Pablo Benalcazar

Techno-economic aspects of green hydrogen production play a significant role in shaping the development and deployment of new hydrogen facilities. Comprehensive analyses of cost components that impact the levelized cost of green hydrogen have become increasingly important for supporting investment strategies and production planning processes. Furthermore, these analyses have proven valuable in decision-making processes related to the establishment of support mechanisms that ensure the sustainable energy transition of national and local power, heating, and transport sectors. This chapter identifies and discusses various metrics and factors affecting the nascent green hydrogen market. Additionally, this chapter is devoted to identifying the current economic trends and future prospects of green hydrogen production technologies, specifically alkaline, proton exchange membranes, and solid oxide water electrolysis powered by renewable energy sources. Finally, the chapter analyzes existing policy efforts and various policy instruments to promote green hydrogen as a critical element in the decarbonization of global economies.

The development of the European PV market has shown the strong potential for using grid-connected solar PV systems operated simultaneously with battery storage. Since 2018, an important policy measure for the enhanced deployment of small-scale photovoltaic installations in Poland has been the grant support program “My electricity”. Starting from April 2022, the program provides financial support to projects that include energy storage systems. In this context, this study contributes to the literature on the acceptance and uptake of PV-battery systems in Poland by evaluating the effect of tariff incentives on the optimal operation of grid-connected residential PV-battery systems. The developed framework addresses the uncertainty of PV power generation and demand using predictive models based on LSTM neural networks. An optimization component is developed to capture the effect of battery degradation and ensure the effective utilization of the PV-battery system. The results indicate that installing a PV system in a residential home reduces the energy bill by 40%, from € 475.53 to € 287.18. Moreover, the quantitative analysis indicates that the potential adoption of a feed-in tariff that mimics the current prosumer policy in Germany and the coupling of battery systems would cause fundamental changes in the grid utilization of Polish households.

The uncoordinated development of a green hydrogen economy could potentially have far-reaching geopolitical implications. The differential access to resources and technologies will affect the import-export relations between countries. This study presents a techno-economic analysis of large-scale green hydrogen production systems in countries that may emerge as major clean hydrogen producers and exporters (Australia, Chile, Morocco, and Colombia). Additionally, it investigates the impact of different uncertainties on their levelized costs of hydrogen (LCOH) and provides a comparative analysis of local wind and solar resources. The uncertainties encompass factors influencing the LCOH, including electricity and water prices, capital, operational, and replacement costs, utilization rates, efficiency ratios, and system lifetime. A Monte Carlo simulation was developed and employed for the techno-economic assessment of large-scale hydrogen production systems in seventy-six spatially distributed sites. The results indicate that Chile has the potential to produce green hydrogen at the lowest cost (2.8–4.5/kg in 2030). The LCOH in Morocco may range from 3.2 to 3.5/kg, Australia from 3.2 to 3.6/kg, and Colombia from 4.1 to $4.9/kg by 2030. The simulations indicate that the LCOH is most sensitive to changes in specific investment costs and the utilization rates of electrolyzers, regardless of the country and scenario examined.

Solar photovoltaic capacities have experienced remarkable gains worldwide. The accelerated deployment of photovoltaic (PV) systems has emphasized the need for methods and tools that can assist in planning and investment decisions of utility-scale photovoltaic systems to ensure a sustainable energy transition. This study bridges the gap between research and current solar PV project evaluation practices by proposing a geographic information system (GIS)-based approach for analyzing land eligibility and performing techno-economic assessments of utility-scale photovoltaic systems. To tackle the issue of country-specific cost elements, the model incorporates a levelized cost of electricity (LCOE) breakdown often used by governmental and intergovernmental organizations. The proposed GIS-based model can assist in mapping the distribution of eligible land for utility-scale solar systems while considering exclusion constraints, estimating PV capacity and generation potentials, as well as determining the average LCOE of utility-scale solar photovoltaic systems at a spatial resolution of 100 m. The GIS-based approach is demonstrated through the case study of Poland. The model estimates that 3.61% of the total area of Poland is suitable for the installation of utility-scale solar PV systems. Implementing PV installations in these areas would result in solar capacities ranging from 394.64 to 563.77 GW. Furthermore, the findings of the case study indicate that the LCOE would range from €0.043/kWh to €0.049/kWh, with a national average of €0.045/kWh. The proposed approach can be utilized to develop national and regional strategies focused on large-scale PV installations, facilitating the attainment of renewable energy goals. The study fills a significant gap in the literature as it provides a GIS-based tool for planning the sustainable development of utility-scale PV systems at the regional scale. In addition, it is the first to comprehensively assess the capacity and generation potential of utility-scale solar photovoltaics in Poland at the NUTS-2 level.

The European Commission’s plan to decarbonize the economy using innovative energy carriers has brought into question whether the national targets for developing electrolysis technologies are sufficiently ambitious to establish a local hydrogen production industry. While several research works have explored the economic viability of individual green hydrogen production and storage facilities in the Western European Member States, only a few studies have examined the prospects of large-scale green hydrogen production units in Poland. In this study, a Monte Carlo-based model is proposed and developed to investigate the underlying economic and technical factors that may impact the success of the Polish green hydrogen strategy. Moreover, it analyzes the economics of renewable hydrogen at different stages of technological development and market adoption. This is achieved by characterizing the local meteorological conditions of Polish NUTS-2 regions and comparing the levelized cost of hydrogen in such regions in 2020, 2030, and 2050. The results show the geographical locations where the deployment of large-scale hydrogen production units will be most cost effective.

In the next decades, energy storage technologies will play a major role in decarbonizing the European heating and cooling sector. In this regard, the deployment of complementary technologies is of paramount importance for the energy transformation of the Polish heating sector. This work addresses the challenge of sizing large-scale thermal energy storage (TES) systems for combined heat and power (CHP) plants connected to district heating networks and participating in day-ahead electricity markets. In this paper, a method based on a mixed-integer linear programming approach is proposed to find the optimal capacity of TES units connected to coal-fired CHP systems. The model considers the specific investment costs of the storage technology and optimizes the annual operation scheduling of the CHP-TES system. The model is applied to the case study of a coal-fired CHP system. Four scenarios are used to investigate the performance of the CHP system and evaluate the effects of rising carbon prices on the optimal capacity of the TES unit. The results reveal that the integration of the TES leads to a significant drop in the utilization of the heat-only boilers, helping mitigate fuel and environmental costs.

Thermal energy storage technologies are of great importance for the power and heating sector. They have received much recent attention due to the essential role that combined heat and power plants with thermal stores will play in the transition from conventional district heating systems to 4th and 5th generation district heating systems. This paper presents a novel decision support method for sizing and optimizing the operation of thermal energy storage units in combined heat and power plants. To achieve this goal, the method in this paper comprises three steps. The first step provides an approximation of the storage capacity based on the characterization of the thermal load. The second step extends the applicability of the method by enabling the evaluation of the hourly operation of the combined heat and power plant with thermal storage. The third step evaluates the long-term economic effects of retrofitting the combined heat and power plant with a heat storage option. The applicability of the method is illustrated using the example of a coal-fired combined heat and power plant and the study of two scenarios. The analysis of the scenarios shows that the utilization of the energy storage enhances the operational flexibility of the system by increasing the number of hours in which the combined heat and power plant operates at its maximum electrical output and, at the same time, reduces the thermal contribution of the heat-only boilers. The method developed in this work can be applied to carry out the financial analysis of an energy storage project.

Combined heat and power (CHP) have been internationally recognized as a low-carbon electricity technology that will transform the way future power systems operate. In the last two decades, technological advances in energy storage technologies have accelerated their integration with CHP plants and district heating systems. As the importance of energy storage becomes more apparent, and the prospects of new revenue streams for energy companies expand, several questions have been asked by relevant stakeholders regarding the potential economic and operational effects of integrating CHP plants and energy storage units. Furthermore, a major challenge in future decades is the decarbonization of heat production, one of the most energy-intensive sectors in the world. A potential solution for the mitigation of carbon emissions and air pollutants is the deployment of systems comprised of or integrated with combined heat and power technologies. This chapter presents a Mixed Integer Linear Programming (MILP) approach for solving the operation planning problem (commonly referred in the literature as “day plan”) of a coal-fired CHP system. The system comprises a CHP plant (equipped with an extraction-condensing steam turbine driven by two pulverized coal-fired boilers), two auxiliary boilers and a tank thermal energy storage. The objective of the mathematical model is the minimization of the operating costs of the CHP system considering the heat demand of a district heating network and the potential revenues from the sales of electricity in the local power market. An illustrative example based on a typical cogeneration system operating in Central and Eastern Europe is used to demonstrate the applicability of the proposed approach. Two scenarios are investigated to highlight the advantages of the model in dealing with the co-optimization of heat and power.