significant investment in workforce training programs and technical education, particularly in rural or underdeveloped regions such as Libya’s desert areas. 14.2.2. Community-Level Benefits and Risks Hydrogen farms can contribute to local development by improving infrastructure (e.g., roads, power lines) and creating service demand in adjacent towns. But there are potential drawbacks, especially if community concerns about land use, noise, and safety are not adequately addressed. Lessons from Kenya’s Kipeto Wind Project highlight that successful land-intensive energy projects must be paired with robust community engagement strategies and fair compensation to avoid backlash or delays [35]. 14.2.3. Skills Gap and Educational Requirements Hydrogen energy projects rely on engineers, system operators, and safety experts, who are often in short supply in many developing countries. Without targeted educational policies and industrial partnerships, the region could become overly reliant on foreign labor and technology providers, therby undermining long-term self-reliance. This challenge was echoed in Southeast Asian projects where land access was easier than securing skilled labor and ensuring technology transfer [34]. 14.3. Addressing Environmental Challenges in Hydrogen Production While hydrogen is often celebrated as a clean energy carrier, its production isn’t without environmental trade-offs. Key concerns include water consumption, land use, and the generation of waste byproducts. To ensure hydrogen systems are truly sustainable, especially in regions with limited natural resources, strategic mitigation approaches are essential. 14.3.1. Tackling Water Use in Electrolysis Producing hydrogen through electrolysis consumes a substantial amount of water, about 9 L for every kilogram of hydrogen produced. In water-scarce regions like North Africa and the Middle East, this poses a significant challenge. One promising solution is substituting freshwater with treated wastewater or seawater. Technologies like reverse osmosis and advanced membrane systems make this feasible by purifying non-potable water for use in electrolysis. Some innovative studies, such as supercritical water gasification, have even demonstrated the ability to convert wastewater sludge into hydrogen, addressing two key issues simultaneouslywater scarcity and waste management [36]. 14.3.2. Turning Waste into Feedstock Hydrogen production doesn’t always have to rely on virgin materials or land-intensive crops. An increasingly viable pathway is converting existing waste, such as municipal solid waste (MSW), agricultural residues, or old tyres, into hydrogen. This approach not only reduces land pressure but also addresses waste disposal challenges. For instance, pyrolysis-gasification of waste tyres has shown high hydrogen yields while diverting harmful materials from landfills. Multi-output systems that convert MSW into hydrogen while generating electricity or heat offer both environmental and energy efficiency benefits [37]. 14.3.3. Managing Byproducts Sustainably Hydrogen production processes, particularly those involving electrolysis or biomass conversion, can generate solid and chemical residues. Without proper disposal, these byproducts could undermine the environmental benefits of hydrogen itself. A more sustainable approach involves integrating circular economy principles, finding secondary uses for byproducts rather than discarding them. For example, biochar produced from gasification can be used to improve soil health. Likewise, advanced catalytic systems in aqueous-phase reforming processes can help minimise harmful emissions while efficiently managing residual compounds [38]. 14.3.4. Rethinking Land Use Establishing hydrogen farms at scale can have a noticeable footprint, potentially encroaching on farmland or natural habitats. To mitigate this impact, project developers are increasingly exploring co-location strategies, installing electrolysers alongside solar farms or on rooftops, and making use of underutilised or contaminated land (brownfields). Offshore and urban hydrogen systems, while still emerging, offer high-density alternatives that dramatically reduce the land requirements of traditional installations. Life cycle assessments support these approaches, highlighting their role in preserving valuable land resources while supporting clean energy goals [39]. 14.4. Realism, Financing, and Timeline Analysis The proposed hydrogen farm in Libya, with a projected capital cost nearing USD a trillion, raise critical questions about its practical feasibility within a single national economy. While the ambition aligns with global decarbonisation goals, implementing such a vast infrastructure project demands a deeper examination of realism, financing, and timelines. Here is an evidence-based exploration of these issues:   14.4.1. Practical Implementation in Libya Implementing a hydrogen farm of this scale would require a national effort equivalent to several times Libya’s annual GDP. Even under optimistic conditions, such projects are typically phased across decades. For example, global energy megaprojects like the Noor Ouarzazate Solar Complex in Morocco took over 10 years to develop, and that project cost less than USD 10 billion. According to Mohamadi (2021), successful project execution in developing countries often depends on strong public-private coordination, robust legal frameworks, and reliable institutions for project oversight [40]. 14.4.2. Financing Mechanisms for Trillion-Dollar Hydrogen Projects Given the scale, Libya cannot fund the project solely through public budgets or sovereign debt alone. However, several mechanisms exist to attract international investment

Project Finance and Public-Private Partnerships (PPP)

Project finance enables non-recourse funding, where the project’s revenue stream is used to repay lenders. This model isolates financial risk and is especially useful for energy projects. Mohamadi (2021) notes that project finance is the most common form used in renewable energy infrastructure due to its ability to handle large-scale capital and long-term returns. PPP models, especially Build-Operate-Transfer (BOT) and Public-Private Partnerships, are already being used for infrastructure across Africa, with mixed success. Bai & Zhang (2020) found that PPPs are especially effective for hydrogen infrastructure in capital-constrained countries due to their ability to share risks across stakeholders [41].

Development Banks and Blended Finance

Institutions such as the World Bank, African Development Bank, and International Finance Corporation (IFC) can provide concessional loans, technical support, and risk guarantees. Bond (1994) emphasised that IFC-financed infrastructure projects have grown rapidly in developing nations and can unlock significant private capital with proper risk mitigation [42]. Project finance and public-private partnerships (PPPs) offer a practical solution for Libya by attracting private investment while limiting financial risk to the government. This approach allows large-scale hydrogen projects to move forward without placing pressure on national budgets, making it a strong fit for Libya’s economic situation. 14.4.3. Timeline for Implementation Hydrogen megaprojects typically unfold over 15–30 years, depending on institutional readiness, financing, and infrastructure maturity. A phased approach, starting with pilot projects (1–5 GW scale), followed by progressive expansions, would be more realistic and help attract incremental investment while building local capacity. Case in point: Saudi Arabia’s NEOM green hydrogen project, targeting 4 GW by 2030, has committed USD 8.4 billion in its first stage alone and involves a partnership between ACWA Power, Air Products, and NEOM itself, a clear example of gradual, high-stakes investment pacing [43]. 14.5. Comparative Analysis of Hydrogen Farms vs. Other Low-Carbon Export Pathways for Libya Libya’s geographic and solar potential positions it as a promising exporter of clean energy. However, to support strategic policymaking, it’s important to weigh the case for large-scale hydrogen farms against other non-carbon energy export options, such as direct renewable electricity export, and emerging technologies like helium-based closed-cycle gas turbines. 14.5.1. Economic Viability Hydrogen Farms: Hydrogen production (especially green hydrogen via electrolysis) is capital-intensive. Projects often require USD billions in up-front investment due to the cost of electrolysers, renewable generation, water treatment, storage, and transportation infrastructure. However, hydrogen is a flexible and globally tradable commodity. Once liquefied or converted into ammonia, it can be exported via ship to distant markets. The global hydrogen trade is expected to scale significantly by 2030, particularly driven by demand from Europe and East Asia [44]. Direct Renewable Electricity Export: Electricity export, particularly via high-voltage direct current (HVDC) cables, is less capital-intensive and far more energy-efficient. There are fewer conversion losses compared to hydrogen (transmission losses can be <3% per 1000 km, versus ~30–40% energy loss in hydrogen conversion and logistics) [45]. However, this pathway requires stable regional political relations and compatible grid infrastructure—challenges that Libya may face with its neighbours. Helium Closed-Cycle Gas Turbines (He-CCGT): These remain largely at experimental or pilot scale, especially in the context of renewable integration. While they offer theoretical thermodynamic efficiency and low emissions, they are not yet commercially viable for energy export, and there’s limited market demand for helium-based power exports [46]. 14.5.2. Strategic Fit for Libya Hydrogen Farms: Hydrogen can be produced in remote desert areas, independent of the national grid, and exported via ports, ideal for Libya’s vast, underutilised land and weak internal grid. It also supports diversification of the economy beyond oil. However, hydrogen production requires large volumes of water, which necessitates the use of seawater and the incorporation of desalination [47]. Libya’s Mediterranean coastline is approximately 1770 km long, the longest in North Africa. Electricity Export: This route might be faster to deploy if regional interconnectors are developed (e.g., to Egypt or Southern Europe via Tunisia). However, it relies on geopolitical stability, grid harmonisation, and Libya’s ability to stabilise and modernise its domestic transmission systems. Without such upgrades, Libya may struggle to generate surplus electricity for export [48]. Helium-Based Technologies: Currently, these technologies are better suited for internal efficiency improvements or niche applications (e.g., space cooling or high-efficiency nuclear) rather than national-scale exports. Their strategic export role for Libya remains minimal for now [49]. 14.6. Preliminary Profitability Considerations and Future Financial Outlook To enhance the economic depth of the techno-economic environmental risk analysis (TERA), we recognise the value of evaluating profitability metrics such as revenue, NPV, and IRR. Although the primary emphasis in this study was on CAPEX and long-term O&M costs, a supplementary profitability perspective was also considered using the hydrogen output capacity derived from installed electrolysers and paired CCGT infrastructure. Based on international hydrogen market trends, export prices ranging from $3 to $6 per kg can be reasonably applied. When cross-referenced with electrolyser production capacity and expected availability (capacity factor), the model estimates annual hydrogen revenues that can reach tens of billions USD under favourable market conditions. While this initial study does not yet calculate IRR or NPV in detail, the cost sheets already incorporate a 25-year operational lifespan and factor in escalating O&M expenses. Future iterations of this model will integrate projected hydrogen selling prices, discount rates, and inflation assumptions to provide a comprehensive financial outlook and enabling global policymakers to assess market competitiveness and long-term profitability with greater confidence.

15. Conclusions

This study presents a thorough economic evaluation of large-scale hydrogen farms utilising two primary production technologies: alkaline electrolysers and proton exchange membrane (PEM) electrolysers, each assessed in conjunction with 600 MW and 900 MW combined-cycle gas turbine (CCGT) systems. The analysis provides critical insights into capital and operational costs, revealing that although PEM-based farms demand higher upfront investment, they offer improved land-use efficiency. In contrast, alkaline systems present lower capital requirements, especially at larger scales, illustrating the benefits of economies of scale. All scenarios incorporate essential infrastructure, such as hydrogen storage and comprehensive safety systems, resulting in a realistic economic model designed for a 25-year operational period. The framework addresses both immediate and long-term financial needs, equipping decision-makers with practical benchmarks for investment planning and infrastructure development. While land acquisition costs were excluded, assuming access to public land, this variable could notably affect the feasibility of similar projects in other regions. The results are particularly applicable to oil-exporting nations like Libya, where shifting to low-carbon energy exports can contribute to climate goals, diversify the economy, and enhance energy security. The use of established technologies, such as alkaline and PEM electrolysers further supports system stability and reduces reliance on a single solution through technological diversity. This research highlights significant differences between the two technologies in terms of scale and economic performance. PEM electrolysers, while technologically advanced and space-efficient, come with a much higher price tag, both for setup and ongoing maintenance. This makes them more appropriate for areas where space is scarce, but funding is more flexible. In contrast, alkaline systems are more financially accessible and show clear economic advantages as project size increases. The 900 MW alkaline configuration, for instance, becomes slightly more cost-effective per megawatt than the 600 MW option, demonstrating how scaling can drive down costs. For a country like Libya, with abundant land and tighter budget constraints, this positions alkaline technology as a more practical solution. These conclusions provide a valuable foundation for decision-makers aiming to match hydrogen production strategies with national development priorities and available resources. In conclusion, this research offers a strong foundation for strategic decision-making in the clean energy sector and highlights the viability of hydrogen as a scalable, sustainable energy solution. Future work should incorporate real-world cost factors and adapt to evolving market conditions to improve the relevance and effectiveness of these models globally. The next phase of this research involves conducting a sensitivity analysis as outlined in the paper titled “Techno-Economic Environmental Risk Analysis in Hydrogen Farms” (TERA). This analysis is essential for testing the robustness of the findings, identifying the most influential cost drivers, and equipping decision-makers with a more nuanced understanding of the investment risks associated with large-scale hydrogen projects. It is also important to note that the cumulative cost method used in the baseline study, where projected operation and maintenance (O&M) costs over 25 years were aggregated with capital expenditure, served as a broad techno-economic benchmarking approach. However, a more refined and widely accepted method, the Levelized Cost of Hydrogen (LCOH), was later applied in the follow-up TERA study. In that work, future costs were discounted and calculated on a per unit basis of hydrogen output, enabling a clearer assessment of financial viability and facilitating direct comparisons with global hydrogen benchmarks. This progression allows for a more comprehensive evaluation of the economic performance and competitiveness of hydrogen production systems.