A solution to renewable hydrogen economy for fuel cell buses – A case study for Zhangjiakou in North China

Fuel cell vehicles fueled with renewable hydrogen is recognized as a life-cycle carbon-free option for the transport sector, however, the profitability of the H₂ pathway becomes a key issue for the FCV commercialization. By analyzing the actual data from the Zhangjiakou fuel cell transit bus project, this research reveals it is economically feasible to commercialize FCV in areas with abundant renewable resources. Low electricity for water electrolysis, localization of H₂ supply, and curtailed end price of H₂ refueling effectively reduce the hydrogen production, delivery and refueling cost, and render a chance for the profitability of refueling stations. After the fulfillment of the intense deployment of both vehicles and hydrogen stations for the 2022 Winter Olympics, the H₂ pathway starts to make a profit thereafter. The practices in the Zhangjiakou FCB project offer a solution to the hydrogen economy, which helps to break the chicken-egg dilemma of vehicles and hydrogen infrastructure.     

Renewable-powered hydrogen economy from Australia's perspective

This article broadly reviews the state-of-the-art technologies for hydrogen production routes, and methods of renewable integration. It outlines the main techno-economic enabler factors for Australia to transform and lead the regional energy market. Two main categories for competitive and commercial-scale hydrogen production routes in Australia are identified: 1) electrolysis powered by renewable, and 2) fossil fuel cracking via steam methane reforming (SMR) or coal gasification which must be coupled with carbon capture and sequestration (CCS). It is reported that Australia is able to competitively lower the levelized cost of hydrogen (LCOH) to a record $(1.88–2.30)/kg_H2 for SMR technologies, and $(2.02–2.47)/kg_H2 for black-coal gasification technologies. Comparatively, the LCOH via electrolysis technologies is in the range of $(4.78–5.84)/kg_H2 for the alkaline electrolysis (AE) and $(6.08–7.43)/kg_H2 for the proton exchange membrane (PEM) counterparts. Nevertheless, hydrogen production must be linked to the right infrastructure in transport-storage-conversion to demonstrate appealing business models.     

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).     

Development of European hydrogen infrastructure scenarios—CO2 reduction potential and infrastructure investment

For the introduction of a hydrogen economy one of the most relevant questions is: what are the suitable feedstocks and production technologies for hydrogen, which is a secondary energy carrier, taking into account the manifold objectives of hydrogen introduction: the cost-effective substitution of oil, increasing the security of energy supply, and reducing CO₂ and other emissions? This study focuses on constructing a hydrogen infrastructure in Europe by 2030. Several hydrogen technologies and their integration into an infrastructure system, including the production, transport and distribution of hydrogen, are analysed on the basis of energy chain calculations and expert judgements and consistent scenarios are developed. It can be shown that under economic and CO₂-reduction objectives, the steam reforming of gas, followed by coal gasification and, to a limited extent, the electrolysis of electricity from renewable energy carriers are the most promising hydrogen production options in this first phase for developing a hydrogen infrastructure. These options result in a significant level of CO₂-reduction. However, the total cost of the infrastructure will account for 0.3% of EU-25 GDP in 2030. This shows the extent of the challenge involved in constructing a hydrogen infrastructure.     

Evaluation of hydrogen production methods using the Analytic Hierarchy Process

In this paper, seven common hydrogen production processes are evaluated using the Analytic Hierarchy Process (AHP) in respect to five criteria. The processes to be evaluated are steam methane reforming (SMR), partial oxidation of hydrocarbons (POX), coal gasification (CG), biomass gasification (BG), the combination of photovoltaics and electrolysis (PV–EL), the combination of wind power and electrolysis (W–EL) and the combination of hydropower and electrolysis (H–EL). The selected criteria that were used in the evaluation, for each of the seven hydrogen production processes are CO₂ emissions, operation and maintenance costs, capital cost, feedstock cost and hydrogen production cost. According to the evaluation, the processes that combine renewable energy sources with electrolysis (PV–EL, W–EL and H–EL) rank higher in classification than conventional processes (SMR, POX, CG and BG).     

Decarbonization synergies from joint planning of electricity and hydrogen production: A Texas case study

Hydrogen (H₂) shows promise as an energy carrier in contributing to emissions reductions from sectors which have been difficult to decarbonize, like industry and transportation. At the same time, flexible H₂ production via electrolysis can also support cost-effective integration of high shares of variable renewable energy (VRE) in the power system. In this work, we develop a least-cost investment planning model to co-optimize investments in electricity and H₂ infrastructure to serve electricity and H₂ demands under various low-carbon scenarios. Applying the model to a case study of Texas in 2050, we find that H₂ is produced in approximately equal amounts from electricity and natural gas under the least-cost expansion plan with a CO₂ price of $30–60/tonne. An increasing CO₂ price favors electrolysis, while increasing H₂ demand favors H₂ production from Steam Methane Reforming (SMR) of natural gas. H₂ production is found to be a cost effective solution to reduce emissions in the electric power system as it provides flexibility otherwise provided by natural gas power plants and enables high shares of VRE with less battery storage. Additionally, the availability of flexible electricity demand via electrolysis makes carbon capture and storage (CCS) deployment for SMR cost-effective at lower CO₂ prices ($90/tonne CO₂) than for power generation ($180/tonne CO₂). The total emissions attributable to H₂ production is found to be dependent on the H₂ demand. The marginal emissions from H₂ production increase with the H₂ demand for CO₂ prices less than $90/tonne CO₂, due to shift in supply from electrolysis to SMR. For a CO₂ price of $60/tonne we estimate the production weighted-average H₂ price to be between $1.30–1.66/kg across three H₂ demand scenarios. These findings indicate the importance of joint planning of electricity and H₂ infrastructure for cost-effective energy system decarbonization.     

Hydrogen production using methane: Techno-economics of decarbonizing fuels and chemicals

In the near-to-medium future, hydrogen production will continue to rely on reforming of widely available and relatively low-cost fossil resources. A techno-economic framework is described that compares the current best practice steam methane reforming (SMR) with potential pathways for low-CO₂ hydrogen production; (i) Electrolysis coupled to sustainable renewable electricity sources; (ii) Reforming of hydrocarbons coupled with carbon capture and sequestration (CCS) and; (iii) Thermal dissociation of hydrocarbons into hydrogen and carbon (pyrolysis). For methane pyrolysis, a process based on a catalytic molten Ni-Bi alloy is described and used for comparative cost estimates. In the absence of a price on carbon, SMR has the lowest cost of hydrogen production. For low-CO₂ hydrogen production, methane pyrolysis is significantly more economical than electrochemical-based processes using commercial renewable power sources. At a carbon price exceeding $21 t^?1 CO₂ equivalent, pyrolysis may represent the most cost-effective means of producing low-CO₂ hydrogen and competes favorably to SMR with carbon capture and sequestration. The current cost disparity between renewable and fossil-based hydrogen production suggests that if hydrogen is to fulfil an expanding role in a low CO₂ future, then large-scale production of hydrogen from methane pyrolysis is the most cost-effective means during the transition period while infrastructure and end-use applications are deployed.     

Optimal design of wind-powered hydrogen refuelling station for some selected cities of South Africa

The transport sector is considered as one of the sectors producing high carbon emissions worldwide due to the use of fossil fuels. Hydrogen is a non-toxic energy carrier that could serve as a good alternative to fossil fuels. The use of hydrogen vehicles could help reduce carbon emissions thereby cutting down on greenhouse gases and environmental pollution. This could largely be achieved when hydrogen is produced from renewable energy sources and is easily accessible through a widespread network of hydrogen refuelling stations. In this study, the techno-economic assessment was performed for a wind-powered hydrogen refuelling station in seven cities of South Africa. The aim is to determine the optimum configuration of a hydrogen refuelling station powered by wind energy resources for each of the cities as well as to determine their economic viability and carbon emission reduction capability. The stations were designed to cater for 25 hydrogen vehicles every day, each with a 5 kg tank capacity. The results show that a wind-powered hydrogen refuelling station is viable in South Africa with the cost of hydrogen production ranging from 6.34 $/kg to 8.97 $/kg. These costs are competitive when compared to other costs of hydrogen production around the world. The cities located in the coastal region of South Africa are more promising for siting wind powered-hydrogen refuelling station compared to the cities located on the mainland. The hydrogen refuelling stations could reduce the CO₂ and CO emissions by 73.95 tons and 0.133 tons per annum, respectively.     

Towards net-zero compatible hydrogen from steam reformation – Techno-economic analysis of process design options

Increased consumption of low-carbon hydrogen is prominent in the decarbonisation strategies of many jurisdictions. Yet prior studies assessing the current most prevalent production method, steam reformation of natural gas (SRNG), have not sufficiently evaluated how process design decisions affect life cycle greenhouse gas (GHG) emissions. This techno-economic case study assesses cradle-to-gate emissions of hydrogen produced from SRNG with CO₂ capture and storage (CCS) in British Columbia, Canada. Four process configurations with amine-based CCS using existing technology and novel process designs are evaluated. We find that cradle-to-gate GHG emission intensity ranges from 0.7 to 2.7 kgCO₂e/kgH₂ – significantly lower than previous studies of SRNG with CCS and similar to the range of published estimates for hydrogen produced from renewable-powered electrolysis. The levelized cost of hydrogen (LCOH) in this study (US$1.1–1.3/kgH₂) is significantly lower than published estimates for renewable-powered electrolysis.     

Cost of a potential hydrogen-refueling network for heavy-duty vehicles with long-haul application in Germany 2050

Long-distance road-freight transport emits a large share of Germany's greenhouse gas (GHG) emissions. A potential solution for reducing GHG emissions in this sector is to use green hydrogen in fuel cell electric vehicles (FC-HDV) and establish an accompanying hydrogen refueling station (HRS) network. In this paper, we apply an existing refueling network design model to a HDV-HRS network for Germany until 2050 based on German traffic data for heavy-duty trucks and estimate its costs. Comparing different fuel supply scenarios (pipeline vs. on-site), The on-site scenario results show a network consisting of 137 stations at a cost of 8.38 billion € per year in 2050 (0.40 € per vehicle km), while the centralized scenario with the same amount of stations shows a cheaper cost with 7.25 billion euros per year (0.35 € per vehicle km). The hydrogen cost (LCOH) varies from 5.59 €/kg (pipeline) to 6.47 €/kg (on-site) in 2050.     

Dynamic production,storage, and use of renewable hydrogen: A technical-economic-environmental analysis in the public transport system in São Paulo state,Brazil

This article proposes a calculation methodology that starts from the demand calculation to supply a fleet bus with renewable hydrogen based on the electrolysis process until the energetic, economic, and environmental analyses, involving all the processes of the productive chair. Also considering the dynamic behaviour of the following hydrogen processes: production, storage, and use. The simplified scheme of the proposed system configuration to be studied consists of the use of alternative and renewable sources of energy (solar-wind-biogas) to generate electrical energy in order to produce hydrogen from electrolysis of the water, which is stored in its gaseous state and subsequently redirected to a filling station to be used as vehicle fuel in buses. The results show that to feed one bus the hybrid system generates an average of 78,110 kWh/month with an installed capacity of 1101.905 kW, producing 1209.90 kgH₂/month through the electrolysis process from water. The results also show a range of electricity generation costs between 1.130 and 0.123 US$/kWh and H₂ production between 0.963 and 0.110 US$/kWh. Concluding that the application of renewable energies to produce hydrogen and electricity for the public transport sector is an attractive alternative in the future throughout the country, because the proposed system is technically, economically and ecologically viable.     

A life cycle impact analysis of various hydrogen production methods for public transportation sector

Reducing greenhouse gas emissions is an important task to reduce the adverse effects of climate change. A large portion of greenhouse gas emissions apparently originates from the transportation sector. Therefore, adopting cleaner technologies with lower emission footprints has become vital. For this reason, in this study, a life cycle impact analysis of hydrogen production technologies as an alternative to fossil fuels and the utilization of hydrogen in fuel cell electric buses is carried out. According to the results of this study, the operational contributions of internal combustion engines have a significant impact on life cycle impact analysis indicators. The global warming potentials of clean hydrogen production technologies result in much lower results compared to conventional hydrogen production technologies. Also, almost all indicators for biohydrogen production technologiess yield lower results because of the wastewater removal. The global warming potential results of hydrogen production methods are found to be 6.8, 1.9, 2.1, 0.5, 0.2, and 7.9 kg CO₂ eq./kg H₂ for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation and conventional hydrogen production, respectively. However, the chemicals used in PV and wind turbine production increased the ecotoxicological indicators. On the other hand, hydrogen utilization in buses is a better option environmentally. The global warming potentials for PV electrolysis, wind electrolysis, high temperature electrolysis, dark fermentation, photo fermentation, conventional hydrogen, compressed natural gas bus, and diesel bus are found to be 0.060, 0.016, 0.018, 0.007, 0.006, 0.053, 0.082, and 0.125 kg CO₂ eq./p.km, respectively. The results are especially important in terms of reducing the effects at the source and optimizing the systems.     

Optimal operation of a photovoltaic generation-powered hydrogen production system at a hydrogen refueling station

As the popularity of fuel cell vehicles continues to rise in the global market, production and supply of low-carbon hydrogen are important to mitigate CO₂ emissions. We propose a design for a hydrogen refueling station with a proton exchange membrane electrolyzer (PEM-EL)-based electrolysis system (EL-System) and photovoltaic generation (PV) to supply low-carbon hydrogen. Hydrogen is produced by the EL-System using electricity from PV and the power grid. The system was formulated as a mixed integer linear programming (MILP) model to allow analysis of optimal operational strategies. Case studies with different objective functions, CO₂ emission targets, and capacity utilization of the EL-System were evaluated. Efficiency characteristics of the EL-System were obtained through measurements. The optimized operational strategies were evaluated with reference to three evaluation indices: CO₂ emissions, capacity utilization, and operational cost of the system. The results were as follows: 1) Regardless of the objective function, the EL-System generally operated in highest efficiency state, and optimal operation depended on the efficiency characteristics of the EL-System; 2) mitigation of CO₂ emissions and increase in capacity utilization of the EL-System required trade-offs; and 3) increased capacity utilization of the EL-System showed two opposing effects on hydrogen retail price.     

An analysis of hydrogen production from renewable electricity sources

Three aspects of producing hydrogen via renewable electricity sources are analyzed to determine the potential for solar and wind hydrogen production pathways: a renewable hydrogen resource assessment, a cost analysis of hydrogen production via electrolysis, and the annual energy requirements of producing hydrogen for refueling. The results indicate that ample resources exist to produce transportation fuel from wind and solar power. However, hydrogen prices are highly dependent on electricity prices. For renewables to produce hydrogen at $2 kg⁻¹, using electrolyzers available in 2004, electricity prices would have to be less than $0.01 kWh⁻¹. Additionally, energy requirements for hydrogen refueling stations are in excess of 20 GWh/year. It may be challenging for dedicated renewable systems at the filling station to meet such requirements. Therefore, while plentiful resources exist to provide clean electricity for the production of hydrogen for transportation fuel, challenges remain to identify optimum economic and technical configurations to provide renewable energy to distributed hydrogen refueling stations.     

On capital utilization in the hydrogen economy: The quest to minimize idle capacity in renewables-rich energy systems

The hydrogen economy is currently experiencing a surge in attention, partly due to the possibility of absorbing variable renewable energy (VRE) production peaks through electrolysis. A fundamental challenge with this approach is low utilization rates of various parts of the integrated electricity-hydrogen system. To assess the importance of capacity utilization, this paper introduces a novel stylized numerical energy system model incorporating the major elements of electricity and hydrogen generation, transmission and storage, including both “green” hydrogen from electrolysis and “blue” hydrogen from natural gas reforming with CO₂ capture and storage (CCS). Concurrent optimization of all major system elements revealed that balancing VRE with electrolysis involves substantial additional costs beyond reduced electrolyzer capacity factors. Depending on the location of electrolyzers, greater capital expenditures are also required for hydrogen pipelines and storage infrastructure (to handle intermittent hydrogen production) or electricity transmission networks (to transmit VRE peaks to electrolyzers). Blue hydrogen scenarios face similar constraints. High VRE shares impose low utilization rates of CO₂ capture, transport and storage infrastructure for conventional CCS, and of hydrogen transmission and storage infrastructure for a novel process (gas switching reforming) that enables flexible power and hydrogen production. In conclusion, all major system elements must be considered to accurately reflect the costs of using hydrogen to integrate higher VRE shares.     

Opportunities and challenges of low-carbon hydrogen via metallic membranes

Today, electricity & heat generation, transportation, and industrial sectors together produce more than 80% of energy-related CO₂ emissions. Hydrogen may be used as an energy carrier and an alternative fuel in the industrial, residential, and transportation sectors for either heating, energy production from fuel cells, or direct fueling of vehicles. In particular, the use of hydrogen fuel cell vehicles (HFCVs) has the potential to virtually eliminate CO₂ emissions from tailpipes and considerably reduce overall emissions from the transportation sector. Although steam methane reforming (SMR) is the dominant industrial process for hydrogen production, environmental concerns associated with CO₂ emissions along with the process intensification and energy optimization are areas that still require improvement. Metallic membrane reactors (MRs) have the potential to address both challenges. MRs operate at significantly lower pressures and temperatures compared with the conventional reactors. Hence, the capital and operating expenses could be considerably lower compared with the conventional reactors. Moreover, metallic membranes, specifically Pd and its alloys, inherently allow for only hydrogen permeation, making it possible to produce a stream of up to 99.999+% purity.For smaller and emerging hydrogen markets such as the semiconductor and fuel cell industries, Pd-based membranes may be an appropriate technology based on the scales and purity requirements. In particular, at lower hydrogen production rates in small-scale plants, MRs with CCUS could be competitive compared to centralized H₂ production. On-site hydrogen production would also provide a self-sufficient supply and further circumvent delivery delays as well as issues with storage safety. In addition, hydrogen-producing MRs are a potential avenue to alleviate carbon emissions. However, material availability, Pd cost, and scale-up potential on the order of 1.5 million m³/day may be limiting factors preventing wider application of Pd-based membranes.Regarding the economic production of hydrogen, the benchmark by the year 2020 has been determined and set in place by the U.S. DOE at less than $2.00 per kg of produced hydrogen. While the established SMR process can easily meet the set limit by DOE, other carbon-free processes such as water electrolysis, electron beam radiolysis, and gliding arc technologies do not presently meet this requirement. In particular, it is expected that the cost of hydrogen produced from natural gas without CCUS will remain the lowest among all of the technologies, while the hydrogen cost produced from an SMR plant with solvent-based carbon capture could be twice as expensive as the conventional SMR without carbon capture. Pd-based MRs have the potential to produce hydrogen at competitive prices with SMR plants equipped with carbon capture.Despite the significant improvements in the electrolysis technologies, the cost of hydrogen produced by electrolysis may remain significantly higher in most geographical locations compared with the hydrogen produced from fossil fuels. The cost of hydrogen via electrolysis may vary up to a factor of ten,d epending on the location and the electricity source. Nevertheless, due to its modular nature, the electrolysis process will likely play a significant role in the hydrogen economy when implemented in suitable geographical locations and powered by renewable electricity.This review provides a critical overview of the opportunities and challenges associated with the use of the MRs to produce high-purity hydrogen with low carbon emissions. Moreover, a technoeconomic review of the potential methods for hydrogen production is provided and the drawbacks and advantages of each method are presented and discussed.     

Market penetration analysis of hydrogen vehicles in Norwegian passenger transport towards 2050

The Norwegian energy system is characterized by high dependency on electricity, mainly hydro power. If the national targets to reduce emissions of greenhouse gases should be met, a substantial reduction of CO₂ emissions has to be obtained from the transport sector. This paper presents the results of the analyses of three Norwegian regions with the energy system model MARKAL during the period 2005–2050. The MARKAL models were used in connection with an infrastructure model H2INVEST. The analyses show that a transition to a hydrogen fuelled transportation sector could be feasible in the long run, and indicate that with substantial hydrogen distribution efforts, fuel cell cars can become competitive compared to other technologies both in urban (2025) and rural areas (2030). In addition, the result shows the importance of the availability of local energy resources for hydrogen production, like the advantages of location close to chemical industry or surplus of renewable electricity.     

Life cycle greenhouse emissions of compressed natural gas–hydrogen mixtures for transportation in Argentina

We have developed a model to assess the life cycle greenhouse emissions of compressed natural gas–hydrogen (CNG–H₂) mixtures used for transportation in Argentina. The overall fuel life cycle is assessed through a well-to-wheel (WTW) analysis for different hydrogen generation and distribution options. The combustion stage in road vehicles is modeled using the COPERT IV model. Hydrogen generation options include classical steam methane reforming (SMR) and water electrolysis (WE) in central plants and distributed facilities at the refueling stations. Centralized hydrogen generation by electrolysis in nuclear plants as well as the use of solar photovoltaic and wind electricity is also considered. Hydrogen distribution options include gas pipeline and refrigerated truck transportation for liquefied hydrogen. A total number of fifteen fuel pathways are studied; in all the cases the natural gas–hydrogen mixture is made at the refueling station. The use of WE using nuclear or wind electricity appears to be less contaminant that the use of pure CNG.     

Polygeneration-Annex: Integrating hydrogen into syngas-based gasoline production

As a result of the rising share of renewable energy in Germany, suitable energy storage solutions are needed. At the same time, existing base-load lignite-fired power plants suffer from low capacity utilization and frequent load changes. In combination with a Coal-to-Liquids (CTL) facility, the power generation utilization might increase. By using the existing power plant infrastructure, investment costs for the CTL facility can be reduced. Such combined polygeneration concepts, called ’Annex’, have been developed at TU Bergakademie Freiberg. Previously, polygeneration concepts based on Methanol - to - Gasoline (MTG), Methanol - to - Olefins and Fischer - Tropsch synthesis have been analyzed. In addition, the Annex CTL plant can be used to store energy by incorporating renewable hydrogen from electrolysis into the synthesis step. Such a concept offers the advantage to lower CO₂ emissions and could be used to store renewable excess power. In the current study, concepts based on entrained-flow gasification and MTG synthesis are analyzed. This concept is compared to a stand-alone synthesis route. Linking a 52 MW_el alkaline water electrolysis to the synthesis plant, hydrogen can be integrated in the CTL plant. Four different concepts for hydrogen integration are investigated. Fluctuations in hydrogen supply could be counter-balanced through storage tanks or Demand Side Management in the CTL Annex plant. A techno-economic study is conducted using the commercial software package Aspen Plus. An analysis of efficiencies, carbon emissions and production costs is provided. An overall system efficiency of 36.5–37.6% is determined.     

Large-scale decomposition of green ammonia for pure hydrogen production

It is acknowledged that Hydrogen has a decisive role to play in insuring a reliable and efficient penetration of renewable electricity in the energy mix. Nonetheless, building a sustainable Hydrogen Economy is faced with numerous challenges across the value chain. Namely, large-scale production and storage are still open issues that need to be addressed. A promising solution is to store renewable H₂ in the form of green ammonia often referred to as Power-to-Ammonia. Thus unlocking all available infrastructure for ammonia to effectively store and export hydrogen in bulk. In this value chain, the missing link is ammonia cracking to recover back hydrogen at high purities. The present work explores a technical solution to recover hydrogen from ammonia at large-scale. Through an exhaustive technoeconomic analysis, we have demonstrated the feasibility of large-scale production of pure H₂ from ammonia. The designed Ammonia-to-H₂ plant operates at a thermal efficiency of 68.5% to produce 200 MTPD of pure hydrogen at 250 bar. Furthermore, this study has established a final estimation of the Levelized Cost of Hydrogen (LCOH) from green ammonia. It was revealed that LCOH is mostly dependent on green ammonia cost, which in turn varies with renewable electricity cost.