The economic and institutional rationale of PV subsidies

In terms of cost and performance, infant technologies, such as solar photovoltaics (PV), are normally inferior to entrenched technologies. It is a Catch-22 situation since the diffusion on larger markets that would be needed to reduce cost is hindered by the high cost. Therefore it would make sense to subsidise PV to increase sales, which would increase experience and induce investments in larger factories, which in turn would drive down costs and the subsidies needed. The total costs of such a scheme does not have to be prohibitive if cost reductions with increased volumes are large enough. Over the last 20 years the cost of PV modules was reduced by 18–23% per doubling of cumulative production (a progress ratio of 0.77–0.82). For a progress ratio of 0.80 and an annual growth rate of 30%, the modelled annual subsidy peaks at $14 US billion, which corresponds to an additional electricity tax of no more than 0.1 US cents/kW h in OECD countries. A market support programme also creates institutional learning and increases the political power of the proponents of PV. The current federal German support programme is a product of learning and network formation in earlier market stimulation and research, development and demonstration (RDD) programmes of smaller scale. Hence, the current support programme is now likely to create not only economic virtuous circles that reduce costs, but also institutional virtuous circles that work for the survival and expansion of the programme itself. As the PV industry grows, care should be taken to maintain variety to reduce the risk of a premature lock-in of an inferior design. To maintain variety in the market place may prove costly when the market grows but variety creation at the level of RDD investments is fairly cheap. To increase the world expenditure on RDD of renewable energy technology by a factor of 10 would not cost more than $1 US/ton C or 0.02 US cent/kW h of electricity.     

Solar ponds

This report provides the background to, and the current status of, solar ponds as proven viable large-area collectors capable of providing both low-cost thermal energy and mechanical or electrical energy using state-of-the-art low-temperature turbo-generators.After a short background statement giving the history and motivation to create a viable large-area collector with built-in storage, the basic theory of salt-gradient solar ponds is sketched. (More detailed-theory is available from the given references, particularly two recently published handbooks.) NaCl and MgCl₂ are two common and low-cost salts suitable for solar ponds. A number of problems such as the adverse effect of wind, leakage, fouling—and their solutions—are indicated as are some fundamental constraints (Section 8) that limit the sites suitable for solar ponds. Practical details include how ponds are built and filled and how the heat is extracted. Section 7 presents a condensed account of solar pond experience in a number of countries.Practical operating temperatures of 90°C are obtained with collection efficiencies usually between 15 and 25 per cent: this permits a number of practical applications as discused in Section 10, i.e. heating and cooling, power production and desalination.Realistic pond cost figures indicate thermal energy costs equivalent to US$41 per ton of fuel for a sunny climate (using a conservative 11.7 per cent annual charage on capital): such low-cost calories permit thermodynamic conversion to power: although the conversion efficiency is low, the solar pond power station (SPPS) is viable in many cases. Bus-bar power costs, for a sunny climate, vary from a high of US13.5 cents/kWh—using present technology—to a low 5.3 cents in sizes of 20 GWhr(e) per annum or larger.A 150-kW SPPS has already been built and successfully operated in Israel since December 1979 and a 5000-kW unit is due for completion in the next 2 yr.The ability of a solar pond to store heat even from summer to winter greatly increases its usefulness in almost all applications: for power production, the SPPS can—like a hydro-electric plant, provide peaks of power, on demand—far in excess of the pond mean capacity. The estimate that SPPS costs flatten out at 20–40 MW is of interest to developing countries that could install generating capacity in relatively small steps as demand grows.     

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.     

The feasibility of renewable energies at an off-grid community in Canada

Three renewable energy technologies (RETs) were analyzed for their feasibility for a small off-grid research facility dependent on diesel for power and propane for heat. Presently, the electrical load for this facility is 115 kW but a demand side management (DSM) energy audit revealed that 15–20% reduction was possible. Downsizing RETs and diesel engines by 15 kW to 100 kW reduces capital costs by $27 000 for biomass, $49 500 for wind and $136 500 for solar.The RET Screen International 4.0^® model compared the economical and environmental costs of generating 100 kW of electricity for three RETs compared to the current diesel engine (0 cost) and a replacement ($160/kW) diesel equipment. At all costs from $0.80 to $2.00/l, biomass combined heat and power (CHP) was the most competitive. At $0.80 per liter, biomass’ payback period was 4.1 years with a capital cost of $1800/kW compared to wind's 6.1 years due to its higher initial cost of $3300/kW and solar's 13.5 years due to its high initial cost of $9100/kW. A biomass system would reduce annual energy costs by $63 729 per year, and mitigate GHG emissions by over 98% to 10 t CO₂ from 507 t CO₂. Diesel price increases to $1.20 or $2.00/l will decrease the payback period in years dramatically to 1.8 and 0.9 for CHP, 3.6 and 1.8 for wind, and 6.7 and 3.2 years for solar, respectively.     

An optimum dispatch strategy using set points for a photovoltaic (PV)–diesel–battery hybrid power system

This paper presents dispatch strategies for the operation of a solar photovoltaic (PV)–diesel–battery hybrid power system using ‘set points’. This includes determination of the optimum values of set points for the starting and stopping of the diesel generator to minimise the overall system costs. A computer program for a typical dispatch strategy has been developed to predict the long-term energy performance and the lifecycle cost of the system.     

The impact of state policy on deployment and cost of solar photovoltaic technology in the U.S.: A sector-specific empirical analysis

Using a panel database for 27 programs in 16 U.S. states over 1998–2009, we assess the impact of 12 state-level policies on the cost and deployment of solar photovoltaic (PV) technologies for two sectors defined by system sizes: residential (<10 kW) and commercial (10−100 kW). We first examine the impact of policies on the deployment of solar PV. We show that cash incentives increase the deployment of commercial systems. We also show that interconnection standards potentially promote the deployment of residential systems, whereas property tax incentives potentially foster the deployment of commercial systems. We next examine the impact of policies on the cost of solar PV, and show that the key policies have different effects on costs. The cost of residential systems declines faster if there are cash or property tax incentives in place, whereas the presence of interconnection standards potentially accelerates the decline in commercial system costs. Further, states with a renewable portfolio standard see residential system costs potentially declining slower than states without such a policy. As solar PV is at the brink of becoming cost competitive, our findings assist regulators in fine-tuning their set of support tools.     

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).     

High concentration photovoltaic systems applying III–V cells

High concentration systems make use of the direct solar beam and therefore are suitable for application in regions with high annual direct irradiation values. III–V PV cells with a nominal efficiency of up to 39% are readily available in today's market, with further efficiency improvements expected in the years ahead. The relatively high cost of III–V cells limits their terrestrial use to applications under high concentration, usually above 400 suns. In this way the relatively high cell cost is compensated through the low amount for cells needed per kW nominal system output.This paper presents a state of the art of high concentration photovoltaics using III–V cells. This PV field accounts already for more than 20 developed systems, which are commercially available or shortly before market introduction.     

The economics of photovoltaic stand-alone residential households: A case study for various European and Mediterranean locations

The cost-effective sizing and evaluation of residential stand-alone photovoltaic systems at various European and Mediterranean locations is the subject of this paper. The stand-alone photovoltaic system is serving the energy needs of a medium-sized household inhabited by a typical four member family. A typical energy consumption daily profile is assumed, and the solar array, battery and back-up generator – if necessary – are optimally sized to minimise the system life-cycle cost (LCC). The calculations have been done assuming economic parameters and PV technology costs applicable to years 1998 and 2005.     

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.     

Pre-feasibility study of stand-alone hybrid energy systems for applications in Newfoundland

A potential solution for stand-alone power generation is to use a hybrid energy system in parallel with some hydrogen energy storage. In this paper, a pre-feasibility study of using hybrid energy systems with hydrogen as an energy carrier for applications in Newfoundland, Canada is explained. Various renewable and non-renewable energy sources, energy storage methods and their applicability in terms of cost and performance are discussed. HOMER is used as a sizing and optimization tool. Sensitivity analysis with wind speed data, solar radiation level, diesel price and fuel cell cost was done. A remote house having an energy consumption of 25 kW h/d with a 4.73 kW peak power demand was considered as the stand-alone load. It was found that, a wind–diesel–battery hybrid system is the most suitable solution at present. However, with a reduction of fuel cell cost to 15% of its current value, a wind–fuel cell system would become a superior choice. Validity of such projection and economics against conventional power sources were identified. Sizing, performance and various cost indices were also analyzed in this paper.     

Assessing the potential of concentrating solar photovoltaic generation in Brazil with satellite-derived direct normal irradiation

With the declining costs of flat plate and concentrating photovoltaic (PV) systems, solar PV generation in many sunny regions in Brazil will eventually become cost competitive with conventional and centralized power generation. Detailed knowledge of the local solar radiation resource becomes critical in assisting on the choice of the technology most suited for large-scale solar electricity generation. When assessing the energy generation potential of non-concentrating, fixed flat plate versus concentrating PV, sites with high levels of direct normal irradiation (DNI) can result in cost-competitive electricity generation with the use of high concentrating photovoltaic systems (HCPV). In large countries, where the transmission and distribution infrastructure costs and associated losses typical of centralized generation must be taken into account, the distributed nature of solar radiation should be perceived as a valuable asset. In this work we assess the potential of HCPV energy generation using satellite-derived DNI data for Brazil, a large and sunny country with a continental surface of 8.5 million km². The methodology used in the study involved the analysis of global horizontal, latitude-tilt, and direct normal solar irradiation data resulting from the Solar and Wind Energy Resource Assessment (SWERA) Project, and an estimate of the resulting electricity production potential, based on a review of HCPV generators operating at other sites. The satellite-derived solar irradiation data, with 10 km × 10 km spatial resolution, were analysed over the whole country, in order to identify the regions where HCPV might present a considerable advantage over fixed plate PV on an annual energy generation basis. Our results show that there is a considerable fraction of the national territory where the direct normal solar irradiation resource is up to 20% higher than the latitude-tilt irradiation availability. Furthermore, these sites are located in the most industrially-developed region of the country, and indicate that with the declining costs of this technology, distributed multi-megawatt HCPV can be a good choice of technology for solar energy generation at these sites in the near future.     

Analysis of grid connected solar PV system in the southeastern part of Bangladesh

Bangladesh is a potential site of implementing renewable energy system to reduce the severe power crisis throughout the year. According to this, Chittagong is the southeastern part of Bangladesh is also a potential site for implementing renewable energy system such as grid-connected photovoltaic (PV) system. Financial viability and green-house gas emission reduction of solar PV as an electricity generation source are assessed for 500 kW grid connected solar PV system at University of Chittagong, Chittagong. Homer simulation software and monthly average solar radiation data from NASA is used for this task. In the proposed system monthly electricity generation varies between 82.65 MW h and 60.3 MW h throughout the year with a mean value of 68.25 MW h depending on the monthly highest and lowest solar radiation data. It is found that per unit electricity production cost is US$ 0.20 based on project lifetime 25 years. The IRR, equity payback and benefit-cost ratio shows favorable condition for development of the proposed solar PV system in this site. A minimum 664 tones of green-house gas emissions can be reduced annually utilizing the proposed system.     

Technical and economical system comparison of photovoltaic and concentrating solar thermal power systems depending on annual global irradiation

Concentrating solar thermal power and photovoltaics are two major technologies for converting sunlight to electricity. Variations of the annual solar irradiation depending on the site influence their annual efficiency, specific output and electricity generation cost. Detailed technical and economical analyses performed with computer simulations point out differences of solar thermal parabolic trough power plants, non-tracked and two-axis-tracked PV systems. Therefore, 61 sites in Europe and North Africa covering a global annual irradiation range from 923 to 2438 kW h/m² a have been examined. Simulation results are usable irradiation by the systems, specific annual system output and levelled electricity cost. Cost assumptions are made for today's cost and expected cost in 10 years considering different progress ratios. This will lead to a cost reduction by 50% for PV systems and by 40% for solar thermal power plants. The simulation results show where are optimal regions for installing solar thermal trough and tracked PV systems in comparison to non-tracked PV. For low irradiation values the annual output of solar thermal systems is much lower than of PV systems. On the other hand, for high irradiations solar thermal systems provide the best-cost solution even when considering higher cost reduction factors for PV in the next decade. Electricity generation cost much below 10 Eurocents per kW h for solar thermal systems and about 12 Eurocents/kW h for PV can be expected in 10 years in North Africa.     

Potential of solar electricity generation in the European Union member states and candidate countries

During the years 2001–2005, a European solar radiation database was developed using a solar radiation model and climatic data integrated within the Photovoltaic Geographic Information System (PVGIS). The database, with a resolution of 1 km × 1 km, consists of monthly and yearly averages of global irradiation and related climatic parameters, representing the period 1981–1990. The database has been used to analyse regional and national differences of solar energy resource and to assess the photovoltaic (PV) potential in the 25 European Union member states and 5 candidate countries. The calculation of electricity generation potential by contemporary PV technology is a basic step in analysing scenarios for the future energy supply and for a rational implementation of legal and financial frameworks to support the developing industrial production of PV. Three aspects are explored within this paper: (1) the expected average annual electricity generation of a ‘standard’ 1 kW_p grid-connected PV system; (2) the theoretical potential of PV electricity generation; (3) determination of required installed capacity for each country to supply 1% of the national electricity consumption from PV. The analysis shows that PV can already provide a significant contribution to a mixed renewable energy portfolio in the present and future European Union.     

Organic solar cells consisting of stacked amine–thiophene copolymer and 3,4,9,10-perylenetetracarboxyl-bis-benzimidazole layers

Organic solar cells were fabricated using a new amine–bithiophene copolymer as an electron donor layer and 3,4,9,10-perylenetetracarboxyl-bis-benzimidazole (PV) as an electron acceptor layer. The amine–thiophene copolymer, poly{(9,9-dioctylfluorene-2,7-diyl)-co-[N,N′-bis(4-tert-butylphenyl)benzidine-N,N′-bis(phenylene-4,4′-diyl)]-co-(2,2′-bithiophene-5,5′-diyl)} (PF8-TPD-T2), had a glass transition temperature (T_g) at about 77 °C, and exhibited liquid crystalline states and a high hole mobility. The rigid bithiophene units in the polymer chain are probably responsible for the formation of the liquid crystalline states and the high hole mobility. A solar cell made of the PF8-TPD-T2 copolymer and PV layers showed a photocurrent density of 0.99 mA/cm², an open-circuit voltage of 0.61 V, and an energy conversion efficiency of 0.332%. The photocurrent of the solar cells was generated at both the copolymer and PV layers, and the copolymer layer was the main contributor to photocurrent when the thickness of the polymer was about 17 nm. After annealing the solar cells at temperatures well above the glass transition temperature (T_g) of the copolymer, the photocurrent action spectra of the solar cells were broadened and the performance was improved. The changes were mostly due to the increased contribution of the PV layer to the photocurrent by the annealing.     

Performance of submersible PV solar pumping systems under conditions in the Sudan

Water pumping for domestic use and irrigation purposes can be considered as one of the basic needs in the rural areas of Sudan. For the favourable solar radiation conditions in the country (6 kW h/m²/day), solar water pumping may be a competitive application against diesel-driven pumps for remote areas.Three SP4–8 Grundfos submersible pumps, installed at three different locations in the country, were evaluated. Two of these pumps were driven by M-51 Arco Solar modules, while the third was driven by M-53 Arco Solar modules. For each of these pumps, solar radiation in the plane of the PV array, ambient temperature, PV array voltage and current, water discharge and water delivery pressure were monitored using a data logger.Grundfos solar pumps used in the Sudan have proven in most cases to be reliable. However, their performance was 10–25% less than predicted by the manufacturer's literature. In general the product of the daily water demand (m³ per day) and the total pumping head (m) should not exceed 750 m⁴ for sites with good solar radiation.     

Hydrogen production from solar energy

Three alternatives for hydrogen production from solar energy have been analyzed on both efficiency and economic grounds. The analysis shows that the alternative using solar energy followed by thermochemical decomposition of water to produce hydrogen is the optimum one. The other schemes considered were the direct conversion of solar energy to electricity by silicon cells and water electrolysis, and the use of solar energy to power a vapor cycle followed by electrical generation and electrolysis. The capital cost of hydrogen via the thermochemical alternative was estimated at $575/kW of hydrogen output or $3·15/million Btu. Although this cost appears high when compared with hydrogen from other primary energy sources or from fossil fuel, environmental and social costs which favor solar energy may prove this scheme feasible in the future.     

Promoting applications of hybrid (wind+photovoltaic+diesel+battery) power systems in hot regions

Depleting oil and gas reserves, combined with growing concerns of atmospheric pollution/degradation, have made the search for energy from renewable sources of energy, such as solar and wind, inevitable. Literature indicates that commercial/residential buildings in Saudi Arabia consume an estimated 10–40% of the total electric energy generated. In the present study, hourly mean wind-speed and solar radiation data for the period 1986–1997 recorded at the solar radiation and meteorological monitoring station, Dhahran (26°32′ N, 50°13′ E), Saudi Arabia, have been analyzed to investigate the potential of utilizing hybrid (wind+solar) energy conversion 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 for Dhahran range from 4.1 to 6.4 m/s. The monthly average daily values of solar radiation for Dhahran range from 3.6 kWh/m² to 7.96 kWh/m². The hybrid systems considered in the present analysis consist of different combinations of commercial 10 kW wind energy conversion systems (WECS), photovoltaic (PV) panels supplemented with battery storage unit and diesel back-up. The study shows that with 30 10-kW WECS together with 150 m² PV, and 3 days of battery storage, the diesel back-up system has to provide 17% of the load demand. However, in the absence of battery storage, about 38% of the load needs to be provided by the diesel system.     

Present status and future of crystalline silicon solar cells in Japan

Crystalline silicon solar cells show promise for further improvement of cell efficiency and cost reduction by developing process technologies for large-area, thin and high-efficiency cells and manufacturing technologies for cells and modules with high yield and high productivity.In this paper, Japanese activities on crystalline Si wafers and solar cells are presented. Based on our research results from crystalline Si materials and solar cells, key issues for further development of crystalline Si materials and solar cells will be discussed together with recent progress in the field. According to the Japanese PV2030 road map, by the year 2030 we will have to realize efficiencies of 22% for module and 25% for cell technologies into industrial mass production, to reduce the wafer thickness to 50–100 μm, and to reduce electricity cost from 50 Japanese Yen/kWh to 7 Yen/kWh in order to increase the market size by another 100–1000 times.