Off‐Grid Renewable Hydrogen Systems in Australia: A Multi‐Regional Techno‐Economic and Environmental Evaluations

NEOM City in Saudi Arabia is planned to be the first environmentally friendly city in the world that is powered by renewable energy sources minimizing CO2 emissions to reduce the effect of global warming according to Saudi Arabia’s Vision 2030. In recent years, Saudi Arabia has had a problem with water scarcity. The main factors affecting water security are unequal water distribution, wrong use of water resources and using bad or less efficient irrigation techniques. This paper is aimed to provide a detailed feasibility and techno-economic evaluation of using several scenarios of a stand-alone hybrid renewable energy system to satisfy the electrical energy needs for an environmentally friendly seawater desalination plant which feeds 150 m−3 day−1 of freshwater to 1000 people in NEOM City, Saudi Arabia. The first scenario is based on hybrid solar photovoltaic PV, fuel cells (FC) with a hydrogen storage system and batteries system (BS), while the second and third scenarios are based on hybrid PV/BS and PV/FC with a hydrogen storage system, respectively. HOMER® software was used to obtain the optimal configuration based on techno-economic analysis of each component of the hybrid renewable energy systems and an economic and environmental point of view based on the values of net present cost (NPC) and cost of energy (COE). Based on the obtained results, the best configuration is PV/FC/BS. The optimal size and related costs for the optimal size are 235 kW PV array, 30 kW FC, 144 batteries, 30 kW converter, 130 kW electrolyzer, and 25 kg hydrogen tank is considered the best option for powering a 150 m3 reverse osmosis (RO) desalination plant. The values of net present cost (NPC) and the cost of energy (COE) are $438,657 and $0.117/kWh, respectively. From the authors’ point view, the proposed system is one among the foremost environmentally friendly systems to provide electric energy to the seawater desalination plant, especially when connecting to the utility grid, because it is ready to reduce a large amount of greenhouse gas emissions due to using oil/nature gas in utility generation stations to reduce the effect of global warming.

This paper presents a techno-economic analysis of hybrid renewable energy systems to supply the electrical load requirements of the nursing home located in Istanbul, Turkey. The standalone hybrid renewable energy systems (Photovoltaic (PV)/wind/fuel cell/electrolyzer, PV/fuel cell/electrolyzer, and wind/fuel cell/electrolyzer, etc.) considered in the analysis were comprised of different combinations of PV panels, fuel cells, and wind turbines supplemented with hydrogen storage. In this study, the Hybrid Optimization of Multiple Energy Resources (HOMER) software is used as the assessment tool to determine the optimal configuration of hybrid renewable energy systems taking total net present cost and cost of energy into consideration. As a result, it is determined that the optimal system configuration of standalone wind/PV/fuel cell/electrolyzer hybrid renewable energy systems with the lowest total net present cost consists of 30 kW PV panel, 20 kW wind turbine, 20 kW fuel cell, 20 kW power converter, 50 kW electrolyzer, 20 kW rectifier, and 100 kg hydrogen tank. Besides, the net present cost and cost of energy of the optimum configuration are calculated to be $607,298 and $1.306/kWh, respectively. The system is considered as completely renewable. When wind speed and solar radiation values increase, then the cost of energy decrease about $0.979/kWh.

Analysis of the economic and technological viability of producing green hydrogen with renewable energy sources in a variety of climates to reduce CO2 emissions: A case study in Egypt

Design of a stand-alone energy hybrid system for a makeshift health care center: A case study

A sustainable future hydrogen economy hinges on the development of green hydrogen and the shift away from grey hydrogen, but this is highly reliant on reducing production costs, which are currently too high for green hydrogen to be competitive. This study predicts the cost trajectory of alkaline and proton exchange membrane (PEM) electrolyzers based on ongoing research and development (R&D), scale effects, and experiential learning, consequently influencing the levelized cost of hydrogen (LCOH) projections. Electrolyzer capital costs are estimated to drop to 88 USD/kW for alkaline and 60 USD/kW for PEM under an optimistic scenario by 2050, or 388 USD/kW and 286 USD/kW, respectively, under a pessimistic scenario, with PEM potentially dominating the market. Through a combination of declining electrolyzer costs and a levelized cost of electricity (LCOE), the global LCOH of green hydrogen is projected to fall below 5 USD/kgH2 for solar, onshore, and offshore wind energy sources under both scenarios by 2030. To facilitate a quicker transition, the implementation of financial strategies such as additional revenue streams, a hydrogen/carbon credit system, and an oxygen one (a minimum retail price of 2 USD/kgO2), and regulations such as a carbon tax (minimum 100 USD/tonCO2 for 40 USD/MWh electricity), and a contract-for-difference scheme could be pivotal. These initiatives would act as financial catalysts, accelerating the transition to a greener hydrogen economy.

Renewable energy development and hydrogen economy in MENA region: A review

Electrolytic hydrogen produced through renewable energy can help to decarbonize some hard-to-abate sectors, including heavy industry and long-haul transport. However, the higher levelized cost of green hydrogen, compared to grey hydrogen produced from fossil fuels, has limited its large-scale deployment and application. However, an optimized system configuration of a green hydrogen project, including choosing a suitable power generation technology considering the renewable resources, and its capacity ratio to electrolysers, could help to yield the maximum hydrogen production at the lowest cost. In this paper, an optimization model embedded with the function of production simulation is presented. Then, five different component combinations for a green hydrogen project are introduced, including photovoltaic (short as PV)+electrolyser, wind power (short as WP) + electrolyser, WP+electrolyser+ storage, PV+electrolyser+storage and PV+WP+electrolyser+ storage. For each combination, the influences of generation technology to electrolyser ratio and annual capacity factor on the levelized cost of hydrogen (short as LCOH) and the operation characteristics of the system are analyzed. At last, suggestions concerning system configuration for deploying green hydrogen projects in different regions of China are put forward.

Optimum sizing of hybrid renewable power systems for on-site hydrogen refuelling stations: Case studies from Türkiye and Spain

Green hydrogen (GH) is recognized as a fundamental pillar in shaping a sustainable global future. The process involves the hydrolysis of water with sustainable electrical sources. This paper presents a techno-economic assessment of hybrid renewable wind and solar power systems in Yanbu, Saudi Arabia, to provide clean energy to enhance carbon-natural petrochemical operations. The implementation of Energy Compensation Policies, such as Net Energy Metering or Net Energy Billing Mechanisms, has a substantial influence on the financial viability of GH Plant. The present research compared the impact of such a mechanism on the levelized cost of Energy (LCOE) and the Levelized cost of Hydrogen (LCOH). The study recommended the adoption of a Net Metering Mechanism as a highly efficient strategy to encourage private sector investment in renewable energy production in the Kingdom of Saudi Arabia (KSA). This approach was found to be effective, resulting in an accumulated electricity tariff of 26.5 $/MWh and a levelized cost of hydrogen (LCOH) of 1.65 $/kg.

The early development of blue hydrogen is often proposed to ‘kick-start’ a hydrogen economy however, the volatility of the cost of gas, different emission intensities of blue technological options, and projected cost reductions in electrolysers could lead to stranded assets. We develop a model to interrogate the dynamics of hydrogen supply and demand using different cost trajectories for green and blue hydrogen production, and under different carbon pricing scenarios. We find that the window of opportunity for blue hydrogen is mostly determined by how quickly green hydrogen costs reduce. We show that blue hydrogen assets deployed within the next three decades are likely to be significantly underutilised, unless the cost of green hydrogen remains at the high end of projections. This analysis implies that there is a substantial risk that investments in blue hydrogen will lead to stranded assets, which could occur without high-quality information and clear policies. • Blue hydrogen risks becoming obsolete due to rapid green hydrogen cost reductions. • High carbon pricing speeds retirement of emission-intensive blue hydrogen assets. • Policymakers should promote long-term green hydrogen investments through stable regulations.

Green hydrogen produced via water electrolysis is a key pillar of the European Union’s decarbonisation strategy for hard-to-abate sectors. However, its economic competitiveness remains highly uncertain in small, electricity-importing power systems characterised by volatile wholesale electricity prices. The study assesses the techno-economic viability of grid-connected green hydrogen production in Latvia under current and near-term electricity market conditions. A comparative analysis is conducted for alkaline water electrolysis (AWE), proton exchange membrane (PEM), anion exchange membrane (AEM), and solid oxide electrolysis (SOEC) using industry-standard performance parameters and European cost benchmarks for the 2023–2024 period. The levelized cost of hydrogen (LCOH) is calculated on an ex-plant basis using observed Latvian electricity prices for 2025, a uniform economic lifetime of 15 years, and a weighted average cost of capital of 10 %. Results indicate that electricity prices are the dominant cost driver, accounting for more than two-thirds of total hydrogen production costs under high-price conditions. At electricity prices around EUR 85/MWh, the LCOH ranges from approximately EUR 6.1–6.6/kg for AWE and PEM, exceeding the cost of conventional hydrogen production via steam methane reforming (SMR) and SMR with carbon capture and storage (CCS). Sensitivity analysis confirms a near-linear relationship between electricity prices and hydrogen costs, with a reduction of EUR 1/MWh lowering LCOH by approximately EUR 0.052/kg for low-temperature electrolysis technologies. Competitiveness thresholds are derived analytically: achieving an LCOH of EUR 5/kg requires electricity prices below approximately EUR 50/MWh, while an LCOH of EUR 4/kg requires prices below approximately EUR 32/MWh, excluding compression. Additional electricity demand for hydrogen compression further tightens these thresholds.

Feasibility studies of green hydrogen production using photovoltaic systems in Iran's southern coastal regions

In this study, a techno-economic feasibility analysis of a stand-alone hybrid renewable energy system (HRES) for a remote rural area of Chikmagalur district of Karnataka (India) has been presented. Load shifting-based demand-side management (DSM) has been implemented for Lead-Acid and Lithium-Ion batteries based HRES for evaluating the feasibility. The performance of the proposed system has been conducted with DSM and without DSM. From the results, it is found that Lithium-Ion battery-based HRES with DSM gives the optimal feasible solution for providing reliable power supply to the proposed un-electrified villages. The optimal Net present Cost (NPC) and Cost of Energy (COE) are found to be $467,644 and 0.106 $/kWh without DSM implementation. Whereas, the operating costs are $314,564 and 0.072 $/kWh respectively with DSM implementation. Based on the analysis, it is observed that the saving of NPC and COE is found to be $153,080 and 0.034 $/kWh, respectively.KeywordsHybrid renewable energy systemDemand-side managementLead-AcidLithium-IonHOMER

Investment decisions for offshore wind-to-hydrogen (W2H) projects are often framed as “better forecasts reduce uncertainty,” but it is less clear when higher-fidelity scenario modelling meaningfully changes a financing decision versus merely narrowing outcome ranges. We address this question using a decision-coupled evaluation that scores forecast skill on propagated economic distributions and links it directly to financeability metrics.Using 61 years of ERA5 wind data at 150 m hub height, we generate 1000 synthetic 23-year hourly wind scenarios per method and propagate them through a techno-economic model of a 375 MW offshore W2H project (development in 2024, operation in 2026-2050, base hydrogen price €8/kg, discount rate 7%). We compare three probabilistic scenario generators: historical bootstrapping, parametric Weibull fitting, and a calibrated probabilistic long short-term memory (LSTM) sequence model (used as a benchmark rather than architectural novelty).We evaluate (a) continuous ranked probability score (CRPS) of levelized cost of hydrogen (LCOH), net present value (NPV), and internal rate of return (IRR), (b) decision bandwidths W(Y) = P95(Y) – P5(Y), (c) threshold-crossing probabilities Pr(NPV>0) and Pr(IRR>10%), and (d) a local elasticity E(Y) = dW(Y)/dCRPS that maps marginal forecast skill to risk-band compression. Finally, we run a financing price sweep to identify the minimum hydrogen offtake price that achieves a 90% probability target for NPV > 0 and the joint target NPV > 0, IRR > 10%.Results show that improved scenario modelling can substantially reduce economic distribution error and compress risk bands: the LSTM lowers CRPS by 30% for LCOH and NPV and by 25% for IRR versus the best bootstrap/Weibull configurations. However, under base assumptions the financeability thresholds are nearly invariant across methods: the 90%-target required hydrogen price is €7.76-7.78/kg for Pr(NPV>0) and €9.16-9.18/kg for Pr(NPV>0 and IRR>10%), with cross-method spread below €0.02/kg indicates a threshold-saturated regime where better modelling mainly narrows uncertainty rather than shifting the decision boundary. Sensitivity analysis indicates decision value is highest in moderate-margin regimes (roughly €5.5-8/kg) and diminishes at high profitability where models converge.This work reframes “better scenarios” into an investment-relevant diagnostic: use elasticity and threshold behaviour to identify when modelling improvements will shift financeability versus only compress risk bands, supporting more defensible screening and policy design.

The EU Delegated Act establishes criteria for certifying electrolytic hydrogen as renewable. However, adjustments to these criteria are under review to balance hydrogen’s economic viability with its sustainability. This study employs a European integrated electricity and hydrogen system model to evaluate the climate and economic impacts of relaxing additionality and spatiotemporal correlation criteria by 2030. Scenarios range from unrestricted electrolysis flexibly operating at short-run marginal electricity prices to domestic and cross-border power purchase agreements (PPAs) with newly installed renewables, under hourly or annual temporal matching. Two perspectives are explored, both applying a ‘compete’ additionality framework where hydrogen production competes with direct electrification in a co-optimized system. The first analysis constrains the country-specific renewable buildout to National Energy and Climate Plans (NECPs) using ten-year network development plan’s (TYNDP 2024) National Trend trajectories. This reflects the practical difficulty of accelerating renewable expansion by 2030, even with green hydrogen mandates. Under this constraint, additionality with spatiotemporal correlation reduces attributional emissions (i.e. emissions from grid electricity use, attributed to hydrogen production) but raises power system emissions by ∼1 kgCO2/kgH2 compared to the unrestricted electrolysis scenario, as scarce new renewables are diverted to green hydrogen production, increasing fossil generation in the background electricity system. The second, exploratory perspective allows endogenous expansion beyond NECP targets to simulate policy-driven accelerated deployment, where building out green hydrogen, slightly reduces the additional power system emissions associated with hydrogen integration compared to unrestricted electrolysis. Moreover, although total system cost impacts remain modest, additionality with spatiotemporal criteria raises the levelized cost of hydrogen (LCOH) in both perspectives, with cross-country variation driven by short-run electricity prices. EU-averaged results show unrestricted electrolysis yields lower LCOH of €2–2.5/kgH2 (assuming NECPs are met), while stringent PPA-based scenarios increase it up to €7/kgH2. Easing temporal correlation in PPA-based scenarios slightly raises attributional emissions but lowers LCOH. However, additionality remains the dominant cost driver. Finally, the study underscores the need for tailored exemptions from additionality and spatiotemporal correlation criteria based on factors such as nuclear share, renewable targets, and marginal clean generation frequency to refine these requirements effectively.