Analyzing the levelized cost of hydrogen in refueling stations with on-site hydrogen production via water electrolysis in the Italian scenario

Hydrogen refueling infrastructures with on-site production from renewable sources are an interesting solution for assuring green hydrogen with zero CO₂ emissions. The main problem of these stations development is the hydrogen cost that depends on both the plant size (hydrogen production capacity) and on the renewable source.In this study, a techno-economic assessment of on-site hydrogen refueling stations (HRS), based on grid-connected PV plants integrated with electrolysis units, has been performed. Different plant configurations, in terms of hydrogen production capacity (50 kg/day, 100 kg/day, 200 kg/day) and the electricity mix (different sharing of electricity supply between the grid and the PV plant), have been analyzed in terms of electric energy demands and costs.The study has been performed by considering the Italian scenario in terms of economic streams (i.e. electricity prices) and solar irradiation conditions.The levelized cost of hydrogen (LCOH), that is the more important indicator among the economic evaluation indexes, has been calculated for all configurations by estimating the investment costs, the operational and maintenance costs and the replacement costs.Results highlighted that the investment costs increase proportionally as the electricity mix changes from Full Grid operation (100% Grid) to Low Grid supply (25% Grid) and as the hydrogen production capacity grows, because of the increasing in the sizes of the PV plant and the HRS units. The operational and maintenance costs are the main contributor to the LCOH due to the annual cost of the electricity purchased from the grid.The calculated LCOH values range from 9.29 €/kg (200 kg/day, 50% Grid) to 12.48 €/kg (50 kg/day, 100% Grid).     

Parameter study for dimensioning of a PV optimized hydrogen supply plant

Green hydrogen produced from intermittent renewable energy sources is a key component on the way to a carbon neutral planet. In order to achieve the most sustainable, efficient and cost-effective solutions, it is necessary to match the dimensioning of the renewable energy source, the capacity of the hydrogen production and the size of the hydrogen storage to the hydrogen demand of the application.For optimized dimensioning of a PV powered hydrogen production system, fulfilling a specific hydrogen demand, a detailed plant simulation model has been developed. In this study the model was used to conduct a parameter study to optimize a plant that should serve 5 hydrogen fuel cell buses with a daily hydrogen demand of 90 kg overall with photovoltaics (PV) as renewable energy source. Furthermore, the influence of the parameters PV system size, electrolyser capacity and hydrogen storage size on the hydrogen production costs and other key indicators is investigated. The plant primarily uses the PV produced energy but can also use grid energy for production.The results show that the most cost-efficient design primarily depends on the grid electricity price that is available to supplement the PV system if necessary. Higher grid electricity prices make it economically sensible to invest into higher hydrogen production and storage capacity. For a grid electricity price of 200 €/MWh the most cost-efficient design was found to be a plant with a 2000 kWp PV system, an electrolyser with 360 kW capacity and a hydrogen storage of 575 kg.     

Design and evaluation of hydrogen electricity reconversion pathways in national energy systems using spatially and temporally resolved energy system optimization

For this study, a spatially and temporally resolved optimization model was used to investigate and economically evaluate pathways for using surplus electricity to cover positive residual loads by means of different technologies to reconvert hydrogen into electricity. The associated technology pathways consist of electrolyzers, salt caverns, hydrogen pipelines, power cables, and various technologies for reconversion into electricity. The investigations were conducted based on an energy scenario for 2050 in which surplus electricity from northern Germany is available to cover the electricity grid load in the federal state of North Rhine-Westphalia (NRW).A key finding of the pathway analysis is that NRW's electricity demand can be covered entirely by renewable energy sources in this scenario, which involves CO₂ savings of 44.4 million tons of CO₂/a in comparison to the positive residual load being covered from a conventional power plant fleet. The pathway involving CCGT (combined cycle gas turbines) as hydrogen reconversion option was identified as being the most cost effective (total investment: € 43.1 billion, electricity generation costs of reconversion: € 176/MWh).Large-scale hydrogen storage and reconversion as well as the use of the hydrogen infrastructure built for this purpose can make a meaningful contribution to the expansion of the electricity grid. However, for reasons of efficiency, substituting the electricity grid expansion entirely with hydrogen reconversion systems does not make sense from an economic standpoint. Furthermore, the hydrogen reconversion pathways evaluated, including large-scale storage, significantly contribute to the security of the energy supply and to secured power generation capacities.     

Techno-economic feasibility of fleets of far offshore hydrogen-producing wind energy converters

Innovative solutions need to be developed for harvesting wind energy far offshore. They necessarily involve on-board energy storage because grid-connection would be prohibitively expensive. Hydrogen is one of the most promising solutions. However, it is well-known that it is challenging to store and transport hydrogen which may have a critical impact on the delivered hydrogen cost.In this paper, it is shown that there are vast areas far offshore where wind power is both characterized by high winds and limited seasonal variations. Capturing a fraction of this energy could provide enough energy to cover the forecast global energy demand for 2050. Thus, scenarios are proposed for the exploitation of this resource by fleets of hydrogen-producing wind energy converters sailing autonomously. The scenarios include transportation and distribution of the produced hydrogen.The delivered hydrogen cost is estimated for the various scenarios in the short term and in the longer term. Cost estimates are derived using technical and economic data available in the literature and assumptions for the cost of electricity available on-board the wind energy converters. In the shorter term, delivered cost estimates are in the range 7.1–9.4 €/kg depending on the scenario and the delivery distance. They are based on the assumption of on-board electricity cost at 0.08€/kWh. In the longer term, assuming an on-board electricity cost at 0.04€.kWh, the cost estimates could reduce to 3.5 to 5.7 €/kg which would make the hydrogen competitive on several hydrogen markets without any support mechanism. For the hydrogen to be competitive on all hydrogen markets including the ones with the highest GHG emissions, a carbon tax of approximately 200 €/kg would be required.     

Fuel cell electric vehicle as a power plant: Fully renewable integrated transport and energy system design and analysis for smart city areas

Reliable and affordable future zero emission power, heat and transport systems require efficient and versatile energy storage and distribution systems. This paper answers the question whether for city areas, solar and wind electricity together with fuel cell electric vehicles as energy generators and distributors and hydrogen as energy carrier, can provide a 100% renewable, reliable and cost effective energy system, for power, heat, and transport. A smart city area is designed and dimensioned based on European statistics. Technological and cost data is collected of all system components, using existing technologies and well-documented projections, for a Near Future and Mid Century scenario. An energy balance and cost analysis is performed. The smart city area can be balanced requiring 20% of the car fleet to be fuel cell vehicles in a Mid Century scenario. The system levelized cost in the Mid Century scenario is 0.09 €/kWh for electricity, 2.4 €/kg for hydrogen and specific energy cost for passenger cars is 0.02 €/km. These results compare favorably with other studies describing fully renewable power, heat and transport systems.     

Centralized and decentralized electrolysis-based hydrogen supply systems for road transportation – A modeling study of current and future costs

This work compares the costs of three electrolysis-based hydrogen supply systems for heavy road transportation: a decentralized, off-grid system for hydrogen production from wind and solar power (Dec-Sa); a decentralized system connected to the electricity grid (Dec-Gc); and a centralized grid-connected electrolyzer with hydrogen transported to refueling stations (Cen-Gc). A cost-minimizing optimization model was developed in which the hydrogen production is designed to meet the demand at refueling stations at the lowest total cost for two timeframes: one with current electricity prices and one with estimated future prices. The results show that: For most of the studied geographical regions, Dec-Gc gives the lowest costs of hydrogen delivery (2.2–3.3€/kgH₂), while Dec-Sa entails higher hydrogen production costs (2.5–6.7€/kgH₂). In addition, the centralized system (Cen-Gc) involves lower costs for production and storage than the grid-connected decentralized system (Dec-Gc), although the additional costs for hydrogen transport increase the total cost (3.5–4.8€/kgH₂).     

Advanced optimal planning for microgrid technologies including hydrogen and mobility at a real microgrid testbed

This paper investigates the optimal planning of microgrids including the hydrogen energy system through mixed-integer linear programming model. A real case study is analyzed by extending the only microgrid lab facility in Austria. The case study considers the hydrogen production via electrolysis, seasonal storage and fueling station for meeting the hydrogen fuel demand of fuel cell vehicles, busses and trucks. The optimization is performed relative to two different reference cases which satisfy the mobility demand by diesel fuel and utility electricity based hydrogen fuel production respectively. The key results indicate that the low emission hydrogen mobility framework is achieved by high share of renewable energy sources and seasonal hydrogen storage in the microgrid. The investment optimization scenarios provide at least 66% and at most 99% carbon emission savings at increased costs of 30% and 100% respectively relative to the costs of the diesel reference case (current situation).     

Techno-economic evaluation of two hydrogen supply options to southern Germany: On-site production and import from Portugal

Hydrogen production through electrolysis using renewable electricity is considered a major pathway and component for a sustainable energy system of the future. For this production pathway, a high renewable energy potential, especially in solar energy, is crucial. Countries like Germany with a high energy demand and low solar potential strongly depend on hydrogen import. In the present work, a case study with two alternative hydrogen supply options is conducted to evaluate the economic viability of solar hydrogen delivered to a hydrogen pipeline in Stuttgart, Germany. For both options, hydrogen is generated through an 8 MW alkaline electrolyser, solar powered and supported by grid-based electricity to meet the required load. The first option is based on a hydrogen production system that is positioned in Sines, Portugal, an area with high global radiation and proximity to a deep sea port. The hydrogen is processed by liquefaction and transported to Stuttgart by tanker ship via Hamburg and by truck. The second supply option uses an on-site hydrogen production system in Stuttgart.The work shows that the production costs in Sines with 2.09 €/kgH₂ (prices in €₂₀₂₁) are, as expected, significantly lower than in Stuttgart with 3.24 €/kgH₂. However, this price difference of 1.15 €/kgH₂ for hydrogen production drops to a marginal difference of 0.13 €/kgH₂ when considering the whole value chain to the delivery point in Stuttgart. If the waste heat from electrolysis is used in a district heating system in Stuttgart, the price difference is down to 0.03 €/kgH₂. The first supply option is dominated by costs for processing, especially liquefaction. These costs would need to be reduced to fully exploit the cost advantage of solar hydrogen production in Portugal. Also, a fundamental switch to pipeline transport of gaseous hydrogen should be considered. Both investigated hydrogen supply options show the potential to provide the pipeline in Stuttgart with hydrogen at lower costs than by using the alternative technology of steam reforming of natural gas.     

A flexible techno-economic analysis tool for regional hydrogen hubs – A case study for Ireland

The increasing urgency with which climate change must be addressed has led to an unprecedented level of interest in hydrogen as a clean energy carrier. Much of the analysis of hydrogen until this point has focused predominantly on hydrogen production. This paper aims to address this by developing a flexible techno-economic analysis (TEA) tool that can be used to evaluate the potential of future scenarios where hydrogen is produced, stored, and distributed within a region. The tool takes a full year of hourly data for renewables availability and dispatch down (the sum of curtailment and constraint), wholesale electricity market prices, and hydrogen demand, as well as other user-defined inputs, and sizes electrolyser capacity in order to minimise cost. The model is applied to a number of case studies on the island of Ireland, which includes Ireland and Northern Ireland. For the scenarios analysed, the overall LCOH ranges from €2.75–3.95/kgH₂. Higher costs for scenarios without access to geological storage indicate the importance of cost-effective storage to allow flexible hydrogen production to reduce electricity costs whilst consistently meeting a set demand.     

Techno-economic assessment of renewable hydrogen production and the influence of grid participation

Large-scale hydrogen production facilities will be required to supply the chemical energy demand of certain industries in the future. The case for such production plants based on individual adapted PV and wind farms has been addressed in several studies. However, most studies focus on an island solution of the evaluated plant and therefore, do not allow grid assistance which significantly reduce the installed capacity of the corresponding units. To address this issue, we developed a tool with a linear programming approach to evaluate any location around the world for its renewable hydrogen production costs and the influence on the plant layout depending on its interaction with the grid. A detailed techno-economic evaluation has been performed for five locations where hydrogen production costs in the range of 4–6 €₂₀₂₀/kg have been retrieved. Furthermore, it is shown that with perspective cost data the costs can further be reduced to 2.50 €₂₀₂₀/kg.     

Development of a viability assessment model for hydrogen production from dedicated offshore wind farms

Dedicated offshore wind farms for hydrogen production are a promising option to unlock the full potential of offshore wind energy, attain decarbonisation and energy security targets in electricity and other sectors, and cope with grid expansion constraints. Current knowledge on these systems is limited, particularly the economic aspects. Therefore, a new, integrated and analytical model for viability assessment of hydrogen production from dedicated offshore wind farms is developed in this paper. This includes the formulae for calculating wind power output, electrolysis plant size, and hydrogen production from time-varying wind speed. All the costs are projected to a specified time using both Discounted Payback (DPB) and Net Present Value (NPV) to consider the value of capital over time. A case study considers a hypothetical wind farm of 101.3 MW situated in a potential offshore wind development pipeline off the East Coast of Ireland. All the costs of the wind farm and the electrolysis plant are for 2030, based on reference costs in the literature. Proton exchange membrane electrolysers and underground storage of hydrogen are used. The analysis shows that the DPB and NPV flows for several scenarios of storage are in good agreement and that the viability model performs well. The offshore wind farm – hydrogen production system is found to be profitable in 2030 at a hydrogen price of €5/kg and underground storage capacities ranging from 2 days to 45 days of hydrogen production. The model is helpful for rapid assessment or optimisation of both economics and feasibility of dedicated offshore wind farm – hydrogen production systems.     

Value of hydro power flexibility for hydrogen production in constrained transmission grids

The cost of large scale hydrogen production from electrolysis is dominated by the cost of electricity, representing 77–89% of the total costs. The integration of low-cost renewable energy is thus essential to affordable and clean hydrogen production from electrolysis. Flexible operation of electrolysis and hydro power can facilitate integration of remote energy resources by providing the flexibility that is needed in systems with large amounts of variable renewable energy. The flexibility from hydro power is limited by the physical complexities of the river systems and ecological concerns which makes the flexibility not easily quantifiable. In this work we investigate how different levels of flexibility from hydro power affects the cost of hydrogen production.We develop a two-stage stochastic model in a rolling horizon framework that enables us to consider the uncertainty in wind power production, energy storage and the structure of the energy market when simulating power system operation. This model is used for studying hydrogen production from electrolysis in a future scenario of a remote region in Norway with large wind power potential. A constant demand of hydrogen is assumed and flexibility in the electrolysis operation is enabled by hydrogen storage. Different levels of hydro power flexibility are considered by following a reservoir guiding curve every hour, 6 h or 24 h.Results from the case study show that hydrogen can be produced at a cost of 1.89 €/kg in the future if hydro power production is flexible within a period of 24 h, fulfilling industry targets. Flexible hydrogen production also contributes to significantly reducing wasted energy from spillage from reservoirs or wind power curtailment by up to 56% for 24 h of flexibility. The results also show that less hydro power flexibility results in increased flexible operation of the electrolysis plant where it delivers 39–46% more regulating power, operates more on higher power levels and stores more hydrogen.     

Techno-economics of novel refueling stations based on ammonia-to-hydrogen route and SOFC technology

This paper presents the economic assessment of novel refueling stations, in which through advanced and high efficiency technologies, the polygeneration of more energy services like hydrogen, electricity and heat is carried out on-site.The architecture of these polygeneration plants is realized with a modular structure, organized in more sections.The primary energy source is ammonia that represents an interesting fuel for producing more energy streams. The ammonia feeds directly the SOFC that is able to co-generate simultaneously electricity and hydrogen by coupling a high efficiency energy system with hydrogen chemical storage.Two system configurations have been proposed considering different design concepts: in the first case (Concept_1) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized also for self-sustaining the plant electric power consumption, while in the second one (Concept_2) the plant is sized for producing 100 kg/day of hydrogen and the power section is sized for self-sustaining the plant electric power consumption and for generating 50 kW for the DC fast charging.The economic analysis has been carried out in the current and target scenarios, by evaluating, the levelized cost of hydrogen (LCOH), the levelized cost of electricity (LCOE), the Profitability Index (PI), Internal rate of Return (IRR) and the Discounted Payback Period (DPP).Results have highlighted that the values of the LCOH, for the proposed configurations and economic scenarios, are in the range 6–10 €/kg and the values of the LCOE range from 0.447 €/kWh to 0.242 €/kWh.In terms of PI and IRR, the best performance is achieved in the Concept_1 for the current scenario (1.89 and 8.0%, respectively). On the contrary, in the target scenario, thanks to a drastic costs reduction the co-production of hydrogen and electricity as useful outputs, becomes the best choice from all economic indexes and parameters considered.     

The value of flexible fuel mixing in hydrogen-fueled gas turbines – A techno-economic study

In electricity systems mainly supplied with variable renewable electricity (VRE), the variable generation must be balanced. Hydrogen as an energy carrier, combined with storage, has the ability to shift electricity generation in time and thereby support the electricity system. The aim of this work is to analyze the competitiveness of hydrogen-fueled gas turbines, including both open and combined cycles, with flexible fuel mixing of hydrogen and biomethane in zero-carbon emissions electricity systems. The work applies a techno-economic optimization model to future European electricity systems with high shares of VRE.The results show that the most competitive gas turbine option is a combined cycle configuration that is capable of handling up to 100% hydrogen, fed with various mixtures of hydrogen and biomethane. The results also indicate that the endogenously calculated hydrogen cost rarely exceeds 5 €/kg_H2 when used in gas turbines, and that a hydrogen cost of 3–4 €/kg_H2 is, for most of the scenarios investigated, competitive. Furthermore, the results show that hydrogen gas turbines are more competitive in wind-based energy systems, as compared to solar-based systems, in that the fluctuations of the electricity generation in the former are fewer, more irregular and of longer duration. Thus, it is the characteristics of an energy system, and not necessarily the cost of hydrogen, that determine the competitiveness of hydrogen gas turbines.     

Transient simulation and techno-economic assessment of a near-zero energy building using a hydrogen storage system and different backup fuels

Proposing a cost-effective off-grid Hybrid Renewable Energy System (HRES) with hydrogen energy storage with a minimum CO2 emission is the main objective of the current study. The electricity demand of an office building is considered to be supplied by Photovoltaic Panels and wind turbines. The office building, modeled in Energy Plus and Open studio, has annual electricity consumption of 500 MWh electricity. 48.9% of the required electricity can be generated via renewable resources. Considering a system without energy storage, the remaining amount of electricity is generated from diesel generators. Hence, for reducing CO2 emission and fuel costs, a hydrogen energy storage system (ESS) is integrated into the system. Hydrogen ESS is responsible for supplying 38.6% of the demand electricity, which means that it can increase the energy supplying ability of the system from 48.9% to 87.5%. In addition to analyzing the application of the hydrogen storage system, the effect of four different kinds of fuel is considered as well. effects of Natural gas, Diesel, Propane, and LPG on the system's application are investigated in this study. Results indicate that natural gas emits less amount of CO2 compared to other fuels and also has a fuel cost of 3054 $/year, while hydrogen ESS is available. For the renewable system without ESS, the fuel cost rises to 10,266 $/year. However, liquid gas, Propane, and LPG have better performance in terms of CO2 emission and fuel cost, respectively.     

Techno-economic evaluation of hydrogen refueling stations with liquid or gaseous stored hydrogen

In this study, different hydrogen refueling station (HRS) architectures are analyzed energetically as well as economically for 2015 and 2050. For the energetic evaluation, the model published in Bauer et al. [1] is used and norm-fitting fuelings according to SAE J2601 [2] are applied. This model is extended to include an economic evaluation. The compressor (gaseous hydrogen) resp. pump (liquid hydrogen) throughput and maximum pressures and volumes of the cascaded high-pressure storage system vessels are dimensioned in a way to minimize lifecycle costs, including depreciation, capital commitment and electricity costs. Various station capacity sizes are derived and energy consumption is calculated for different ambient temperatures and different station utilizations. Investment costs and costs per fueling mass are calculated based on different station utilizations and an ambient temperature of +12 °C. In case of gaseous trucked-in hydrogen, a comparison between 5 MPa and 20 MPa low-pressure storage is conducted. For all station configurations and sizes, a medium-voltage grid connection is applied if the power load exceeds a certain limit. For stations with on-site production, the electric power load of the hydrogen production device (electrolyzer or gas reformer) is taken into account in terms of power load. Costs and energy consumption attributed to the production device are not considered in this study due to comparability to other station concepts. Therefore, grid connection costs are allocated to the fueling station part excluding the production device. The operational strategy of the production device is also considered as energy consumption of the subsequent compressor or pump and the required low-pressure storage are affected by it. All station concepts, liquid truck-supplied hydrogen as well as stations with gaseous truck-supplied or on-site produced hydrogen show a considerable cost reduction potential. Long-term specific hydrogen costs of large stations (6 dispensers) are 0.63 €/kg – 0.76 €/kg (dependent on configuration) for stations with gaseous stored hydrogen and 0.18 €/kg for stations with liquid stored hydrogen. The study focuses only on the refueling station and does not allow a statement about the overall cost-effectiveness of different pathways.     

A comparison of two hydrogen storages in a fossil-free direct reduced iron process

Hydrogen direct reduction has been proposed as a means to decarbonize primary steelmaking. Preferably, the hydrogen necessary for this process is produced via water electrolysis. A downside to electrolysis is the large electricity demand. The electricity cost of water electrolysis may be reduced by using a hydrogen storage to exploit variations in electricity price, i.e., producing more hydrogen when the electricity price is low and vice versa. In this paper we compare two kinds of hydrogen storages in the context of a hydrogen direct reduction process via simulations based on historic Swedish electricity prices: the storage of gaseous hydrogen in an underground lined rock cavern and the storage of hydrogen chemically bound in methanol. We find the methanol-based storages to be economically advantageous to lined rock caverns in several scenarios. The main advantages of methanol-based storage are the low investment cost of storage capacity and the possibility to decouple storage capacity from rate capacity. Nevertheless, no storage option is found to be profitable for historic Swedish electricity prices. For the storages to be profitable, electricity prices must be volatile with relatively frequent high peaks, which has happened rarely in Sweden in recent years. However, such scenarios may become more common with the expected increase of intermittent renewable power in the Swedish electricity system.     

Low-carbon hydrogen production via electron beam plasma methane pyrolysis: Techno-economic analysis and carbon footprint assessment

Electron beam plasma methane pyrolysis is a hydrogen production pathway from natural gas without direct CO₂ emissions. In this work, two concepts for a technical implementation of the electron beam plasma pyrolysis in a large-scale hydrogen production plant are presented and evaluated in regards of efficiency, economics and carbon footprint. The potential of this technology is identified by an assessment of the results with the benchmark technologies steam methane reforming, steam methane reforming with carbon capture and storage as well as water electrolysis. The techno-economic analysis shows levelized costs of hydrogen for the plasma pyrolysis between 2.55 €/kg H₂ and 5.00 €/kg H₂ under the current economic framework. Projections for future price developments reveal a significant reduction potential for the hydrogen production costs, which support the profitability of plasma pyrolysis under certain scenarios. In particular, water electrolysis as direct competitor with renewable electricity as energy supply shows a considerably higher specific energy consumption leading to economic advantages of plasma pyrolysis for cost-intensive energy sources and a high degree of utilization. Finally, the carbon footprint assessment indicates the high potential for a reduction of life cycle emissions by electron beam plasma methane pyrolysis (1.9 kg CO₂ eq./kg H₂ – 6.4 kg CO₂ eq./kg H₂, depending on the electricity source) compared to state-of-the-art hydrogen production technology (10.8 kg CO₂ eq./kg H₂).     

Techno-economic analysis of hydrogen transportation infrastructure using ammonia and methanol

The transformation from a fossil fuels economy to a low carbon economy reshapes how energy is transmitted. Since most renewable energy is harvested in the form of electricity, hydrogen obtained from water electrolysis using green electricity is considered a promising energy vector. However, the storage and transportation of hydrogen at large scales pose challenges to the existing energy infrastructures, both regarding technological and economic aspects. To facilitate the distribution of renewable energy, a set of candidate hydrogen transportation infrastructures using methanol and ammonia as hydrogen carriers were proposed. A systematical analysis reveals that the levelized costs of transporting hydrogen using methanol and ammonia in the best cases are $1879/t-H₂ and $1479/t-H₂, respectively. The levelized cost of energy transportation using proposed infrastructures in the best case is $10.09/GJ. A benchmark for hydrogen transportation infrastructure design is provided in this study.     

Hydrogen production by coupling pressurized high temperature electrolyser with solar tower technology

Solar hydrogen production by coupling of pressurized high temperature electrolyser with concentrated solar tower technology is studied. As the high temperature electrolyser requires constant temperature conditions, the focus is made on a molten salt solar tower due to its high storage capacity. A flowsheet was developed and simulations were carried out with Aspen Plus 8.4 software for MW-scale hydrogen production plants. The solar part was laid out with HFLCAL software. Two different scenarios were considered: the first concerns the production of 400 kg/d hydrogen corresponding to mobility use (fuel station). The second scenario deals with the production of 4000 kg/d hydrogen for industrial use. The process was analyzed from a thermodynamic point of view by calculating the overall process efficiency and determining the annual production. It was assumed that a fixed hydrogen demand exists in the two cases and it was assessed to which extent this can be supplied by the solar high temperature electrolysis process including thermal storage as well as hydrogen storage. For time periods with a potential over supply of hydrogen, it was considered that the excess energy is sold as electricity to the grid. For time periods where the hydrogen demand cannot be fully supplied, electricity consumption from the grid was considered. It was assessed which solar multiple is appropriate to achieve low consumption of grid electricity and low excess energy. It is shown that the consumption of grid electricity is reduced for increasing solar multiple but the efficiency is also reduced. At a solar multiple of 3.0 an annual solar-to-H₂ efficiency greater than 14% is achieved at grid electricity production below 5% for the industrial case (4000 kg/d). In a sensitivity study the paramount importance of electrolyser performance, i.e. efficiency and conversion, is shown.