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The mass introduction of variable renewable energies, including wind and solar photovoltaic, leads to additional costs caused by the intermittency. Many recent studies have addressed these “integration costs,” and proposed novel metrics that replace the traditional metric known as the levelized cost of electricity (LCOE). However, the policy relevance of those metrics remains unclear. In this study, the author investigates and re-defines the concept of system LCOE, referring to prior studies, and proposes concrete methods to estimate them. Average system LCOE allocates the integration cost to each power source, dividing that by the adjusted power output. Marginal system LCOE revises the concept of system LCOE and value-adjusted LCOE proposed by prior studies, to be clearer and more policy-relevant. These metrics are also applied to Japan’s power sector in 2050, suggesting the necessity of aiming for a “well-balanced energy mix” in future power systems with decarbonised power sources.

Background In an attempt to realize the most beneficial and optimal mix of electricity generation in Niger, a society’s cost of electricity (SCOE) as the levelized cost of electricity (LCOE) plus the cost of climate change and air pollution is formulated. The SCOE is used as a basis for setting the performance criteria for supply optimization to balance future electricity demand in Niger. The demand projection is derived from a system dynamics model that anticipates future changes based on its influencing factors of population growth, urbanization progress, and industrial development. Results Reference case and what-if scenarios are simulated to see the projected electricity demand and possible renewable energy transition pathways. As a result, for example, the annual electricity of 3214 GWh estimated for 2030 might be balanced with about 200 MW, 104 MW, 85 MW, and 63 MW power from hydropower, grid-tied PV, coal, and diesel for SCOE optimized grid. For the same case, a greenhouse gas (GHG) emission reduction of 11.26–15.66% could be achieved when compared to the LCOE-based optimized grid. In addition, the most preferred energy option hydropower will be almost exhausted when the projected electricity demand in 2035 reaches slightly more than double its value in 2025. Thus, Niger should start exploiting its solar as well as conventional sources intensively to balance its future energy demand. Conclusions In this work, a mixed energy grid is optimized primarily on affordability while considering its sustainability. The implemented holistic approach lessens the need for energy import in the country and provides relief to energy security issues such as electricity price volatility and supply reliability. Additionally, the proposed strategy helps to guide the renewable energy transition pathway in Niger.

Economic feasibility studies of concentrated solar power (CSP) plants with thermal energy storage (TES) systems have been mainly based on the levelized cost of electricity (LCOE), disregarding the economic benefits to the electricity system resulting from the dispatchability of the CSP plants. The analysis of these benefits is essential since the existence of storage can provide greater operating flexibility to the system. Although there are few studies on the benefits of CSP plants in thermoelectric systems, this analysis has not yet been done in a predominantly hydroelectric system. In this paper, CSP plants with TES systems were inserted in a hydrothermal system in order to estimate the economic benefits and the net cost of electricity generated by those plants. The System Advisor Model (SAM) and the hydrothermal scheduling model DESSEM were used in a real case study of inclusion of CSP plants in the Brazilian system. The results indicate that the cost of a CSP plant, previously estimated by the LCOE, can be reduced by at least 37% when considering its benefits to a hydrothermal system, increasing its competitiveness with other technologies. Therefore, we propose the use of the net cost for an appropriate comparison among energy sources.

A solar thermal wind tower (STWT) is a low-temperature power generation plant that mimics the wind cycle in nature, comprising a flat plate solar air collector and central updraft tower to produce thermal wind that drives turbines to generate electricity. The development of power generation systems toward a sustainable future needs to be made taking into account the balance between environmental impact and economic feasibility. We examine the sustainability of STWT power generation technology using the inclusive impact index light (Triple I-light), which estimates whether it is good to do the project, including both the negative environmental impact and the economic aspect. Environmental disadvantages are discussed by performing a CO2 inventory analysis for the life-cycle of the STWT power plant. Evaluation of the economic feasibility is done by calculating the levelized electricity cost (LEC), which is the cost per unit of electricity generated. From the calculations, it is found that overall system efficiency is increased by enlarging the capacity, the negative environmental impact by the STWT plant comes mainly from manufacturing stage (more than 60%), and the levelized electricity cost is dramatically decreased by enlarging the capacity of the system (about 50% reduction). A negative value of Triple I (meaning it is sustainable) can be achieved for high power generation capacity (above 100 MW). Moreover, this paper discusses the implementation and the potential of constructing offshore STWTs.

As more companies strive for net-zero emissions, mitigating indirect greenhouse gas emissions embedded in value chains—especially in logistics activities—has become a critical priority. In the European logistics sector, sustainability and energy efficiency are receiving growing attention, given the sector’s intersectional role in both transportation and construction. This transition toward low-carbon logistics design not only reduces carbon emissions but also yields financial benefits, including operational cost savings and new market opportunities. This study examines the impact of passive design strategies and low-carbon technologies in a Swedish logistics center, assessed using the low-carbon design criteria from the BREEAM International standard, version 6. The findings show that passive energy-efficient measures, such as the installation of 47 skylights for natural daylighting, reduced light power density in accordance with AHSHARE 90.1-2019 and the integration of free night flushing, contribute to a 23% reduction in total energy consumption. In addition, the integration of 600 PV panels and 480 batteries with a capacity of 268 ampere-hours and 13.5 kWh storage, operating at 50 volts, delivers a further 56% reduction in carbon emissions. By optimizing the interaction between passive design and active low-carbon technologies, this research presents a comprehensive feasibility analysis that promotes sustainable logistics practices while ensuring a future-proof, low-carbon operational model.

Energy storage will be required over a wide range of discharge durations in future zero-emission grids, from milliseconds to months. No single technology is well suited for the complete range. Using 9 years of UK data, this paper explores how to combine different energy storage technologies to minimize the total cost of electricity (TCoE) in a 100% renewable-based grid. Hydrogen, compressed air energy storage (CAES) and Li-ion batteries are considered short-, medium-, and long-duration energy stores, respectively. This paper analyzes different system configurations to find the one leading to the lowest overall cost. Results suggest that the UK will need a storage capacity of ~66.6 TWh to decarbonize its grid. This figure considers a mix of 85% wind + 15% solar-photovoltaics, and 15% over-generation. The optimum distribution of the storage capacity is: 55.3 TWh in hydrogen, 11.1 TWh in CAES and 168 GWh in Li-ion batteries. More than 60% of all energy emerging from storage comes from medium-duration stores. Based on current costs, the storage capacity required represents an investment of ~£172.6 billion, or approximately 8% of the country’s GDP. With this optimum system configuration, a TCoE of ~75.6 £/MWh is attained.

Microgrids are an emerging technology that offers many benefits compared with traditional power grids, including increased reliability, reduced energy costs, improved energy security, environmental benefits, and increased flexibility. However, several challenges are associated with microgrid technology, including high capital costs, technical complexity, regulatory challenges, interconnection issues, maintenance, and operation requirements. Through an in-depth analysis of various research areas and technical aspects of microgrid development, this study aims to provide valuable insights into the strategies and technologies required to overcome these challenges. By assessing the current state of microgrid development in Pakistan and drawing lessons from international best practices, our research highlights the unique opportunities microgrids present for tackling energy poverty, reducing greenhouse gas emissions, and promoting sustainable economic growth. Ultimately, this research article contributes to the growing knowledge of microgrids and their role in addressing global sustainability issues. It offers practical recommendations for policymakers, industry stakeholders, and local communities in Pakistan and beyond.

Evaluation of economic aspects is one of the main milestones that affect taking rapid actions in dealing with GHGs mitigation; in particular, avoiding CO2 emissions from large source points, such as power plants. In the present study, three kinds of capturing solutions for coal power plants as the most common source of electricity generation have been studied from technical and economic standpoints. Aspen HYSYS (ver.11) has been used to simulate the overall processes, calculate the battery limit, and assess required equipment. The Taylor scoring method has been utilized to calculate the costliness indexes, assessing the capital and investment costs of a 230 MW power plant using anthracite coal with and without post-combustion, pre-combustion, and oxy-fuel combustion CO2 capture technologies. Comparing the costs and the levelized cost of electricity, it was found that pre-combustion is more costly, to the extent that the total investment for it is approximately 1.6 times higher than the oxy-fuel process. Finally, post-combustion, in terms of maturity and cost-effectiveness, seems to be more attractive, since the capital cost and indirect costs are less. Most importantly, this can be applied to the existing plants without major disruption to the current operation of the plants.

Electricity access and reliability in Nigeria is poor due to obsolete power distribution infrastructure. This could be improved by deploying wind energy resources. The present research assessed the thermo-economic, advanced and extended exergy analysis of deploying wind turbine for distributed generation in four Nigerian locations. The air temperature and wind speed of the sites was used together with Weibull statistical parameters to mathematically model the thermodynamic performance of selected wind turbine for the sites. The results show that the energy and standard exergy efficiency of the sites ranges from 0.16 – 0.44, 0.05 – 0.37, 0.23 –0.39, 0.26 – 0.37 and 0.12 –0.33, 0.04 – 0.25, 0.17 – 0.28, 0.18 – 0.28 respectively for Enugu, Kaduna, Katsina and Jos. The exergy efficiency based on the extended exergy analysis (EEA) approach was found to be much lower than the standard exergy efficiency for all the sites. Based on EEA, Enugu, Kaduna, Katsina and Jos has exergy efficiency of 1.05, 0.73, 2.52 and 3.22 % respectively. Economic performance results showed that Jos is the best site with least monthly average COE value of 0.15$/kWh which compares closely with global average COE value of 0.14 $ /kWh for households. Katsina and Enugu have a COE value of 0.19 and 0.84$/kWh respectively while Kaduna is the worst in performance with highest COE value of 1.13 $ /kWh. 

This paper investigates a comparative study for practical optimal sizing of rooftop solar photovoltaic (PV) and battery energy storage systems (BESSs) for grid-connected houses (GCHs) by considering flat and time-of-use (TOU) electricity rate options. Two system configurations, PV only and PV-BESS, were optimally sized by minimizing the net present cost of electricity for four options of electricity rates. A practical model was developed by considering grid constraints, daily supply of charge of electricity, salvation value and degradation of PV and BESS, actual annual data of load and solar, and current market price of components. A rule-based energy management system was examined for GCHs to control the power flow among PV, BESS, load, and grid. Various sensitivity analyses are presented to examine the impacts of grid constraint and electricity rates on the cost of electricity and the sizes of the components. Although the capacity optimization model is generally developed for any case study, a grid-connected house in Australia is considered as the case system in this paper. It is found that the TOU-Flat option for the PV-BESS configuration achieved the lowest NPC compared to other configuration and options. The optimal capacities of rooftop PV and BESS were obtained as 9 kW and 6 kWh, respectively, for the PV-BESS configuration with TOU-Flat according to two performance metrices: net present cost and cost of electricity.