The development and testing of small concentrating PV systems

Spreadsheets have been used to compare some 90 possible small PV concentrator designs that might be suitable for use at remote sites. They have apertures of about 2 m², use BP Solar LBG cells, and employ small aperture modules to reduce heat sinking and construction costs. Designs include fixed V-troughs and CPCs, single axis tracked cylindrical lens and mirror systems, and two-axis tracked spherical-symmetry systems. Performance and volume production costs were estimated. Four promising systems were constructed as prototypes:

(A) Point-focus Fresnel lenses, two-axis tracking; Cg=32×; and 69× with secondaries.

(B) Line-focus mirror parabolic troughs, one-axis tracking, Cg=20×.

(C) SMTS (‘single-mirror two-stage’), one-axis tracking, Cg=30×.

(F) Multiple line-focus mirror parabolic troughs, E–W 1/day manual tracking, Cg=6×.

The prototypes were tested at Reading, and three for up to a year’s field trial at ZSW’s test site, Widderstall, in Germany. The best system efficiencies, normalised to 25°C and excluding the end losses of linear systems, were 12.5%, 13.2%, 13.6% and 14.3% for collectors A, B, C, and F, respectively. The collectors were practical and robust, and the performances of collectors B, C and F are only 10% below the estimates in the spreadsheet calculations. The best collectors have estimated production costs between 1.5 and 1.8 US $/Wp, yielding energy costs at a good site (excluding BOS and overheads) of between 5 and 7 cents/kWh (18 and 25 cents/MJ). On the same cost basis a conventional PV array costs 4.3 $/Wp, and 18 cents/kWh (65 cents/MJ).     

An off-peak energy storage concept for electric utilities: Part I—Electric utility requirements

The water battery, a reversible water electrolyser device being developed in a long-term research effort at Battelle's Columbus Laboratories, was evaluated in an analytical and conceptual design study as a load-levelling system for an electric utility. During periods when off-peak electrical power was available, the water battery would produce hydrogen and oxygen by electrolysis of water; during peak demand periods the water battery would be operated in the reverse mode, functioning as a fuel cell by producing electrical power through the recombination of the oxygen and hydrogen held in its storage vessels.The analysis involved characterisation of the PSE&G system demand requirements now and in the future, its current off-peak energy availability, the typical sizing and placement of energy storage units and the approximate break even economics and potential advantages to the utility of a water battery energy storage system. In the economic analysis, the water battery was compared with the gas turbine and the fuel cell for cost effectiveness in meeting peak and intermediate power demands, respectively.Compared with a ‘reformer-type’ fuel cell (costed at $300/kW for intermediate duty) the break even capital cost of a 50% efficient water battery would be $100/kW plus about $200/kW for each increase of $1/10⁶ Btu above the reference cost of $1/10⁶ Btu for fossil fuel. The available margin would increase about $50/kW for each decrease of 1 mill/kWh in off-peak energy cost below the reference cost of 8 mills/kWh. In a similar comparison with the gas turbine (costed at $135/kW) for peaking duty, the break even cost of a 50% efficient water battery would be $100/kW. The break even cost could rise about $100/kW for each increase in fossil fuel cost of $1/10⁶ Btu and about $20/kW for each decrease in off-peak energy cost of 1 mill/kWh.     

Techno-economic study of off-grid hybrid photovoltaic/battery and photovoltaic/battery/fuel cell power systems in Kunming,China

The objective of this study is to evaluate the technical and economic feasibility of stand-alone hybrid photovoltaic (PV)/battery and PV/battery/fuel cell (FC) power systems for a community center comprising 100 households in Kunming by using the Hybrid Optimization Model for Electric Renewable (HOMER) software. HOMER is used to define the optimum sizing and techno-economic feasibility of the system equipment based on the geographical and meteorological data of the study region. In this study, different hybrid power systems are analyzed to select the optimum energy system while considering total net present cost (NPC) and levelized cost of energy (COE). The results showed that the optimal hybrid PV/battery system comprised 500 kW PV modules, 1200 7.6-kWh battery units, and 500 kW power converters. The proposed system has an initial cost of $6,670,000, an annual operating cost of $82,763/yr, a total NPC of $7,727,992, and a levelized COE of $1.536/kWh. While the PV/battery/FC power system is possible, the cost increases were due to the investment cost of the FC system. The optimal PV/battery/FC system has an initial cost of $6,763,000, an annual operating cost of $82,312/yr, a total NPC of $7,815,223, and a levelized COE of $1.553/kWh.     

An economic analysis comparison of stationary and dual-axis tracking grid-connected photovoltaic systems in the US Upper Midwest

This paper presents an economic analysis of stationary and dual-axis tracking photovoltaic (PV) systems installed in the US Upper Midwest in terms of life-cycle costs, payback period, internal rate of return, and the incremental cost of solar energy. The first-year performance and energy savings were experimentally found along with documented initial cost. Future PV performance, savings, and operating and maintenance costs were estimated over 25-year assumed life. Under the given assumptions and discount rates, the life-cycle savings were found to be negative. Neither system was found to have payback periods less than the assumed system life. The lifetime average incremental costs of energy generated by the stationary and dual-axis tracking systems were estimated to be $0.31 and $0.37 per kWh generated, respectively. Economic analyses of different scenarios, each having a unique set of assumptions for costs and metering, showed a potential for economic feasibility under certain conditions when compared to alternative investments with assumed yields.     

Review of research on autonomous wind farms and solar parks and their feasibility for commercial loads in hot regions

In the wake of rising cost of oil and fears of its exhaustion coupled with increased pollution, the governments world-wide are deliberating and making huge strides to promote renewable energy sources such as solar–photovoltaic (solar–PV) and wind energy. Integration of diesel systems with hybrid wind–PV systems is pursued widely to reduce dependence on fossil-fuel produced energy and to reduce the release of carbon gases that cause global climate change. Literature indicates that commercial/residential buildings in the Kingdom of Saudi Arabia (KSA) consume an estimated 10–40% of the total electric energy generated. The study reviews research work carried out world-wide on wind farms and solar parks. The work also analyzes wind speed and solar radiation data of East-Coast (Dhahran), KSA, to assess the technical and economic potential of wind farm and solar PV park (hybrid wind–PV–diesel power systems) to meet the load requirements of a typical commercial building (with annual electrical energy demand of 620,000 kWh). The monthly average wind speeds range from 3.3 to 5.6 m/s. The monthly average daily solar global radiation ranges from 3.61 to 7.96 kWh/m². The hybrid systems simulated consist of different combinations of 100 kW wind machines, PV panels, supplemented by diesel generators. NREL (and HOMER Energy's) HOMER software has been used to perform the techno-economic study. The simulation results indicate that for a hybrid system comprising of 100 kW wind capacity (37 m hub-height) and 40 kW of PV capacity together with 175 kW diesel system, the renewable energy fraction (with 0% annual capacity shortage) is 36% (24% wind + 12% PV). The cost of generating energy (COE, $/kWh) from this hybrid wind–PV–diesel system has been found to be 0.154 $/kWh (assuming diesel fuel price of 0.1$/L). The study exhibits that for a given hybrid configuration, the number of operational hours of diesel generators decreases with increase in wind farm and PV capacity. Attention has also been focused on wind/PV penetration, un-met load, excess electricity generation, percentage fuel savings and reduction in carbon emissions (relative to diesel-only situation) of different hybrid systems, cost break-down of wind–PV–diesel systems, COE of different hybrid systems, etc.     

Techno-economic evaluation of a grid-connected PV-trigeneration-hydrogen production hybrid system on a university campus

Many universities have plans to reduce campus energy consumption with developed energy efficiency strategies, supply the energy needs of the university campus with renewable energy and create a green campus. In order to serve this purpose, this study focuses on the simulation of the installation of an on-grid photovoltaic (PV) power system at the Vocational Colleges Campus, Hitit University. On the other hand, the integration of the simulated PV system with a gas fired-trigeneration system is discussed. Moreover, the study explores opportunities for solar hydrogen generation without energy storage on campus. For the PV system simulation, three different scenarios were created by using web-based PV system design software (HelioScope). Installed powers in the simulation were found as 94.2 kWe, 123.9 kWe, and 157.5 kWe for the low scenario (on the rooftop), high scenario (on the rooftop), and the high + PV canopy arrays scenario (on the rooftop and an outdoor parking area), respectively. The levelized cost of electricity (LCOE) values were 0.061 $/kWh, 0.065 $/kWh, and 0.063 $/kWh for the low scenario, high scenario, and the scenario including PV canopy, respectively. The energy payback time is found to be 6.47–6.94 years for the 20–25 years lifetime of the PV plant. The simulation results showed that the PV system could support it by generating additional electrical energy up to 25% of the existing system. The campus can reduce GHG emissions of 1546–2272 tonnes-CO₂eq, which is equivalent to 142–209 ha of forest-absorbing carbon unused during the life of the PV system. Depending on the production and consumption methods utilized on campus, which is a location with relatively large solar potential, the levelized cost of hydrogen (LCOH) of hydrogen generation ranged from 0.054 $/kWhH₂ (1.78 $/kgH₂) to 0.103 $/kWhH₂ (3.4 $/kgH₂). Consequently, with proper planning and design, a grid-connected PV-trigeneration-hydrogen generation hybrid system on a university campus may operate successfully.     

Off-grid hybrid renewable energy system with hydrogen storage for South African rural community health clinic

Most inhabitants of rural communities in Africa lack access to clean and reliable electricity. This has deprived the rural dwellers access to modern healthcare delivery. In this paper, an off-grid renewable energy system consisting of solar PV and wind turbine with hydrogen storage scheme has been explored to meet the electrical energy demands of a health clinic. The health clinic proposed is a group II with 10 beds located in a typical village in South Africa. First, the wind and solar energy resources of the village were analysed. Thereafter, the microgrid architecture that would meet the energy demand of the clinic (18.67 kWh/day) was determined. Some of the key results reveal that the average annual wind speed at 60 m anemometer height and solar irradiation of the village are 7.9 m/s and 4.779 kWh/m²/day, respectively. The required architecture for the clinic composes of 40 kW solar PV system, 3 numbers of 10 kW wind turbines, 8.6 kW fuel cell, 25 kW electrolyser and 40 kg hydrogen tank capacity. The capital cost of the microgrid was found to be $177,600 with a net present cost of $206,323. The levelised cost of energy of the system was determined to be 2.34 $/kWh. The project has a breakeven grid extension distance of 8.81 km. Since this distance is less than the nearest grid extension distance of 21.35 km, it is established that the proposed renewable energy microgrid with a hydrogen storage system is a viable option for the rural community health clinic.     

Potentials for tracking photovoltaic systems and V-troughs in moderate climates

The irradiance received and the energy costs for tracking photovoltaic systems and V-trough concentrators are derived relative to the costs of a fixed system. Radiation data from 28 sites, especially in moderate climates, are investigated with regard to the surplus of radiation achieved with one- and two-axes tracking surfaces. By use of the Perez model the fraction of the supplementary irradiance is computed. A comprehensive computer code describing the optical performance of a low concentrating V-trough was developed. It is used to calculate the annual average concentration for diffuse and direct irradiance under different climatic conditions. Applying a life-cycle cost analysis relative to the costs for a fixed array, the results are freed of political-economic assumptions (inflation or discount rate). The resulting relative energy costs are dependent mainly on module costs. A sensitivity analysis shows that the results are stable against variations in meteorological data, balance-of-system or module efficiencies, and power related balance-of-system costs. The most economical system turns out to be the one-axis tracking PV system for moderate climates. It promises cost advantages for module costs even down to 250 $/m² if the tracker costs do not exceed the area-related balance-of-system costs of fixed systems by more than 100%.     

Size optimization of a PV/wind hybrid energy conversion system with battery storage using response surface methodology

This paper aims to show the use of the response surface methodology (RSM) in size optimization of an autonomous PV/wind integrated hybrid energy system with battery storage. RSM is a collection of statistical and mathematical methods which relies on optimization of response surface with design parameters. In this study, the response surface, output performance measure, is the hybrid system cost, and the design parameters are the PV size, wind turbine rotor swept area and the battery capacity. The case study is realized in ARENA 10.0, a commercial simulation software, for satisfaction of electricity consumption of the global system for mobile communications (GSM) base station at Izmir Institute of Technology Campus Area, Urla, Turkey. As a result, the optimum PV area, wind turbine rotor swept area, and battery capacity are obtained to be 3.95 m², 29.4 m², 31.92 kWh, respectively. These results led to $37,033.9 hybrid energy system cost, including auxiliary energy cost. The optimum result obtained by RSM is confirmed using loss of load probability (LLP) and autonomy analysis.     

The costs and benefits of large-scale solar photovoltaic power production in Abu Dhabi,United Arab Emirates

The potential for a 10 MW photovoltaic power plant in Abu Dhabi is examined in this paper using RETScreen modeling software to predict energy production, financial feasibility and GHG emissions reductions. Initial results show high energy production potential, generating 24 GWh and saving over 10,000 tons of GHG emissions annually, but poor financial prospects yielding a net present value (NPV) of ?$51 million. Benefits of reducing GHG and air pollution emissions by replacing natural gas with PV generation are calculated to have a net present value of $47 million, with a large range of possible values. Results show that the high initial costs and low expected price for electricity generated are driving reasons why photovoltaic systems are not being implemented in Abu Dhabi. A feed-in tariff rate of $0.16/kWh is recommended to make large-scale PV systems profitable.     

Simulation of off-grid generation options for remote villages in Cameroon

Off-grid generation options have been simulated for remote villages in Cameroon using a load of 110 kWh/day and 12 kWp. The energy costs of proposed options were simulated using HOMER, a typical village load profile, the solar resource of Garoua and the flow of river Mungo. For a 40% increase in the cost of imported power system components, the cost of energy was found to be 0.296 €/kWh for a micro-hydro hybrid system comprising a 14 kW micro-hydro generator, a 15 kW LPG generator and 36 kWh of battery storage. The cost of energy for photovoltaic (PV) hybrid systems made up of an 18 kWp PV generator, a 15 kW LPG generator and 72 kWh of battery storage was also found to be 0.576 €/kWh for remote petrol price of 1 €/l and LPG price of 0.70 €/m³. The micro-hydro hybrid system proved to be the cheapest option for villages located in the southern parts of Cameroon with a flow rate of at least 200l/s, while the PV hybrid system was the cheapest option for villages in the northern parts of Cameroon with an insolation level of at least 5.55 kWh/m²/day. For a single-wire grid extension cost of 5000 €/km, operation and maintenance costs of 125 €/yr/km and a local grid power price of 0.1 €/kWh, the breakeven grid extension distances were found to be 15.4 km for micro-hydro/LPG generator systems and 37.4 km for PV/LPG generator systems respectively. These results could be used in Cameroon's National Energy Action Plan for the provision of energy services in the key sectors involved in the fight against poverty.     

Techno-economic evaluation of off-grid hybrid photovoltaic–diesel–battery power systems for rural electrification in Saudi Arabia—A way forward for sustainable development

The burning of depleting fossil fuels for power generation has detrimental impact on human life and climate. In view of this, renewable solar energy sources are being increasingly exploited to meet the energy needs. Moreover, solar photovoltaic (PV)–diesel hybrid system technology promises lot of opportunities in remote areas which are far from utility grid and are driven by diesel generators. Integration of PV systems with the diesel plants is being disseminated worldwide to reduce diesel fuel consumption and to minimize atmospheric pollution. The Kingdom of Saudi Arabia (K.S.A.) being endowed with high intensity of solar radiation, is a prospective candidate for deployment of PV systems. Also, K.S.A. has large number of remote scattered villages. The aim of this study is to analyze solar radiation data of Rafha, K.S.A., to assess the techno-economic feasibility of hybrid PV–diesel–battery power systems to meet the load requirements of a typical remote village Rawdhat Bin Habbas (RBH) with annual electrical energy demand of 15,943 MWh. Rafha is located near RBH. The monthly average daily global solar radiation ranges from 3.04 to 7.3 kWh/m². NREL's HOMER software has been used to perform the techno-economic evaluation. The simulation results indicate that for a hybrid system composed of 2.5 MWp capacity PV system together with 4.5 MW diesel system (three 1.5 MW units) and a battery storage of 1 h of autonomy (equivalent to 1 h of average load), the PV penetration is 27%. The cost of generating energy (COE, US$/kWh) from the above hybrid system has been found to be 0.170$/kWh (assuming diesel fuel price of 0.1$/l). The study exhibits that the operational hours of diesel generators decrease with increase in PV capacity. The investigation also examines the effect of PV/battery penetration on COE, operational hours of diesel gensets. Concurrently, emphasis has been placed on: un-met load, excess electricity generation, percentage fuel savings and reduction in carbon emissions (for different scenarios such as: PV–diesel without storage, PV–diesel with storage, as compared to diesel-only situation), COE of different hybrid systems, etc. The decrease in carbon emissions by using the above hybrid system is about 24% as compared to the diesel-only scenario.     

The cost benefit analysis of implementing photovoltaic solar system in the state of Kuwait

In addition to the high financial cost of energy resources required to meet the rising demand for electricity consumption in Kuwait, the negative environmental impact of fossil fuel is increasing. Hence, the objective of this paper is to determine the economic feasibility and viability of implementing PV solar energy in the State of Kuwait. It was found that the positive characteristics of solar radiation in Kuwait play a critical role in enhancing the feasibility of implementing solar systems. Under the present price of 5$/W and 15% efficiency, the LCOE of a 1 MW station is estimated to be around $0.20/kWh. This LCOE can be feasible only when the cost of oil is around 100$/barrel. The Cost Benefit Analysis showed that when the value of saved energy resources used in producing traditional electricity, and the cost of lowering CO₂ emissions are accounted for, the true economic cost of LCOE of a PV system will decline significantly. The preliminary economic analysis recommends the implementation of PV technology in Kuwait.     

Large energy storage systems for utilities

In addition to the capacity on line, electric networks usually need 8–10 per cent of their installed capacity readily available to handle load variations. Thermal storage of energy as pressurised saturated hot water has done this job for years, but only on a small scale because of cost limitation of the steel pressure vessel. This paper shows that steel lined cavities deep underground, using the rock to provide containment, are economical and practical in large capacities for this energy storage. By reducing the cavity pressure, steam is flashed from the hot water and used to drive peaking turbines when needed; at low load periods surplus steam is condensed in the water to recharge the vault. The saturation pressure of the hot water is borne by the overburden pressure of the rock formation in which the storage vault is prepared. At usual steam plant saturation temperatures the effective storage density is in the range of 18–21 electric kWh/m³ of storage volume, which is 20–50 times the capacity of the usual pumped hydro systems. Recovery of stored energy ranges from 75–90 per cent. The cost of a facility to deliver 1000 MW of peaking power for 10 h would fall in the range of $250–350 million, including indirect costs, interest, etc. The underground facilities represent about 40 per cent of the cost: the balance is for conventional generating and steam plant equipment.     

An experimental study on energy generation with a photovoltaic (PV)–solar thermal hybrid system

A hybrid system, composed of a photovoltaic (PV) module and a solar thermal collector is constructed and tested for energy collection at a geographic location of Cyprus. Normally, it is required to install a PV system occupying an area of about 10 m² in order to produce electrical energy; 7 kWh/day, required by a typical household. In this experimental study, we used only two PV modules of area approximately 0.6 m² (i.e., 1.3×0.47 m²) each. PV modules absorb a considerable amount of solar radiation that generate undesirable heat. This thermal energy, however, may be utilized in water pre-heating applications. The proposed hybrid system produces about 2.8 kWh thermal energy daily. Various attachments that are placed over the hybrid modules lead to a total of 11.5% loss in electrical energy generation. This loss, however, represents only 1% of the 7 kWh energy that is consumed by a typical household in northern Cyprus. The pay-back period for the modification is less than 2 years. The low investment cost and the relatively short pay-back period make this hybrid system economically attractive.     

Solar-fuel fired cogeneration plants—Sizing and costing model for molten salt storage systems

The large-scale utilization of solar energy will be facilitated by economical and efficient energy storage. The proposed energy storage systems have been critically reviewed, and capital cost estimates compared on a common basis. A model for sizing an energy storage system is proposed and used to determine the size range of practical interest. Based on selection criteria and relevant data two storage systems have been investigated: an all sodium system and a molten salt system. The design equations, cost estimates, and correlations indicate that, for the energy storage systems developed to date, in the capacity range of 700–2100 MWh, a molten salt, two-tank isolated-type system is the most cost effective and technically feasible for a solar, central receiver, hybrid cogeneration plant. At the extremes of the above range the unit capital cost for the molten salt storage system was found to be 22.8–26.7 $/kWh of stored energy, compared to 43.0–45.4 $/kWh for the sodium storage system.     

Economic evaluation of a stand-alone residential photovoltaic power system in Bangladesh

The economics of stand-alone photovoltaic power system is studied to test its feasibility in remote and rural areas of Bangladesh and to compare renewable generators with non-renewable generators. The life cycle cost of these generators are determined using the method of net present value analysis. It is found that the life cycle cost of this experimental PV system is Tk. 43.40/kWh for one family (US $1.00 = Bangladeshi taka Tk.50.00). The life cycle cost for grid electricity is Tk. 20.00/kWh and Tk. 7.75/kWh for generation of fuel costs of Tk. 6.80/kWh and Tk. 0.47/kWh respectively. For a village 1 km away from the distribution line, this cost becomes Tk. 125.00/kWh for a family. For petrol generator life cycle cost is Tk. 50.00/kWh at fuel price of Tk. 22.00 per litre. For diesel generator life cycle cost is found to be Tk. 46.10/kWh at fuel cost of Tk. 15.00 per litre. It is observed that the life cycle cost of one unit of energy from grids that are 1 km away from a village is much higher than the cost of energy from a PV system. Thus, the use of PV system is economically feasible in rural villages and remote areas of Bangladesh, where grid electricity is not available.     

Lighting controls: Survey of market potential

This study describes the impact of lighting management systems that dynamically control lights in accordance with the needs of occupants. Various control strategies are described: scheduling, tuning, lumen depreciation, and daylighting. From initial experimental results, the energy savings provided by each of the above strategies are estimated to be 26, 12, 14, and 15%, respectively.Based upon a cost of $0.05–0.10 per kWh for electric energy and a 2-, 3-, or 4-yr payback, target costs for a simple and a sophisticated lighting management system are found to be $0.24 and 1.89 per ft², respectively, for a cost-effective investment.A growth model, based upon an extrapolation of the increase in building stock since 1975, indicates that the commercial and industrial (C & I) building stock will grow from 40 × 10⁹ ft² in 1980 to about 67 × 10⁹ ft² by the year 2000. Even with the use of more efficient lighting components, the energy required for this additional C & I stock will be 307 × 10⁹ kWh compared to the 230 × 10⁹ kWh used today. Adopting controls would reduce this requirement to 243 × 10⁹ kWh, an increase of only 13 × 10⁹ kWh above current use.The specified information is used to analyze the economic impacts that using these systems will have on the lighting industry, end users, utility companies, and the nation's economy. A $1–4 × 10⁹ annual lighting control industry can be generated, creating many jobs. The estimated return on investment (ROI) for controls for end users would be between 19 and 38%. Utilities will be able to make smaller additions to capacity and invest less captial at 7–10% ROI. Finally, the annual energy savings, up to $3.4 × 10⁹ for end users and about $5 × 10⁹ for utilities, representing unneeded generating capacity, will be available to capitalize other areas of our economy.     

Design and analysis of a combined floating photovoltaic system for electricity and hydrogen production

The current study deals with a potential solution for the replacement of fossil fuel based energy resources with a sustainable solar energy resource. Electrical energy demand of a small community is investigated where a floating photovoltaic system and integrated hydrogen production unit are employed. Data are taken from Mumcular Dam located in Aegean Region of Turkey. PvSyst software is used for the simulation purposes. Furthermore, the obtained results are analyzed in the HOMER Pro Software. Photovoltaic (PV) electricity provides the required load and excess electricity to be used in the electrolyzer and to produce hydrogen. Saving lands by preventing their usage in conventional PV farms, saving the water due to reducing evaporation, and compensating the intermittent availability of solar energy are among the obtained results of the study for the considered scenario. Stored hydrogen is used to compensate the electric load through generating electricity by fuel cell. Floating PV (FPV) system decreases the water evaporation of water resources due to 3010 m² shading area. FPV and Hydrogen Systems provides %99.43 of the electricity demand without any grid connection or fossil fuel usage, where 60.30 MWh/year of 211.94 MWh/year produced electricity is consumed by electric load at $0.6124/kWh levelized cost of electricity (LCOE).     

Simulation model for sizing of stand-alone solar PV system with interconnected array

Solar PV arrays made of interconnected modules are comparatively less susceptible to shadow problem and power degradation resulting from the aging of solar cells. This paper presents a simulation model for the sizing of stand-alone solar PV systems with interconnected arrays. It considers the electricity generation in the array and its storage in the battery bank serving the fluctuating load demand. The loss of power supply probability (LPSP) is used to connote the risk of not satisfying the load demand. The non-tracking (e.g., fixed and tilted) and single-axis tracking aperture arrays having cross-connected modules of single crystalline silicon solar cells in a (6×6) modular configuration are considered. The simulation results are illustrated with the help of a numerical example wherein the load demand is assumed to follow uniform probabilistic distribution. For a given load, the numbers of solar PV modules and batteries corresponding to zero values of LPSP on diurnal basis during the year round cycle of operation are presented. The results corresponding to the surplus and deficit of energy as a function of LPSP are also presented and discussed to assess the engineering design trade offs in the system components.Furthermore, a simple cost analysis has also been carried out, which indicates that for Delhi the stand-alone solar PV systems with fixed and tilted aperture arrays are better option than those with single-axis tracking aperture (with north–south oriented tracking axis) arrays.