Search Results (146)

This study investigates how the hydrogen supply chain should be designed under alternative carbon tax scenarios to decarbonize heavy-duty freight transportation. A bi-objective, multi-period optimization model is developed to minimize the total daily system cost while constraining CO₂ emissions using the Augmented ε-constraint approach, thereby revealing the trade-off between economic and environmental objectives. The model was applied to Türkiye’s heavy-duty transportation sector and solved under zero, moderate, and aggressive carbon tax scenarios. The results show that the levelized cost of hydrogen (LCOH) ranges from 2.06 to 14.06 $/kg H₂. High carbon pricing increases the LCOH by 29.06% in hybrid designs, while raising the renewable energy share from 2.04% to 46.97% in centralized supply chains. Sensitivity analysis reveals that a ±20% variation in electrolyzer-based production costs does not alter the network topology but shifts the LCOH between 13.10 and 15.02 $/kg H₂ in emission-focused solutions. The findings indicate that in renewable-energy-based decentralized structures, higher carbon tax policies primarily increase the LCOH. Still, the overall technology mix and network topology remain largely unchanged compared to the no-tax case. However, in centralized supply chains, carbon pricing affects both the energy sources and selected technologies. By integrating Türkiye’s 2030–2053 policy milestones into a multi-period framework, this study distinguishes itself by providing a comprehensive, multi-period planning framework tailored to the economic and logistical realities of developing countries. Unlike existing models, our approach quantifies how evolving carbon tax trajectories decisively drive infrastructure investment by analyzing the direct impact of different tax levels on the operational and strategic decisions of heavy-duty transport. This research represents the first joint assessment of carbon tax policy instruments and the evolution of long-term hydrogen supply chains, offering a decision-making framework for policy-driven energy transitions in similar emerging economies. Full article

Industrial heat demand is a major source of CO₂ emissions, making the decarbonization of this sector essential for achieving sustainability. This study explores and compares different methods for supplying useful heat to the industrial sector through a multi-criteria approach that considers technical performance, economic viability, and environmental impact. Both conventional and alternative systems are examined, aiming to develop sustainable designs. These include solar-based systems using parabolic trough collectors, supported by either electric heaters or natural gas boilers. In addition, a high-temperature heat pump (HTHP) utilizing waste heat is analyzed, also combined with either electric heaters or gas boilers as backup. For reference, a conventional natural gas boiler system is included as a baseline case. In total, five scenarios are evaluated for applications in the chemical industry. Each scenario is assessed in terms of energy and exergy efficiency, cost, and CO₂ emissions. A multi-criteria analysis is then applied to determine the most sustainable option under varying electricity and waste heat price conditions. The results indicate that the configuration combining a high-temperature heat pump with electric heaters (Scenario 3) achieves the highest performance, with energy and exergy efficiencies of 0.952 and 0.666, respectively. The lowest CO₂ emissions are observed in the case of using solar collectors with electric heaters (Scenario 1), reaching 4154 tons per year. From an economic perspective, Scenario 3 emerges as the most favorable option at lower electricity prices (0.10 €/kWh), with a levelized cost of heating (LCOH) of 0.0555 €/kWh. At higher electricity prices, the optimal design shifts to Scenario 2, which combines solar collectors with a natural gas boiler, resulting in an LCOH of 0.0603 €/kWh. Full article

The main challenge of hydrogen electrolysis lies in the high cost of hydrogen production. Achieving a decarbonized energy sector requires substantial investment to shift from carbon-intensive technologies to more sustainable alternatives. However, investment decisions in this context remain complex and uncertain. Currently, green hydrogen projects account for more than 500 initiatives worldwide and are expected to expand rapidly in the coming years. Evidence from feasibility studies suggests that green hydrogen produced from renewable energy is already technically viable and is approaching economic competitiveness. The current emphasis is on large-scale deployment and learning-by-doing processes to reduce electrolyzer costs and improve supply chain efficiency. This transition requires appropriate funding mechanisms, often involving significant public sector participation alongside private investment. This study analyzes the financing structures of green hydrogen projects in Germany, Australia, and Brazil using Principal Component Analysis (PCA) to identify the most relevant combinations of technical, economic, and financial variables. Unlike previous studies that address technical, economic, and financial dimensions in isolation, this study offers an integrated, empirically grounded analysis at the project level, combining cross-country comparison with a multivariate approach. The results indicate that project characteristics are strongly associated with capital intensity and financing structures, while cost variables such as levelized cost of hydrogen (LCOH) play a secondary role in explaining variation across projects. These findings suggest that financing arrangements—particularly those involving public support mechanisms—are closely associated with project configuration in this emerging sector. However, these results should be interpreted as patterns of statistical association rather than evidence of causal relationships. Overall, the analysis highlights the importance of coordinated financing strategies in supporting the development of green hydrogen and its potential contribution to emissions reduction in line with the Paris Agreement and the transition toward climate neutrality. Full article

The day-ahead scheduling of multi-stack Power-to-X (PtX) plants must simultaneously cope with stack degradation under variable loading and with compound uncertainty in renewable generation and electricity prices. Existing scheduling frameworks address these two challenges in isolation, since degradation-aware models remain deterministic and stochastic models treat the electrolyser as a constant-efficiency device. This work develops a degradation-aware two-stage stochastic mixed-integer linear programming (MILP) framework that closes this gap. First-stage binaries fix the commitment and startup decisions of every stack, while second-stage scenario-indexed variables capture the dispatch, the hydrogen output, the shortfall, and the load-dependent and start–stop cycling degradation cost monetised at the stack level through a piecewise linear epigraph. Joint wind price uncertainty is represented by a Gaussian copula fitted on empirical CDF marginals and reduced to twenty representative scenarios via k-medoids clustering. The framework is fully implemented in MATLAB R2024a with the Optimization Toolbox, using the built-in intlinprog and linprog solvers. On a 100 MW reference plant with ten heterogeneous PEM stacks, out-of-sample evaluation against four formal benchmarks demonstrates the lowest LCOH at EUR 24/kg, the highest demand reliability at 85.0%, the highest hydrogen delivery at 7.68 t/day, and up to 50% total cost reduction over deterministic baselines, with end-to-end runtime under two minutes on standard workstation hardware. Full article

China is the world’s largest producer of hydrogen, and it has the potential to export renewable hydrogen and its derivatives. Japan has set ambitious targets for developing a hydrogen-based society but is facing cost challenges. There is strong potential for China and Japan to cooperate regarding renewable hydrogen across the value chain. This study evaluates the cooperation opportunities from the 3E perspective (energy security, economics, and the environment). It estimates the renewable hydrogen production potential in both countries, as well as the economics and greenhouse gas (GHG) emissions associated with the production and export of renewable hydrogen from China to Japan using proton exchange membrane (PEM) technology. The renewable hydrogen production potential in China is estimated to be 12.00 Mt/year by 2035 in the base case of this study, providing a strong foundation for exports to Japan. The levelized cost of hydrogen (LCOH) using PEM technology and onshore wind is estimated at 4.27 USD/kg H₂ in China and 11.01 USD/kg H₂ in Japan for projects built in 2025. Even after accounting for liquefaction costs in China, transport costs from China to Japan (Chifeng—Dalian—Kobe) and regasification costs in Japan, renewable hydrogen produced in China remains more cost-effective than that produced in Japan. In terms of GHG emissions, when renewable hydrogen is produced using wind power, and wind power is also used for liquefaction and other electricity-consuming processes, the total emissions within the case study boundary amount to 2.24 kg CO₂-eq/kg H₂, below Japan’s low-carbon hydrogen threshold of 3.4 CO₂-eq/kg H₂. This study also discusses the challenges which are critical to facilitating cooperation, particularly in regards to coordinating standards and certification systems between the two countries. Full article

This study explores a photovoltaic/thermal (PV/T)-based electrolysis system designed for dual production of hydrogen fuel and domestic hot water (DHW), providing a sustainable energy solution amid rising global emissions. A dynamic rule-based control mechanism with hysteresis thresholds on hydrogen-storage state of charge (SoC) is implemented to balance electrolyzer operation with intermittent solar availability, maintaining PV/T power outputs while preventing storage overfilling and minimizing start–stop cycling. The system is assessed across 27 geographically diverse cities spanning a wide range of solar irradiation and energy price structures. Annual hydrogen yields range from 20 kg/yr in high-latitude locations (Helsinki, Stockholm) to 33.5 kg/yr in high-irradiation regions (Riyadh, Abu Dhabi), while the levelized cost of hydrogen (LCOH) spans from 6.47 USD/kg (Riyadh) to 22.86 USD/kg (Helsinki). Economically, the system achieves its strongest performance in solar-rich, high-energy-cost environments: Rome records the highest net annual cash flow (858.9 USD/yr) and shortest payback period (2.47 years), followed by Davos, Madrid, Brasília, and Canberra. In contrast, locations with subsidized energy tariffs—such as Algiers, Kyiv, and Tehran—yield low or negative net cash flows, rendering the system economically unviable without policy support. Environmental analysis reveals annual CO₂ avoidance ranging from 0.33 ton/yr (Stockholm) to 2.97 ton/yr (Riyadh), with a global mean of 1.095 ton/yr and a combined total of approximately 29.6 tons/yr across all examined sites. A machine learning model is developed to generalize performance predictions across unseen locations, achieving leave-one-out (LOO) R² values of 0.953 (net cash flow), 0.935 (LCOH), and 0.947 (LCO-DHW), with mean absolute errors below ±1 USD/kg and ±0.03 USD/kWh. The findings confirm that, under fixed capital cost assumptions, local electricity price and solar irradiation are the dominant drivers of economic viability, while grid carbon intensity and solar resource jointly govern environmental performance, with markets offering irradiation above 1500 kWh/m²·yr and electricity prices exceeding 0.2 USD/kWh representing the most promising deployment targets. Full article

Chile is widely regarded as a key global player in green hydrogen production due to its exceptional renewable energy potential, which enables low-carbon and competitive production costs. This article provides a comprehensive review of Chile’s green hydrogen sector, evaluating the transition from early strategic goals to the current phase of industrial scaling. It offers an integrated analysis of the regulatory framework, infrastructure deployment, and the techno-economic variables essential for integrating Chilean derivatives into global markets. The country has established a supportive framework through its National Green Hydrogen Strategy (NGHS), which sets out goals of 25 GW of installed electrolyzer capacity and USD 2.5 billion in annual exports by 2030. Despite these ambitious targets, actual deployment remains in the early stages, with only 3.9 GW currently in the implementation phase and a lack of fully operational industrial-scale facilities. Furthermore, initial NGHS projections suggested a levelized cost of hydrogen (LCOH) of USD 1.3–1.4/kg by 2030. However, current calculations point to a more complex reality of approximately USD 3.1/kg due to infrastructure bottlenecks and global supply chain pressures. While Chile’s renewable resources ensure low production-stage emissions, the absence of explicit regulatory carbon targets underscores the need for comprehensive life-cycle assessments encompassing manufacturing and global distribution. Overall, this review concludes that Chile should overcome persistent regulatory and logistical constraints to consolidate a robust and internationally competitive green hydrogen sector, aligned with its 2050 carbon neutrality objectives. Full article

This study examines the economics of blue and green hydrogen as feedstock for large industrial facilities in Southeast Asia. To understand how industries can adopt low-emission and renewable hydrogen, the levelised costs of blue and green hydrogen are calculated. Four pathways are examined, including a large-scale carbon capture and sequestration facility located a distance away from an existing steam methane reforming hydrogen plant, a gigawatt-scale electrolysis facility adjacent to a large industrial site fed by an adjacent solar photovoltaic electricity source, as well as two pathways with either remote electrolyser and solar photovoltaic, necessitating hydrogen transport and storage, or a remote solar photovoltaic source with a dedicated power transmission line. The region’s transition to green hydrogen must overcome the challenges of high renewable electricity costs, the need for large land banks for solar photovoltaic farms and efficient long-distance hydrogen transport solutions or power transmission lines. Moreover, the region must improve its inconsistent track record in implementing billion-dollar public–private projects within budget and on time. Full article

Hydrogen-based zero-emission transport technologies have reached a level of technical maturity that enables their operational deployment; however, their large-scale uptake remains constrained by the limited availability of refuelling infrastructure. This gap between technological readiness and infrastructure provision represents one of the main bottlenecks for the transition towards hydrogen-powered mobility systems. In this context, stakeholders evaluate hydrogen deployment through a set of key quality objectives, primarily related to emissions, economic performance, and efficiency. The achievement of these objectives is inherently conditioned by the configuration of the hydrogen value chain and, in particular, by the spatial dimension of infrastructure deployment. Despite its relevance, the combined effect of value chain variables and location-specific factors on quality outcomes remains insufficiently characterised in the literature. To address this gap, this study proposes a probabilistic modelling framework based on Bayesian Networks to capture the relationships between value chain variables, location-dependent conditions, and resulting quality indicators. This approach enables the explicit representation and propagation of uncertainty across the system, providing a robust analytical basis for evaluating alternative infrastructure deployment strategies. By integrating technical, economic, and spatial dimensions within a unified modelling structure, the proposed framework supports informed decision-making in the planning and optimisation of hydrogen refuelling infrastructure. Full article

The transition to a low-carbon building sector will be greatly aided by hydrogen fuel cells. This paper examines their carbon emission reduction and economic advantages via Life Cycle Assessment (LCA) and Levelized Cost of Hydrogen (LCOH), alongside multiple carbon pricing scenarios. When using coal-produced hydrogen as a hydrogen source, hydrogen fuel cell applications have no carbon reduction effect. When hydrogen production from natural gas steam reforming is employed, the carbon reduction per unit of hydrogen in the HFC-CHP system ranges from 2.34 to 4.07 kgCO₂e, with a hydrogen cost per unit between 24.32 and 37.78 RMB/kg. When using blue hydrogen, the carbon reduction increases to 4.70–9.08 kgCO₂e, with costs ranging from 22.86 to 39.97 RMB/kg. Green hydrogen achieves the highest carbon reduction of up to 10.99 kgCO₂e, but costs rise to 47.51 RMB/kg under this pathway. The results revealed that pipeline transport outperforms trailer transport in carbon reduction and economic efficiency at the same distance. Simultaneously, solely incorporating the carbon market as a hydrogen subsidy measure is insufficient to close the cost disparity between hydrogen fuel cell energy supply and traditional energy supply methods. More types of subsidy measures are needed to enhance the competitiveness of hydrogen energy. Full article

Wind curtailment in Great Britain (GB) is increasing, leading to underutilisation of low-carbon energy and higher system costs. This paper develops a data-driven techno-economic framework for a hydrogen generation and storage system that converts curtailed wind energy into hydrogen. By modelling curtailment time series and electricity prices, and considering a proton exchange membrane (PEM) electrolyser-based power-to-gas system, The framework explicitly represents the operation and interaction of the PEM electrolyser, hydrogen compression, and high-pressure storage under time-varying curtailment and electricity price conditions using reconstructed GB curtailment time series. The levelised cost of hydrogen (LCOH), net present value (NPV), and delivered hydrogen volumes are evaluated. A new sizing metric, curtailment utilisation, is introduced to link curtailment availability with electrolyser and storage productivity. Using a GB curtailment dataset, two key relationships are identified. First, increasing access to low-cost curtailed energy reduces the LCOH until electrolyser utilisation saturates, beyond which additional energy purchases provide diminishing benefits. Second, hydrogen storage exhibits an economic optimum: Undersized tanks increase costs due to ramping and venting losses, whereas oversized tanks raise capital investment requirements and increase the LCOH. For the best-performing configuration, corresponding to 70.2 MWh of curtailed energy, a 2.3 MW electrolyser, and a 94 m³ high-pressure tank, the system achieves an LCOH of £3.51/kg H₂ (excluding downstream delivery) and an NPV of £2.17 M and meets 98.01% of the hydrogen demand. These results indicate that optimal system design requires not only appropriate component sizing but also explicit consideration of curtailment profiles and pricing structures. The proposed framework provides decision-grade guidance for developers and policymakers evaluating hydrogen production from wind curtailment. Future work will extend the model to hybridise with other energy storage system technologies, enable revenue stacking across multiple markets, address real-gas storage modelling, examine the sensitivity of stack degradation, and incorporate transport and delivery costs. These findings show that viable hydrogen production from curtailed wind depends on both low-cost electricity and coordinated electrolyser storage sizing under realistic curtailment conditions. The framework provides practical guidance for developers and policymakers. Full article

The article provides a comprehensive overview of the role of hydrogen as a key vector in the decarbonization of the global transport sector. The study situates hydrogen within the broader context of energy transition and climate neutrality targets, emphasizing its potential to replace fossil fuels in road, rail, maritime, and aviation applications. The analysis integrates a review of current technological, infrastructural, and policy developments, covering both combustion-based and fuel-cell hydrogen propulsion systems. Quantitative and qualitative data were assessed from international reports, scientific publications, and ongoing industrial projects to evaluate performance, efficiency, safety, and cost parameters such as Levelized Cost of Hydrogen (LCOH) and Total Cost of Ownership (TCO). The results indicate that while hydrogen remains economically challenging, technological progress in electrolysis, fuel cells, and refueling infrastructure significantly improves its competitiveness, particularly in heavy-duty and long-range transport. The paper highlights the critical role of international strategies, including the European Hydrogen Strategy and Fit for 55 package, in driving market adoption and regulatory alignment. The conclusions suggest that by 2050, hydrogen could contribute up to one-quarter of total transport energy demand, positioning it as a cornerstone of sustainable mobility and a bridge toward a fully decarbonized transport ecosystem. Full article

This study develops a high-resolution techno-economic optimization framework to assess the feasibility of green hydrogen production in 100% renewable, off-grid systems. Utilizing 5-minute interval meteorological data aggregated to hourly resolution spanning 5 years across seven geographically diverse sites, this study co-optimizes the integration of hybrid wind–solar power generation, flexible electrolyzer operation, and a multi-timescale energy storage portfolio, incorporating short-duration, long-duration, and seasonal storage. On the generation side, a hybrid wind–solar configuration achieves the lowest levelized cost of hydrogen (LCOH). For energy storage, no single storage technology can economically address demand fluctuations across short-term, medium-term, long-term, and seasonal timescales. Instead, a coordinated multi-timescale storage strategy incorporating energy-to-energy mechanisms reduces the LCOH by up to 40%. Increasing hydrogen tank capacity and enabling flexible electrolyzer operation further lowers the LCOH. Significant regional resource variability leads to substantial cost disparities, with the most favorable region achieving a low LCOH of $2.45/kg. Several regions are projected to reach the $3/kg target by 2030, while areas with limited resources require large-scale hydrogen storage to ensure supply reliability. These results represent deterministic lower-bound estimates under perfect foresight; accounting for forecast uncertainty and real-world operational constraints would likely increase actual costs by approximately 5–15%. Full article

The decarbonization of hard-to-abate sectors remains a significant challenge in achieving net-zero emissions targets. These industries depend on energy-dense fuels, making direct electrification and the direct use of hydrogen technically and economically challenging. Electrofuels present a promising pathway to reducing emissions while leveraging surplus renewable energy. This review evaluates the feasibility of electrofuels for deep decarbonization, focusing on production processes, energy demands, and economic viability. Environmental performance is discussed in terms of lifecycle greenhouse gas (GHG) emissions, carbon circularity considerations, and energy conversion efficiencies, while techno-economic feasibility is evaluated using metrics such as levelized cost of hydrogen (LCOH), CO₂ capture costs, and projected fuel production costs. The review indicates that while electrofuels can achieve substantial lifecycle emission reductions up to 40–90%, depending on pathway and electricity source, their deployment remains constrained by high energy demand, conversion losses, and capital costs. Projected reductions in LCOH to below $2.1/kg by 2030 and declining renewable electricity costs could significantly improve competitiveness, particularly in regions with abundant solar and wind resources. However, substantial trade-offs exist between efficiency, infrastructure compatibility, scalability, and carbon neutrality across different electrofuel routes. The review identifies key technological bottlenecks, cost drivers, and research priorities necessary to position electrofuels as a strategic solution for deep decarbonization in sectors where direct electrification is not feasible. Full article

This study compares hydrogen production pathways from water—using renewable-powered electrolysis (alkaline, water-based)—and biomass (gasification), under harmonized system boundaries and a common functional unit of 1 kg H₂ at 99.97% purity. It examines technological efficiency and environmental impacts, including cradle-to-gate Life Cycle Assessments (LCAs) of each pathway, focusing on global warming potential (GWP100), water consumption, land use, acidification, cumulative energy demand, and the critical minerals footprint. The analysis highlights the roles of water electrolysis and biomass gasification within South Africa’s energy landscape, considering the integration of renewable electricity, energy quality, and co-product allocation. Economic factors, such as the Levelized Cost of Hydrogen (LCOH), are evaluated alongside environmental indicators. The study emphasises the environmental challenges of biomass gasification, notably water use and emissions, and contrasts these with the climate benefits of renewable-powered electrolysis. It also reviews policy initiatives and government programs that support hydrogen and sustainable energy in South Africa, aligning with the SDGs. Overall, the findings underscore the trade-offs in hydrogen development, emphasising opportunities for resource utilisation while addressing deployment challenges. Full article