A techno-economic assessment has been carried out to evaluate the economic feasibility of energy self-consumption from a combination of photovoltaics and lead-acid batteries (PV-BAT). The Total annual economic cost (TAEC) and the cost per unit of energy were first calculated, from PV-BAT data collected over a 12 month period and then from energy system model data for the same period. A comparison of the actual renewable energy yield to optimal model output revealed that energy was restrained partially due to limited storage resources. The cost per kilowatt-hour for the two examined scenarios ranged from 0.55 to 0.62 €/kWh and from 0.42 to 0.46 €/kWh, respectively, showing room for further cost reductions. Despite currently lower energy purchasing costs from electricity providers, these findings constitute a significant price indication of the kilowatt-hour produced by PV-BAT, showing the need for further investigation into how battery sizing can be optimized and battery cost can be reduced.

Electricity supply in nonelectrified areas can be covered by distributed renewable energy systems. The main disadvantage of these systems is the intermittent and often unpredictable nature of renewable energy sources. Moreover, the temporal distribution of renewable energy may not match that of energy demand. Systems that combine photovoltaic modules with electrical energy storage (EES) can eliminate the above disadvantages. However, the adoption of such solutions is often financially prohibitive. Therefore, all parameters that lead to a functionally reliable and self-sufficient power generation system should be carefully considered during the design phase of such systems. This study proposes a sizing method for off-grid electrification systems consisting of photovoltaics (PV), batteries, and a diesel generator set. The method is based on the optimal number of PV panels and battery energy capacity whilst minimizing the levelized cost of electricity (LCOE) for a period of 25 years. Validations against a synthesized load profile produced grid-independent systems backed by different accumulator technologies, with LCOEs ranging from 0.34 EUR/kWh to 0.46 EUR/kWh. The applied algorithm emphasizes a parameter of useful energy as a key output parameter for which the solar harvest is maximized in parallel with the minimization of the LCOE.

Salinity gradient energy (SGE) plants generate power from the mixing of salt water and fresh water using advanced membrane systems. In the Strymon River, under low-flow conditions, a salt wedge is formed, developing a two-layer stratified system, which could be used to extract SGE. In this paper, a novel study was implemented by coupling a 3D hydrodynamic model simulating the salt wedge flow, with the SGE model which assesses the net energy produced by a 1 MW SGE plant. Two scenarios were followed: (a) the optimal scenario, operating throughout the year by mixing salt water from the sea (38.1 g/L) and fresh water (0.1 g/L) from the river to produce 4.15 GWh/yr, and (b) the seasonal scenario, utilizing the salinity difference of the salt wedge. Results show that the daily net SGE production varies between 0.30 and 10.90 MWh/day, in accordance with the salinity difference (ΔS_sw ~15–30 g/L). Additionally, a retrospective assessment (from 1981 to 2010) of the annual and seasonal net energy production was conducted. This analysis illustrates that the salt-wedge formation (spring to late summer) coincides with the period of increased regional electricity demand. In the future, the emerging SGE could serve as a decentralized renewable energy source, enhancing energy security in the region.

Based upon the thermodynamic simulation of a biogas-SOFC integrated process and the costing of its elements, the present work examines the economic feasibility of biogas-SOFCs for combined heat and power (CHP) generation, by the comparison of their economic performance against the conventional biogas-CHP with internal combustion engines (ICEs), under the same assumptions. As well as the issues of process scale and an SOFC’s cost, examined in the literature, the study brings up the determinative effects of: (i) the employed SOFC size, with respect to its operational point, as well as (ii) the feasibility criterion, on the feasibility assessment. Two plant capacities were examined (250 m³·h⁻¹ and 750 m³·h⁻¹ biogas production), and their feasibilities were assessed by the Internal Rate of Return (IRR), the Net Present Value (NPV) and the Pay Back Time (PBT) criteria. For SOFC costs at 1100 and 2000 EUR·kW_el⁻¹, foreseen in 2035 and 2030, respectively, SOFCs were found to increase investment (by 2.5–4.5 times, depending upon a plant’s capacity and the SOFC’s size) and power generation (by 13–57%, depending upon the SOFC’s size), the latter increasing revenues. SOFC-CHP exhibits considerably lower IRRs (5.3–13.4% for the small and 16.8–25.3% for the larger plant), compared to ICE-CHP (34.4%). Nonetheless, according to NPV that does not evaluate profitability as a return on investment, small scale biogas-SOFCs (NPV_max: EUR 3.07 M) can compete with biogas-ICE (NPV: EUR 3.42 M), for SOFCs sized to operate at 70% of the maximum power density (MPD) and with a SOFC cost of 1100 EUR·kW_el⁻¹, whereas for larger plants, SOFC-CHP can lead to considerably higher NPVs (EUR 12.5–21.0 M) compared to biogas-ICE (EUR 9.3 M). Nonetheless, PBTs are higher for SOFC-CHP (7.7–11.1 yr and 4.2–5.7 yr for the small and the large plant, respectively, compared to 2.3 yr and 3.1 yr for biogas-ICE) because the criterion suppresses the effect of SOFC-CHP-increased revenues to a time period shorter than the plant’s lifetime. Finally, the economics of SOFC-CHP are optimized for SOFCs sized to operate at 70–82.5% of their MPD, depending upon the SOFC cost and the feasibility criterion. Overall, the choice of the feasibility criterion and the size of the employed SOFC can drastically affect the economic evaluation of SOFC-CHP, whereas the feasibility criterion also determines the economically optimum size of the employed SOFC.

This paper compares two common dispatch policies—Load-Following (LF) and Cycle-Charging (CC)—for a photovoltaic Battery Energy Storage System (PV–BESS) microgrid (MG) with a 12 kW diesel generator, using a full-year of real 15 min PV and load data from an industrial use case in Germany. A forward time-step simulation enforces the battery State-of-Energy (SoE) window (total basis [20, 100] %, DoD = 80%) and computes curtailment, generator use, and unmet energy. Feasible designs satisfy a Loss of Power Supply Probability (LPSP) ≤ 0.03. Economic evaluation follows an Equivalent Annual Cost (EUAC) model with PV and BESS Capital Expenditure/Operation and Maintenance (CAPEX/O&M) (cycle life dependent on DoD and 15-year calendar life), generator costs, and fuel via SFC and diesel price. A value of lost load (VOLL) can be applied to unserved energy, with an optional curtailment penalty. Across the design space, a clear cost valley appears toward moderate storage and modest PV, with the baseline optimum at ≈56 kWp PV and 200 kWh BESS (DoD = 80%). Both policies meet the reliability target (in our runs LPSP ≈ 0), and their SoE trajectories are nearly identical; CC only lifts the SoE slightly after generator-ON events by using headroom to charge, while LF supplies just the residual deficit. Sensitivity analyses show that the optimum is most affected by diesel price and discount rate, with smaller shifts for ±10% changes in SFC. The study provides a transparent, reproducible workflow—grounded in real data—for controller selection and capacity planning.

Sn/C nanocomposites were synthesized by thermal decomposition of precursor mixtures comprising SnO₂ and gluconic acid (GA). The resulting Sn/C material is composed of Sn nanoparticles (60–100 nm) embedded within a carbonaceous matrix. The effect of electrolyte composition and the initial charging break-in current density on the formation and stability of the solid electrolyte interphase (SEI) has been studied and discussed under varying solutions of ethyl-, dimethyl- and vinylene-carbonates. A thin and stable SEI of high ionic conductivity is formed by reduction of vinylene carbonate at increased break-in current densities as high as 800 mA g⁻¹. It is proposed that a certain amount of inserted Li species forms a stable LiSn adduct during the initial charging period, which acts as the substrate phase into which Li⁺ is reversibly and efficiently inserted. The Sn/C nanocomposite interphased with a solvent containing 10% vinyl-carbonate delivers a reversible and stable capacity of 400 mAh g⁻¹ for over 200 cycles.