Techno-economic and life-cycle assessment of hydrogen production pathways in the Middle East and North African region

Hydrogen is a versatile energy carrier and storage medium that may be employed in a variety of applications. According to the industrial processes used for its production, hydrogen may be labelled using different colours: (i) grey hydrogen, produced from natural gas using steam methane reforming (SMR), (ii) blue hydrogen, like the grey one, but with carbon capture and storage (CCS), (iii) green hydrogen, produced by water electrolysis using electricity from renewable sources only, (iv) “grid” hydrogen, produced by electrolysis using grid electricity. In this study, process simulation is used to solve material and energy balances, as well as to estimate capital and maintenance costs for each technology investigated. Then, process simulation outcomes are used to estimate three key performance indicators focusing on sustainability issues: the Energy Return on Energy Invested (EROEI), the Levelized Cost of Hydrogen (LCOH) and the Life Cycle Assessment (LCA). With reference to the case study of the Trieste port in Italy, the potential of synthesizing and utilizing hydrogen to fuel transportation activities within a port is examined. Based on the daily hydrogen consumption in fuel cells installed on locomotors and trucks, the design of the different processes considered is carried out, as well as their comparison in terms of EROEI, LCOH, and LCA. Furthermore, LCA and Total Cost of Ownership (TCO) evaluations for various hydrogen-fueled vehicles within the port are presented and compared to diesel-fueled ones to determine the impact of fuel-cell vehicles during operations. Results show that EROEI of hydrogen produced by electrolysis is larger than that produced by SMR with or without CCS. The LCOH for grey hydrogen is of the same order of magnitude of that of green or grid ones. The hydrogen compression step to 300 bar impacts on both energetic and economic performances. LCA indicates that the Global Warming Potential (GWP) of green hydrogen is at least half with respect to blue hydrogen, however other impact categories are less favourable. On the other hand, the TCO of hydrogen-fueled vehicles is higher than that of diesel-fueled ones, mainly because of the higher purchase costs. It is concluded that the methodology proposed in this paper, based on the evaluation of indicators at the design stage, is suitable for comparing hydrogen production processes. In addition, it is a powerful tool for policy decision-makers in defining the strategies for the development of hydrogen-based transport systems in port operations.

This study evaluates the techno-economic and life-cycle carbon assessments of blue hydrogen production via steam methane reforming (SMR) with carbon capture and sequestration (CCS) at the Escalante hydrogen facility, under the CarbonSAFE project. SMR with carbon capture was simulated in ChemCAD, while an integrated asset model was developed to simulate the carbon dioxide (CO2) compression, transportation, and injection. The results show that SMR without CCS has a carbon footprint of 11.99 kgCO2e/kgH2. Integrating CCS which captures over 95% of CO2 emissions, reduces this footprint to as low as 6.59 kgCO2e/kgH2, but raises the levelized cost of hydrogen (LCOH) from $1.82/kgH2 (no CCS) to $3.22/kgH2 (with CCS, no tax credit) and $2.59/kg H2 (with a 45Q tax credit). Consequently, the levelized net present value (NPV) declines from $0.87/kgH2 without CCS to $0.74/kgH2 with CCS, due to the added costs of carbon capture, transport, and storage. Pipeline route analysis shows that longer routes and challenging terrains modestly increase greenhouse gas (GHG) emissions, while powering SMR with nuclear and renewable sources especially wind and hydro, yields the lowest life-cycle emissions compared to geothermal or hydropower. Sensitivity analyses identify hydrogen selling price, internal rate of return (IRR), and CCS cost as the key drivers of economic feasibility whereas grid electricity consumption is the main contributor to lifecycle emissions. These findings underscore the trade-off between higher production costs and lower emissions, demonstrating that policy incentives, cleaner electricity sources, and robust hydrogen markets are pivotal to advancing low-carbon hydrogen production.

Solar-integrated blue hydrogen production with optimized post-combustion carbon capture: A techno-economic and exergoeconomic assessment

The Cryogenic Flux Capacitor (CFC) is a cold, dense energy storage core that is being studied in the cryo-compressed, about 300 bar and 80K, region of gaseous hydrogen (GH2) storage and liquid hydrogen (LH2) region near the normal boiling point. Hydrogen storage is improved by physically bonding the molecules within the nanoscale pores of the aerogel composite blanket material. The process of bonding or debonding is governed by principles of physical adsorption (physisorption) and thermodynamics. The large surface area afforded by the nanoporous aerogel (∼1,000 m2/g) allows its storage performance to easily exceed capacities of high-pressure GH2 storage for an equivalent volume. With the integrated aerogel, subscale tests have shown that storage is increased by about 36% over a simple tank filled with GH2 at the same operating temperature and pressure. For LH2 conditions, the CFC is shown to operate at improved densities, but testing is ongoing. For the techno-economic analysis (TEA), the source of hydrogen is compared between onsite steam methane reforming (SMR) and onsite solar photovoltaic (PV) panels providing power to electrolyzers to produce green GH2. The TEA compares pure hydrogen produced at a small scale for a 25 MW power system and at a large scale in a 500 MW power system. The system allowed for hydrogen imports and exports at a set price with a tank sized for 10 hours of power production. The two power producing technologies are a combined cycle gas turbine (CCGT) and hydrogen fuel cells. The SMR system uses natural gas as an input and includes a carbon capture and storage (CCS) system. The levelized cost of electricity (LCOE), levelized cost of hydrogen (LCOH), and levelized cost of storage (LCOS) are developed based on the capital cost and operating cost of the systems. The results are shown for current costs using a 2021 benchmark and DOE projections for cost improvements by 2030. The TEA showed that onsite hydrogen generation from SMR has an LCOH of about 1.4 to 2 USD per kg over the life of the plant and the PV hydrogen production LCOH is about 5.2 to 5.5 USD per kg. The LCOS of conventional GH2 systems is estimated to be $210/MWh and cost of storage for LH2 systems is $205/MWh for fuel cell systems and $249/MWh for CCGT systems. CFC improved the LCOS of all these systems to $198/MWh, $191/MWh and $233/MWh respectively. The LCOE also improved with conventional systems between $171/MWh and $228/MWh improved by CFC to between $167/MWh and $212/MWh. Using projections for improvement in costs following DOE’s goals by 2030, green hydrogen improved to as low as $78/MWh LCOS and LCOE for conventional cases. CFC improved over conventional storage with the lowest LCOS being $62/MWh and the lowest LCOE being $73/MWh. These results correspond to an LCOH of $2/kg. Finally, the TEA shows how LCOE is improved for hydrogen conditioning and storage over conventional systems and caverns in the 10 to 50 hour range.

Hydrogen is increasingly recognized as a clean energy vector and storage medium, yet its viability and strategic role in the Western Balkans remain underexplored. This study provides the first comprehensive techno-economic, environmental, and strategic evaluation of hydrogen production pathways in Albania. Results show clear trade-offs across options. The levelized cost of hydrogen (LCOH) is estimated at 8.76 €/kg H2 for grid-connected, 7.75 €/kg H2 for solar, and 7.66 €/kg H2 for wind electrolysis—values above EU averages and reliant on lower electricity costs and efficiency gains. In contrast, fossil-based hydrogen via steam methane reforming (SMR) is cheaper at 3.45 €/kg H2, rising to 4.74 €/kg H2 with carbon capture and storage (CCS). Environmentally, Life Cycle Assessment (LCA) results show much lower Global Warming Potential (<1 kg CO2-eq/kg H2) for renewables compared with ~10.39 kg CO2-eq/kg H2 for SMR, reduced to 3.19 kg CO2-eq/kg H2 with CCS. However, grid electrolysis dominated by hydropower entails high water-scarcity impacts, highlighting resource trade-offs. Strategically, Albania’s growing solar and wind projects (electricity prices of 24.89–44.88 €/MWh), coupled with existing gas infrastructure and EU integration, provide strong potential. While regulatory gaps and limited expertise remain challenges, competition from solar-plus-storage, regional rivals, and dependence on external financing pose additional risks. In the near term, a transitional phase using SMR + CCS could leverage Albania’s gas assets to scale hydrogen production while renewables mature. Overall, Albania’s hydrogen future hinges on targeted investments, supportive policies, and capacity building aligned with EU Green Deal objectives, with solar-powered electrolysis offering the potential to deliver environmentally sustainable green hydrogen at costs below 5.7 €/kg H2.

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.

The role of CO2 capture and storage in Saudi Arabia's energy future

Evaluation of Green and Blue Hydrogen Production Potential in Saudi Arabia

Renewable-powered hydrogen economy from Australia's perspective

The increasing demand for hydrogen has made it a promising alternative for decarbonizing industries and reducing CO2 emissions. Although mainly produced through the gray pathway, the integration of carbon capture and storage (CCS) reduces the CO2 emissions. This study presents a sustainability method that uses flare gas for hydrogen production through steam methane reforming (SMR) with CCS, supported by a techno-economic analysis. Data Envelopment Analysis (DEA) was used to evaluate the oil company’s efficiency, and inverse DEA/sensitivity analysis identified maximum flare gas reduction, which was modeled in Aspen HYSYS V14. Subsequently, an economic evaluation was performed to determine the levelized cost of hydrogen (LCOH) and the cost–benefit ratio (CBR) for Nigeria. The CBR results were 2.15 (payback of 4.11 years with carbon credit) and 1.96 (payback of 4.55 years without carbon credit), indicating strong economic feasibility. These findings promote a practical approach for waste reduction, aiding Nigeria’s transition to a circular, low-carbon economy, and demonstrate a positive relationship between lean and green strategies in the petroleum sector.

This article challenges the view that zero carbon hydrogen from steam methane reforming (SMR) is prohibitively expensive and that the cost of CO2 capture increases exponentially as residual emissions approach zero; a flawed narrative often eliminating SMR produced hydrogen as a route to net zero. We show that the capture and geological storage of 100% of the fossil CO2 produced in a SMR is achievable with commercially available post-combustion capture technology and an open art solvent. The Levelised Cost of Hydrogen (LCOH) of 69£/MWhth HHV (2.7£/kg) for UK production remains competitive to other forms of low carbon hydrogen, but retains a hydrogen lifecycle carbon intensity of 5 gCO2e/MJ (LHV) due to natural gas supply chain and embodied greenhouse gas (GHG) emissions. Compensating for the remaining lifecycle GHG emissions via Direct Air Capture with geological CO2 Storage (DACCS) increases the LCOH to 71–86 £/MWhth HHV (+3–25%) for a cost estimate of 100–1000 £/tCO2 for DACCS and the 2022 UK natural gas supply chain methane emission rates. Finally, we put in perspective the cost of CO2 avoidance of fuel switching from natural gas to hydrogen with long term price estimates for natural gas use and DACCS, and hydrogen produced from electrolysis.

This study assesses the techno-economic viability of a palladium-based membrane reactor for catalytic decomposition (pyrolysis) of methane. A process simulation approach is employed to evaluate the reactor’s performance and to design a complete catalytic decomposition plant. The membrane-based process is benchmarked against conventional steam methane reforming (SMR) in terms of the levelized cost of hydrogen (LCOH) production. Results indicate that the membrane reactor process achieves an approximately 5% lower LCOH than SMR, primarily due to reduced capital costs and the elimination of carbon capture and storage (CCS) requirements. Additionally, the recovery and sale of valuable carbon byproducts─such as carbon black─further improve the economic feasibility of the process. From an environmental perspective, the membrane process presents a cleaner alternative by avoiding CO2 emissions and generating solid carbon instead. Overall, the palladium-based membrane reactor demonstrates strong potential as a transitional pathway toward more sustainable hydrogen production.

Techno-economic assessment of hydrogen production from underground coal gasification (UCG) in Western Canada with carbon capture and sequestration (CCS) for upgrading bitumen from oil sands

Hydrogen (H2) is considered one of the main pillars for transforming the conventional “dark” energy system to a net-zero carbon or “green” energy system. This work reviewed the potential resources for producing low-carbon hydrogen in China, as well as the possible hydrogen production methods based on the available resources. The analysis and comparison of the levelized cost of hydrogen (LCOH) for different hydrogen production pathways, and the optimal technology mixes to produce H2 in China from 2020 to 2050 were obtained using the mixed-integer linear programming (MILP) optimization model. The results were concluded as three major ones: (a) By 2050, the LCOH of solar- and onshore-wind-powered hydrogen will reach around 70–80 $/MWh, which is lower than the current H2 price and the future low-carbon H2 price. (b) Fuel costs (>40%) and capital investments (~20%) of different hydrogen technologies are the major cost components, and also are the major direction to further reduce the hydrogen price. (c) For the optimal hydrogen technology mix under the higher renewable ratio (70%) in 2050, the installed capacities of the renewable-powered electrolysers are all more than 200 GW, and the overall LCOH is 68.46 $/MWh. This value is higher than the LCOH (62.95 $/MWh) of the scenario with higher coal gasification with carbon capture and the storage (CG-CCS) ratio (>50%). Overall, this work is the first time that hydrogen production methods in China has been discussed comprehensively, as well as the acquisition of the optimal H2 production technology mix by the MILP optimization model, which can provide guidance on future hydrogen development pathways and technology development potential in China.

In December 2018, the Council of Australian Governments set a vision (Australia Hydrogen Strategy) for a clean, innovative, safe, and competitive hydrogen industry that benefits all Australians and will be a major global player by 2030. This study will summarize the current and forecast uses and volumes of hydrogen along with estimating the potential future range of hydrogen prices and prices’ key drivers across Australia seven territories. The seven hubs are the basis to understand the range in hydrogen prices combined with the technologies available to produce hydrogen across Australia. These seven hubs are planned as a springboard to large scale production, although hydrogen projects can be outside these hubs as well. The impact of the drivers and price assessment across the green and blue hydrogen technologies were studied. Hydrogen price ranges were calculated and are based on the levelized cost of hydrogen (LCOH) for the different electrolysis technologies as well as, steam methane reforming, black coal and lignite gasification with carbon capture and sequestration. The price is equivalent to a Free on Board (FOB) or at wellhead price. The model was built to replicate the Commonwealth Scientific and Industrial Research Organization (CSIRO) LCOH for the mentioned technologies, which was then used to model the price for green and blue hydrogen across the seven states and territories. Since the model is based on LCOH it does not incorporate additional costs such as transport or company overheads and market forces such as supply and demand. A comparison of the hydrogen price for various generation methods across the states and territories of Australia was generated and analyzed. The key observations from the results include: 1) there is neither a leading technology nor a leading territory for the low or high hydrogen price; 2) variations in energy commodity prices are directly linked to the hydrogen price and the main factor to consider with green hydrogen production; 3) decreases in costs suggest efficiencies in technology across the green and blue hydrogen industry are starting to be realized; 4) short-term volatility is expected as the industry develops but over the longer term the price should stabilize towards the lower end of the range. With Japan is a strong partner aiming to reach hydrogen cost of A$3/kg., Australia must reduce the hydrogen production cost as much as possible to keep its competitive advantage amongst competitors. This paper will describe the hydrogen price calculation process, the variables, and considerations for each of the seven Australian territories to become the top producer and exporter of the region.