5&$)/*$"- )"/%#00, 5IF JOTUBMMBUJPO PG HSPVOE QIPUPWPMUBJD QMBOUT PWFS NBSHJOBM BSFBT 06S IN ",//- 0ROJECT ! NEW CHALLENGE FOR LAND VALORISATION WITHIN A STRATEGIC ECO SUSTAINABLE APPROACH TO LOCAL DEVELOPMENT
TECHNICAL HANDBOOK The installation of on-ground photovoltaic plants over marginal areas
PVs in BLOOM Project - A new challenge for land valorisation within a strategic eco-sustainable approach to local development
G. Nofuentes, J. V. Mu単oz, D. L. Talavera, J. Aguilera and J. Terrados
INDEX
1. PV Grid-Connected Systems Basics 1.1. Overview 1.2. DC Part (PV modules, cabling, DC connection boxes, DC switches) 1.3. AC Part (Inverter & energy meters) 1.4. Metal works and protective elements (earth electrode, voltage surge arrestors, fuses, etc.) 1.5. Some electric characteristics of a typical 1-MWp PVPP BRIEF SUMMARY OF SECTION 1 2. Estimating The Annual Energy Produced by a PV Grid-Connected System 2.1. Assessment on The Solar Resource of the Site (Available insolation data sources: ground-based measurements and satellite-derived data) 2.2. Estimating The Annual Electricity Yield of a PV GridConnected System BRIEF SUMMARY OF SECTION 2
3. Sizing PV Grid-Connected Systems 3.1. Choosing the PV module 3.2. Sizing the nominal power of the PV generator 3.3. Sizing the nominal power of the inverter 3.4. Sizing the number of modules 3.5. Sizing the number of series connected modules 3.6. Sizing the number of parallel connected 3.7. Sizing the cabling 3.8. Sizing protective measurements (fuses, voltage surge arrestors, DC main switch, etc.) 2
3.9. Some characteristic data concerning implemented PVPPs BRIEF SUMMARY OF SECTION 3 APPENDIX OF SECTION 3: TERMINOLOGY 4. Matching PVPP Typologies to Specific Terrains BRIEF SUMMARY OF SECTION 4 5. Economic Assessment on PV Grid-Connected Systems 5.1. Representative figures of the cost of PVGCS in some countries 5.2. Existing supporting measures for PVPPs in each partner country 5.3. Easy-to-use tables to estimate the IRR 5.4. Review of the most meaningful and understandable profitability indices: the internal rate of return (IRR) 5.5. Easy-to-use tables to estimate the IRR 5.6. Short review of the taxation impact BRIEF SUMMARY OF SECTION 5 APPENDIX I OF SECTION 5. TABLES ADDRESSED TO ESTIMATE THE IRR APPENDIX II OF SECTION 5: TERMINOLOGY
Appendix: Main technical and contractual points to be checked and compared when examining a proposal from an EPC supplier by a prospective owner ACKNOWLEDGEMENTS
3
1. PV Grid-Connected Systems Basics
1.1 Overview Photovoltaic (PV) technology converts sunlight into electricity using solid state devices named PV modules. Such way to produce energy has experienced during the last years one of the most formidable growths in the renewable energy industry, as shown in figure 1.1.
Figure 1.1. World evolution of the number of photovoltaic cells production. The increase of MW produced has followed an exponential trend (source: EurObsev'ER 2008).
4
PV systems may be grouped into stand-alone systems (SAPV) and grid-connected systems (PVGCS). Basically the first one used the electricity produced to selfcomsuption while the second one the energy is sold through the electricity grid. Taking into account the characteristics of the PV in Bloom project, the PV stand-alone systems falls out of the scope of analysis of this paper, for this reason we are going to focus on PVGCS. In this kind of PV systems all energy generated is fed into the company electricity grid. In fact, the company plays the role of a huge energy store: in developed countries, most PV systems are connected to the grid. In principle, this point makes PVGCS simpler than SAPV mainly because it is not necessary to store any energy.
The reason of feeding all the energy PVGCS generates is related to the generous existing feed-in tariffs, by which PV-generated electricity is sold to the grid at prices well above the market. Further, the number of these systems has grown sharply worldwide. This development has been brought mainly by means of a continuous decrease trend in PV costs together with a wide variety of supporting policies that diferent countries have launched (e.g.: Germany, Spain and Italy). These strategies or policies are implemented with financial incentives, such as granting a subsidy per kWp of installed capacity or a payment per kWh produced and sold -these concepts will be explained in more depth in section 5 In other words, these financial incentives broadly fall into generation-based (mainly implemented through generous feed-in tariffs) and investment-focused (initial investment subsidies or rebates, lowinterest loans) ones. The latter incentives are being progressively phased out by governmental bodies.
After this short approach to PVGCS a more in-depth study is to be accomplished hereafter, dealing with the elements of these systems and how they work.
1.2 . Parts of PV Grid-Connected Systems A simplified layout of a grid-connected PV system is shown in figure 1.2. The system usually comprises the following elements:
1. PV modules, usually termed PV generator (some PV modules connected in series or parallel on a supporting structure) 5
2. Inverter (a solid-state based device that converts DC electricity from the modules into AC electricity with the same characteristic as that supplied by the grid) 3. Metering device intended to measure the electricity sold to the grid 4. Metering device intended to measure the electricity bought from the grid 5. AC loads from electrical appliances
The first PVGCS were often mounted on private family building roofs using the above scheme. Nowadays, these systems are increasingly being installed on apartment blocks, schools, agricultural and industrial buildings, etc. Additionally, where generous feed-in-tariffs are available, the scheme shown in figure 1.2 has been abandoned and replaced by the more advantageous one shown in figure 1.3. The latter allows the owner of the system to sell the generated electricity in its entirety to the grid. This beneficial layout has paved the way for energy utilities, operating companies and investment companies to deploy large-size PVGCS mounted on ground. In addition, especially in sunny sites, sun tracking systems have proven profitable, given the favourable financial support mentioned above.
(1)
(2) (5) (3)
(4)
(5) AC Loads
=
~ (1) PV modules
(2) Inverter
245,7
457,3
kWh
kWh
Electricity grid
(3) Metering device (4) Metering device (Electricty sold to (Electricity bought from the grid) the grid)
6
Figure 1.2. Simplified layout of a grid-connected PV system. PV-generated electricity is partly sold to the grid
=
245,7
~ (1) PV modules
(2) Inverter
kWh
Electricity grid
(3) Metering device (Electricty sold to the grid)
Figure 1.3. Simplified layout of a grid-connected PV system. All the PV-generated electricity is sold to the grid
If the characteristics of electricity are taken into account, the diagram shown in figure 1.3 can be broadly divided in two parts.
DC PART: from the PV generator to the inverter input, the main characteristic in this part is that the electricity is delivered as DC current. In this part PV modules, supporting structures, wires and DC connection boxes are included.
AC PART: from inverter to public electricity grid, in this part the electricity is delivered as AC current. In this part are included the following elements: inverter, wires,protective elements and a metering device intended to measure the electricity sold to the grid .
7
This division is useful when a PVGCS and its constitutive elements are described. Nevertheless there is a key element of grid connected systems which is related to the DC and the AC parts; namely, metal works and earth electrode. Such elements are elements of the safety system of PVGCS and are intended to protect against electrical shocks.
1.2.1 DC Part PV Modules, wires and connection boxes are the main elements that can be found in the DC part. The DC character of current and operation of modules pose many questions and new situations for novel electrical workers who are used to handling AC current.
1.2.1.1.
PV Modules
PV modules are probably one of the most important elements of PVGCS, when the PV modules are connected in serial and/or parallel configurations obtaining a PV generator. At the same time, modules are made by connecting photovoltaic solar cells, which are connected in series and parallel, to obtain higher current and voltage. To protect the cells against mechanical stress, weathering and humidity, the cells are embedded in a transparent material that also isolates the cells electrically. In most cases, glass is used but depending on the process it is possible to use acrylic plastic, metal or plastic sheeting. In contrast, the electrical connection of thin-film cells is an integral part of the cell fabrication and is achieved by cutting grooves in the individual layers. Finally, the standard modules have aluminium frame although it is possible to acquire frameless modules.
Solar cells included in PV modules convert directly the solar radiation into electrical energy. In the conversion process, the incident energy of the light creates mobile charged particles in some materials, known like semiconductors, which are separated by the device structure and produce electrical current. This current can be used to power an electric circuit.
The most commonly used photovoltaic cell material is silicon (Si), one of the most abundant elements on earth. The first commercially available cells
were 8
monocrystalline silicon in which all the silicon atoms are perfectly aligned building an organised crystal.In order to reduce costs, new manufacturing techniques were developed which in turn gave birth to the polycrystalline solar cells. This type of material contains many crystals and the atoms are aligned in diferent directions.
Figure 1.4. Main types of solar cells available in the present market
These techniques permit to manufacture solar cells in an easier, cheaper and faster way using less pure silicon. In this sense, development of thin film technologies has permitted further cost reductions by reducing the amount of material needed to make a solar cell. Some materials other than silicon such as cadmium telluride (CdTe), copper indium diselenide (CIS), amorphous silicon , etc. are used to manufacture solar cells. Many diferent solar cells are now available on the market and yet more are under development.
The types of modules are frequently divided according to the technology of the solar cells incorporated. In this sense, it is common to find in literature monocrystal Si modules, policrystal Si modules, amorphous Si modules, CdTe modules, CIS modules, etc. Following this way, a more in-depth explanation of the most important solar cells technologies existing nowadays is given below.
Crystalline silicon technologies. 9
The most important material for crystalline solar cells is silicon. This is the second most abundant element on earth though it is never found as a pure chemical element. It is bounded to oxygen in the form of silicon dioxide. So it is necessary to separate both elements by means of a chemical process to get metallurgical silicon with a purity of 98%. This type of silicon cannot be used to produce solar cells due to its low purity. So, it is necessary to apply another purification process which permits to obtain high-grade silicon (at least 99:9999999% of purity). This high-grade silicon can now be processed in diferent ways to produce monocrystalline or polycrystalline cells. It is not poisonous, and it is environment friendly, since its waste does not represent any problem.
Among all kinds of solar cells the silicon solar cells are the most widely used. Their efficiency is limited due to several factors. The energy of photons decreases at higher wavelengths. The highest wavelength at which the photon energy is still large enough to produce free electrons is 1.15Âľm (valid for silicon only). Radiation with higher wavelength causes only heating up of solar cell and does not produce any electrical current. Each photon can cause only production of one electron-hole pair. Even at lower wavelengths many photonsdo not produce any electron-hole pairs, yet they increase solar cell temperature. The highest achieved efficiency of a silicon solar cell in a Research Lab lies around 23%, while for other semi-conductor materials this figure rises up to 30%. In fact, eficiency is dependent on the semiconductor material. The losses are caused by metal contacts on the upper side of a solar cell, in addition a part of the solar radiation is reected on the upper side (glass) of solar cell. Crystalline solar cells are usually wafers, about 0.3 mm thick, sawn from a Si ingot with a diameter of 10 to 15 cm. They generate approximately 35 mA of current per cm2 area (together up to 2 A/cell) at voltage of 550mV at full illumination. The effciency in Lab of the solar cells exceeds 20%, while classically produced solar cells by commercial brands is usually above 15%. Actually, there are potential types of silicon solar cells: monocrystalline (single-crystalline), polycrystalline (both first types commented before) and amorphous. Nevertheless to create the amorphous silicon cells it is necessary a special technique of manufacturing, for this reason it is not usually catalog this cells together monocrystalline or polycrystalline otherwise besides thin film.
Thin film cells 10
During the last years, the development of thin-film processes for manufacturing solar cells has become more and more important. The process consists of applying a thin layer of photoactive semiconductors on a substrate (usually glass). The most common materials are: amorphous silicon (a-Si), thin multicrystalline silicon films on a low-cost substract, copper indium diselenide (CIS) and cadmium telluride (CdTe).The reduced material, the energy consumption and the automated production provides this technology with a very high potential for reducing costs when compared with crystalline silicon technology.
The amorphous silicon differs from crystalline silicon because silicon atoms are not located at very precise distances from each other and this randomness in the atomic structure has a powerful impact on the electronic properties of the material. The manufacturing process consists in the deposition on a low-cost glass of diferent layers of oxide, a-Si and a metallic contact. The efficiency of amorphous solar cells lies typically between 6 and 8%. The lifetime of amorphous cells is shorter than the lifetime of crystalline cells. Amorphous cells have current density of up to 15mA/cm2, and the voltage of the cell without connected load of 0.8 V, a larger figure than that of crystalline cells for this parameter. Their spectral response peaks at the wavelength range of blue light: therefore, the ideal light source for amorphous solar cells is a fluorescent lamp. The main disadvantage of the amorphous silicon is its low effciency (6-8%) which even diminishes during the first 6-12 months of operation. After this period of time, the efficiency gets a stable value. Related to the thin multicrystalline silicon films, a conductive ceramic substrate containing silicon is covered with a thin layer of polycrystalline silicon. The manufacturing process requires lower temperatures so it is possible to obtain high quality semiconductors which have very high potential to reduce costs.
Cadmium telluride (CdTe) is a thin-film material produced by deposition or by sputtering is a promising low cost foundation for photovoltaic applications in the future. The procedure disadvantage is that a poisonous material (cadmium) is used in its manufacturing, although some manufacturers support an insurance policy approach to funding the estimate futurecosts of reclaiming and recycling their modules at the end of their use. Labsolar cells efficiency is up to 16%, whilst the commercial types efficiency is up to 8%. 11
Copper-indium-diselenide (CuInSe2, or CIS) is a thin-film material with efficiencies ranging from some 13% in marketed modules to some 17% achieved at Research Labs. This is a is promising material, yet not widely used due to production specific procedures and to the scarcity of indium. Table 1.1 summarises the main characteristics of commercial solar cells. Table 1.1. Main characteristics of commercial solar cells Material
Efficiency
Nominal power degradation after 22-year outdoor exposure
Monocrystal
15-22%
Si
14,8%
(TedlarTM
Colour
a
and
EVA
Dark blue
encapsulant)
Multicrystal
13-15%
Si
6,4%
(Transparent
silicon
Blue
encapsulant)
Amorphous Si
8-15%
N/A
Red-blue, black
CdTe
6-9%
N/A
Dark green, black
CIS
7.5-9.5
N/A
Black
a
Source: Ewan D. Dunlop and David Halton, The Performance of Crystalline Silicon Photovoltaic Solar Modules after 22 Years of Continuous Outdoor Exposure, Prog. Photovolt: Res. Appl., DOI: 10.1002/pip.627
Nowadays, the PV market offers a huge range of the power output of the PV modules. It is possible to acquire PV modules from a few watts to several hundred of watts and the number of the companies which offer PV modules in the world is very high. A typical standard module consists of 36-72 cells and the power ranges from 75-270 Wp, in the case of crystalline cells. Sometimes, in some operation conditions solar cells in a PV module can be shaded and their temperature may increase until it causes damage in the material. This situation is known like ‘hot spots’ and when it appears the nominal power delivered by module is reduced dramatically. In order to avoid and prevent hot spots, the PV modules must incorporate bypass diodes. Usually, a bypass diode is connected to protect 18-20 solar cells.
1.2.1.2.
Cabling
The cabling of a PV installation is addressed to carry the electricity from the PV generator to the inverter and from the inverter to grid electricity company. It means that
12
the cabling is required in both DC and AC parts. Special attention must be paid in DC cabling because the features of DC current make this part more dangerous than AC if a shortcircuit takes place. For this reason it is advisable to use a isolation level category II in all wires used, so these types of cables have a double coating to make the cabling more resistant to weather conditions. In addition, the current that flows in the DC part (in most cases higher than that which ows in the AC part) makes advisable to use a suitable cable section to avoid losses in electrical production. In this sense, it has to be followed the advise which claims that the voltage drop in the cabling must not exceed 1.5%. Section 3 will resume this issue in order to size the suitable cross-section of the cabling in a PV installation.
Last, in order to make a correct layout of the cabling, it is advisable that the positive pole and negative pole are separated and clearly differentiated. In this sense the colour of the positive cable pole must be different than that of the negative, using in the most of the cases warm colours for the positive (i.e. red) pole and cold colours for negative pole (i.e. black). In the AC part it is advisable to use differentiated colours between phases and neutral-ground too.
1.2.1.3. Connection boxes Connection boxes are the elements where the strings of the PV generator are connected. The connection boxes role is two-fold: first, it ensures a weatherproof connection between strings and second, it includes several safety devices very advisable to protect the installation against electrical failures and weather problems like short circuits by humidity or degradation by prolonged exposure to solar UV radiation. Figure 1.6 will be used to illustrate and explain the elements included in DC connection boxes.
1. Each string from the PV generator must be guided to the connection box separately, positives lines bundled on one side and negatives ones bundled to another. This measure ensures a safety physical distance between positive and negative poles avoiding short circuits and enabling easy maintenance works. 2. Each string has a fuse to protect the line against reverse currents. The reverse currents may appear when one of the strings has a failure and the current of another strings flow through this faulty string. 13
3. Voltage surge arrestors (varistors) arrest possible overvoltages (e.g.: induced voltages in cable loops owing to lightning strikes near the installation) that may appear in the PV generator. 4. The DC switch is a very advisable element in order to break the flow of the DC current from generator to inverter.
Figure 1.6. State-of-the-art DC connection box. All its elements have a good placement and are accessible (Courtesy of Suntechnics)
5. All metal works and outputs from varistors must be connected to earth electrode. 6. The output cabling must be guided to the inverter or to another connection box. Obviously, the cross-section of these output wires must be higher that string cables.
14
1.2.2 AC Part The inverter(s), AC cabling, the DC main switch (and both the magnetothermic switch and the residential current circuit breaker) together with the energy meters are the main elements that are to be found in the AC part. The inverter is the paramount element in this part as the energy meter is a device chosen and installed by the electricity company in most of the cases. In fact, the inverter converts DC current into AC current of the same characteristics as those of the grid. This is way the inverter(s) are crucial elements in PV plants.
1.2.2.1. Inverter Grid-connected inverters are also known as grid-tied inverters. This device (figures 1.2 and 1.3) connects the PV array to the grid, or to both the grid and the AC loads of a building. It is mainly devoted to convert the solar DC electricity into AC electricity of the same characteristics as those of the grid, as commented above. The performance of these devices has significantly improved during the recent past and only small losses take place in this conversion. In PVPPs, as a particular case of PVGCS, the inverter is connected directly to the grid following the scheme depicted in figure 1.3, so all the generated electricity is fed into the grid.
15
Figure 1.7. Image of a 100-kW power rated inverter during the realization of a quality check.
PVGCS using inverters up to a power of 5 kW usually are usually single-phase systems. When this figure is exceeded, three-phase inverters are used (Figure 1.7). Making the most of the voltage-current curve of the PV generator requires the inverter to operate in the maximum power point (MPP) of this curve. This point ceaselessly changes according to environmental conditions, so suitable electronic devices must be available inside the inverter to track this MPP and maximize the DC power input.
Inverters often incorporate built-in trans-formers to electrically isolate the PVGCS from the grid. Transformerless inverters are smaller and lighter but not all national electrical regulation codes addressed to grid connected PV allow the use of such devices (i.e: the Spanish regulations do not allow to use transformerless inverters, while German regulations do).
16
The conversion efficiency (η) is the parameter is the ratio between the output AC power and the input DC power. This parameter takes into account losses caused by the transformer –if this device is built into the inverter- ohmic elements, switching devices, etc. It is worth noting that conversion efficiency depends on the input DC power: this is especially noticeable at low levels of irradiance impinging on the PV generator, which causes a lower load to be connected to the inverter. Manufacturers usually provide a curve depicting conversion efficiency versus output AC power: state-of-the-art inverters may achieve a peak in this curve of some 95%. In order to make sound efficiency-based comparisons of inverters, a reasonable way of measuring efficiency taking into account different climate conditions (Euro efficiency, or η
Euro)
was introduced by defining the
Euro efficiency (η Euro). The Euro efficiency is a parameter weighted for the European climate, taking into account different load conditions due to climate. Parameter η Euro is stated as:
Euro E
0.03 0
5%
0.06 0
10% 10
0.13 0
20% 20
0.1 0
30% 30
0.48 0
50% 50
0.2 0
100% 10
(1.1)
Where the subscript of parameter η refers to the efficiency of the inverter at a load expressed as a percentage of the nominal AC load (100%) which corresponds to η 100% . It must be pointed out that the different weights assigned to each figure of η at different loads was carried out bearing in mind the Central European climate. State-of-the-art inverters may achieve a η Euro ranging from 92 to 96 per cent. 1.2.2.2. Energy meters The energy meter (figure 1.8) is the element aimed at measuring the AC electricity produced by the PV installation. This device is placed just before the connection point of the grid, after the inverter. Obviously, the energy meter is a device installed and checked by the grid electricity company so that neither the installer or the owner of the PV system may manipulate it, for obvious reasons.
17
Figure 1.8. Three-phase energy meter with a monitoring and communication system.
Almost all the energy meters installed nowadays have a monitoring system to store the readings. Then, the readings are accessible for both the installation owner and the electricity company.
1.2.3 Metal works and earth electrode Both AC and AC parts have conductive metal works which may be accessible to people. The earth electrode is a protective element meant to prevent these metal works from rendering electrical shocks to persons. In fact, a dangerous situation may take place if a DC or AC wire experiences an isolation fault and it gets in touch with a metal part of the installation. In this sense and to prevent risky situations like this one, all the metal works of the PV installation such as the inverter chassis, module frames, DC connection boxes must be connected with the earth electrode. In this case, if an isolation fault appears, the earth electrode would play the role of a drain that avoids the risk of an electrical shock. In addition, one of the terminals of the surge arresters is connected to
18
the earth electrode: this element provides the way to drain the overcurrent that is carried through these surge arresters.
In spite of being not an active part of the PVGCS, the earth electrode connected to the metal works are the key to solve safety problems related to isolation failures, overcurrents and overvoltages. Since the PV plants are usually ungrounded for the sake of safety –and many national electrical regulation codes enforce this electrical schemenone of its poles (positive o negative) are connected to the earth electrode, the correct design of this element is an issue to be attended carefully. Thus, it is highly advisable that the resistance of earth electrode do not be over to 37 ohms. In addition, the connection between all the metal works and the earth electrode must be easily visible and accessible in order to check the system safety (figure 1.8).
Figure 1.8. Connection point between the earth electrode and various metal works in a PV installation.
19
1.5. Some electrical characteristics of a typical 1-MWp PVPP Given the wide variety of existing marketed devices used to build PVPP’s within the power range that the ‘PVs in Bloom’ project is focused on (50 kWp - 2 MWp) and the different technical solutions that may be adopted to install a PVPP of a given peak power, it is difficult to furnish the reader with some typical electrical characteristics of such systems. However, an example of a typical PVPP of some 1-MWp implementation may help get an idea of the range of voltage, current and power these systems deal with.
A widespread technical solution aimed at deploying large-scale PVPPs (with rated power equal or greater than 1-MWp) may consist of dividing it into smaller PV subsystems. A state-of-the-art feasible solution may comprise ten 120-MWp subsystems. Each subsystem PV generator is connected to a 3-phase 100-kW inverter whilst each couple of inverters are fed to a 400-kVA 380V / 20 kV1 transformer (five of such transformers are required in total). Figure 1.9 depicts the electric scheme for such a 1.2-MWp PVPP. In this figures, the ten energy meters (one for each inverter) may also be replaced for just only one placed at the high voltage output of the transformer. In fact, placing the energy meter at either the low voltage input or the high voltage output of the latter device usually has to do more with legal matters than with technical constraints
1
The figure for the high voltage side of the transformer may vary depending on the country electrical distribution system. The nominal power of the transformer is deliberately oversized up to twice the inverter connected power. 20
=
245,7
=
5 X
kWh
GRID
~
345,2
~
kWh
400-kVA 380 / 20 kV transformer Two 120-kWp PV generators
Two 100-kW 3-phase inverters
Figure 1.9. Electric scheme of a possible technical solution for a 1.2-MWp PVPP.
The main electrical characteristics in STC of the PV generator of each one of these possible ten subsystems are gathered in Table 1.2. Table 1.2. Main electrical characteristics in STC of the PV generator of a subsystem of the typical PVPP of some 1 MWp described in this section. The figures for these electric characteristics have been chosen taking into account state-of the art crystalline silicon modules and inverters –which drive the selection of series-connected and parallel-connected modules- marketed at the date of writing this document Nominal power
Open-circuit
Short-circuit
Voltage at
Current at
(Wp)
voltage (V)
current (A)
maximum power
maximum power
point (V)
point (A)
120 000
790
205
631
190
BRIEF SUMMARY OF SECTION 1 Throughout section 1 the main features of a photovoltaic grid connected system have been detailed. In order to describe these systems, a suitable division has been done. In this sense, any of these systems is roughly compounded of three
21
different parts. So, each part is commented and its constitutive elements have been approached
DC part: it stretches from the PV generator to the inverter input; the main characteristic in this part is that the electricity is delivered as DC current. PV modules, supporting structures, protective elements, wires and DC connection boxes are included in the DC part. The characteristics (efficiency, encapsulation, degradation, etc.) and types (monocrystal, policrystal or thin film) of PV cells and PV modules have been emphasized in this section.
AC part: it stretches from the inverter to public electricity grid; in this part the electricity is delivered as AC current. Inverter, wires, protective elements and a metering device intended to measure the electricity sold to the grid. The inverter efficiency has been emphasized in this section, including equations to calculate this parameter.
Metal works and earth electrode: this part is aimed to avoiding electrical shocks to people. Concepts like overcurrents and overvoltages in PV plants together with the elements addressed to prevent these failures have been presented
Some electrical characteristics of a typical 1-MWp PVPP are provided to help the reader to achieve a better understanding of this PV concept
22
2. Estimating the annual energy produced by a PV grid-connected system Although the cost of a typical on-ground PV installation ranging from 50 kWp to 2 MWp (the size range of the PVPPs that the project PVs in Bloom deals with) has dramatically been reduced by some 35% during the years 2007-2009, the initial investment the installation requires forces the prospective owner in many cases to take money on loan from a bank. The future energy production of the plant is the best warranty for the owner –and for the bank, of course- in order to acomplish the payment of the loan. This fact may help to get an idea of the importance of making a good estimate of the annual energy produced by a PV grid-connected system. This section aims at explaining how to calculate the annual electricity yield of a PV grid-connected system. In addition, the online existing tools to evaluate the solar resource (the main uncertainty source) are going to be detailed hereafter as well.
2.1 Assessment on the solar resource of the site Knowing the solar resource is the first step to evaluate the annual production of a PV plant. This means that it is necessary to know the annual incident irradiation on the PV generator. In addition, both the module slope (β, or tilt angle, which lies between 0º and 90º) and orientation (α, or azimuth, East = -90º, South = 0º, West = 90º) have to be taken into account in this issue because the irradiation received over one year by a surface with an arbitrary tilt angle and azimuth may largely differ from the irradiation collected by a horizontal surface (the most common available irradiation data in solar databases). There are some methods to determine the former parameter from the latter, but they lie out of the scope of this work. Anyway, it is useful to know that an Equatorfacing PV generator –it implies South-facing (α = 0º) and North-facing (α = 180º) for North and South hemispheres, respectively- with a tilt angle slightly lower than the local latitude (βopt) maximizes the collected annual global irradiation and consequently maximizes the electricity generation. Figure 2.1 illustrates the features related to the tilt angle β and the azimuth α.
23
Figure 2.1.: Slope and orientation of a PV generator (source: IDAE, 2002. Instalaciones de Energía Solar Fotovoltaica. Pliego de Condiciones Técnicas de Instalaciones Conectadas a Red. IDAE, Madrid, p.53)
Before starting to introduce how to evaluate the solar resource, it is interesting to explain what the irradiation is and what the differences between irradiation (H) and irradiance (G) are. In order to see the difference between these two terms, Figure 2.2 may be useful for this purpose. Figure 2.2-A depicts a graph of measured irradiance vs. time during a sunny day. As it is shown, the irradiance has units of watts per square meter (W/m2) so the irradiance is the incident sunlight power density. Since the irradiance is nothing but sunlight power per square meter, the instantaneous character of the irradiance has to be emphasized. In Figure 2.2-B, the area under the latter irradiance curve and x-axis has been coloured in red: this area is the irradiation collected over this day. Thus, the irradiation has units of W•s/ m2 or kWh/m2: this means energy collected per square meter during a specific time interval. If the considered time interval is a day or a year, the terms ‘daily irradiation’ or annual irradiation’ may be used.
Figure 2.2. Graph A depicts the measured irradiance during a sunny day whilst the red area of graph B equals the collected irradiation during this sunny day
24
Given the statistical nature of the irradiation profile of a site, annual or monthly average values for the daily irradiation (Hda(0) and Hma(0), respectively) are commonly used when designing PV systems. As commented earlier, these average values are available only for horizontal surfaces in most solar databases. However, for installations located in European sunny climates and with an optimun tilt angle, equation 2.1 is a rule-ofthumb that broadly relates the annual average horizontal irradiation -H(0)- and the annual average irradiation collected on a equator-facing, βopt –tilted surface -H(0,βopt): 2 1 H ( 0, op opt )[ kWh·m · year ] This obviously means that:
1.15 H ( 0 )[ kWh·m 2 · year 1 ]
(2.1)
2 1 H da ( 0, op 1.15 H da ( 0 )[ kWh·m 2 ·day 1 ]·365 (2.2) opt )[ kWh·m ·day ]·365 This is: 2 1 H da ( 0, op 1.15 H da ( 0 )[ kWh·m 2 ·day 1 ] (2.3) opt )[ kWh·m ·day ]
If irradiation collected on surfaces with an arbitrarily azimuth angle α and tilt angle β is to be estimated -H(α,β)- some graphs proposed in literature may be of great help. Thus, figure 2.3 is intended to derive the latter value from H(0) and it can be applied to similar range of latitudes to those of Spain (i.e.: Southern European countries). An example is provided to achieve a better understanding of its use.
25
Figure 2.3. Percentage ratio between the average annual daily radiation on an arbitrarily oriented surface and the maximum value of this parameter in Madrid (α = 0 ° and β =35 °) (source: IDAE, 2002. Instalaciones de Energía Solar Fotovoltaica. Pliego de Condiciones Técnicas de Instalaciones Conectadas IDAE, Madrid, p.55)
The concentric circumferences represent the tilt angle while the radii indicate the orientation (azimuth angle) of the surface in figure 2.3. For example, let us assume that the location is Jaén, Spain (37°N latitude, 3ºW longitude) where Hda(0) = 4.9 kWh·m2
day-1. Hda(0) is located in the centre of the circle (blue dot). It stems from the colour
code of the figure that Hda(0) =0.85·Hda(0°,35°). Consequently, Hda(0°,35°)=Hda(0) / 0.85= 5.8 kWh·m-2 day-1 (black dot). Let us now assume a surface with 60º
(red
dot).
According
to
the
colour
code
of
the
= -30º y figure,
=
Hda(-
30°,60º)=0.85·Hda(0°,35°)= 4.93 kWh·m-2 day-1. The white central area suggests that collected irradiation show relative little sensitivity to small deviations from the optimal orientation and tilt angle. There are some other graphs in literature intended for the same purpose as that described above. For instance, figure 2.4 provides the average annual irradiation (kWh·m-2·year-1) in Berlin according to the azimuth and tilt angle of the considered 26
surface. The relative shape of the contour lines –not the specific values of the average annual irradiation- may apply to Central European climates
Figure2.4. Average annual irradiation (kWh·m-2·year-1) in Berlin depending on the azimuth and tilt angle (Source: DGS and Ecofys, 2005. Planning and Installing Photovoltaic Systems. A guide for installers, architects and engineers, James & James, London, p. 13)
Two-axis tracking in Southern Europe may achieve irradiation gains up to some 40% when compared to static surfaces optimally oriented and tilted (0,βopt). This gain lowers down to some 30% in Central Europe, due to its cloudier climate. Single-axis tracking in Southern Europe may achieve irradiation gains up to some 25-33% -depending on the tracking method- when compared to static systems to static surfaces optimally oriented and tilted (0,βopt). This gain lowers down to some 20% in Central Europe, owing to the same fact as that mentioned earlier.
Apart from the above graphical methods, there are some convenient software tools addressed to evaluate the irradiation on an arbitrarily inclined and oriented surface for a specific site (determined by its latitude and longitude). Most of this software tools work with a data base obtained through two ways: data collected by ground-based measurements and/or satellite-derived data. These software applications usually have a software engine which is able to evaluate the irradiation through complex interpolation methods taking into account the data from several meteorological stations and/or satellite observations around the placement of the PV plant.
In this sense, programs like Meteonorm, Sundy and Shell Solar Path make possible and easy to evaluate the annual irradiation of a given site. There are some free online software tools to estimate the irradiation too. In this way, for Europe and Africa locations, the EC-funded PVGIS project (http://re.jrc.ec.europa.eu/pvgis/) gives support 27
through a excelent web aplication shown in figure 2.5. The application options -which has been designed for PV projects- makes it possible to include a lot of technical characteristics of the PV installation even if the installation uses tracking techniques.
Figure2.5. Web application to estimate the irradiation included in PVGIS web site (source: http://re.jrc.ec.europa.eu/pvgis/apps3/pvest.php#).
Last, the NASA website (http://eosweb.larc.nasa.gov/sse/) provides online Irradiation data but in this case the values are available for any place around the world.
2.2. Estimating the annual electricity yield of a PV grid-connected system A system is said to be 1-kWp rated if its PV generator produces 1 kW under Standard Test Conditions (STC). These conditions consist of a global irradiance of 1000 W·m-2 with a spectral distribution conforming to the AM 1.5G spectrum and a PV module cell temperature of 25ºC. Despite this apparently complex definition, PV system rating using kWp (or its multiples) is convenient, since it enables a straightforward estimation of the annual energy yield of a PVGCS (EPV) by means of the following equation: E PV [ kWh· yearr 1 ]
H ( , ))[ kWh·m 2 · yearr 1 ] ·P* [ kWp ] · PR (2.4)
28
Where P* = PV generator power in STC and PR = performance ratio
The performance ratio is related to the efficiency of the system together with many other losses that inevitably take place –operation temperature losses, power conditioning and wiring losses, etc- and influence electricity generation in PV systems. PR values for well designed PVGCS may be assumed ranging from 0.70 to 0.80. These figures are in good agreement with many available performance data.
An example may help to achieve a better understanding of eqn. (2.4). Let us assume a 1MWp PVGCS located on a site where the average annual irradiation on the PV generator equals 1900 kWh·m-2·year-1. If a figure of 0.7 is assumed for the performance ratio of the system, then: E PV (kWh·year 1 ) 1900 1 kWh·m 2 ·year 1 ·1000 kWp·0.7 1330000 1 kWh·year
1
A commonly used parameter to assess the amount of solar electricity produced by a PVGCS is the final yield (Yf, in kWh·kWp-1·year-1). Figure 2.6 depicts some minimum and maximum values for this parameter in some countries. Also, Table 2.1 gathers some typical values for this parameter calculated in some specific sites located in each project partner country.
29
Figure 2.6. Minimum and maximum annual PV electricity yields in different countries produced by a 1kWp system (kWh year-1) with optimally inclined PV modules and performance ratio equal to 0.75. (Sources: European Commission Joint Research Centre, http://re.jrc.cec.eu.int/pvgis/apps/pvest.php?lang=en&map=Europe; and National Renewable Energy Laboratory, http://www.nrel.gov/rredc/pvwatts/). Table 2.1 Typical values for this parameter calculated in some specific sites located in each project partner country. N.B.: PVGIS software has been used. Equator-facing and optimally tilted static structures together with a performance ratio that equals 0.8 have been assumed Place
Latitude, longitude Optimal tilt angle (º)
Yf, (kWh·kWp-1·year-1)
Representative places from Italy Padova (Italy)
45.410N, 11.877E
34°
1144
Belluno (Italy)
46.140N, 12.218E
36º
1096
Berchidda (Italy)
40.785N, 9.166E
34°
1456
Lugo di Vicenza (Italy)
45.746N, 11.530E
35º
1112
Mores (Italy)
41.474N, 1.564E
34º
1376
Sassari (Italy)
40.727N, 8.56E
34°
1456
Siliqua (Italy)
39.301N, 8.81E
34°
1472
Representative places from Greece Afetes (Greece)
39.283N, 23.18E
30°
1328
Aiginio (Greece)
40.511N, 22.54E
31°
1280
Lefkonas (Greece)
41.099N, 23.50E
31°
1224
Milies (Greece)
39.328N, 23.15E
30°
1352
Sourpi (Greece)
39.103N, 22.90E
29°
1304
30
Representative places from Poland Adamow (Poland)
50.595N, 23.15E
35°
Gmina Wisznice (Poland)
51.789N, 23.21E
36°
Urzad Miasta Lublin (Poland)
51.248N, 22.57E
36°
936 944 936
Representative places from Austria Burgau (Austria)
48.432N, 10.41E
36°
Fürstenfeld (Austria)
47.095N, 15.98E
35°
1000 1064
Representative places from Slovakia Drahovce
48.518N, 17.80E
35°
Bacuch
48.859N, 19,81E
38°
1040 1024
Representative places from Spain Valencia
39.470N, -0.377E
35°
Jaén
37.766N, -3.790E
33°
Alcaudete
37.591, -4.087E
33°
Hornos
38.217N, -2.720E
32°
1400 1544 1560 1520
BRIEF SUMMARY OF SECTION 2 Explaining how to calculate the solar irradiaton collected on a surface with a given orientation (α) and tilt angle (β), paves the way to calculate the energy produced by a PV plant. Some graphical methods have been provided to estimate the solar irradiaton collected on an arbitrarily oriented and tilted surface. (H(α ,β)). Some software tools addressed to the same purpose have been introduced An equation that combines accuracy and simplicity aimed at calculating the annual energy production of the installation has been presented:
E PV [ kWh· yearr 1 ]
H ( , ))[ kWh·m 2 · yearr 1 ] ·P* [ kWp ] · PR
Where P* = PV generator power in STC and PR = performance ratio (0.7-0.8)
31
3. Sizing PV grid-connected systems This section deals with the basic concepts aimed at sizing a PV grid-connected system deployed on a degraded area (a PVPP). Accomplishing an in-depth explanation of how to design a PVPP by means of a rigorous and universal approach, covering each configuration, would encompass nearly every possible case. On the other hand, this would require much more effort and would reduce the understandability of the text. Consequently, the concepts presented hereafter have been simplified to some extent and only sizing flat-plate module PVGCS with central inverter is studied.
3.1. Choosing the PV module The used PV modules highly determine the sizing of the remaining PVGCS elements. A rough estimate of 10 m2 of required area per installed kWp is useful as a first approach. Taking into account the present state of the art, more accurate estimations are gathered in table 3.1, depending on the solar cell technology. Mono and polycrystalline silicon solar cells still hold the lion’s share of the PV market, but new promising technologies like that based on CdTe are increasing their presence in it. 1 kWp 10 m2 of required surface (crystalline silicon) if the PV modules are deployed in the same plane as the surface –roof or terrain- on which they are supported It is worth noting that the above considerations are true if the PV modules are deployed in the same plane as the surface –roof or terrain- on which they are supported. This is not the case in most PVPPs. In PVPPs, making an estimate of the required area for the system may turn into a complex problem which involves local latitude, terrain slope, module tilt angle, etc. However, for the sake of simplicity, the following statements will be assumed: horizontal terrain surface, tilt angle slightly lower than the latitude, and no self shadowing between PV module arrays. Taking into account the present state of the art as above, table 3.2 shows the required terrain surface to install a 1-kWp PVGCS, depending on the solar cell technology. Table 3.1. Required surface for a 1-kWp PVGCS if PV modules are deployed in the same plane as the surface –roof or terrain- on which they are supported (Source: DGS y Ecofys, 2008. Planning and Installing
32
Photovoltaic Systems. A guide for installers, architects and engineers. Second Edition. James & James, London, p. 151) Technology
1 kWp
Surface (m2)
Monocrystalline silicon
7-9
Polycrystalline silicon
8-11
Copper Indium Diselenide (CIS)
11-13
Cadmium Telluride (CdTe)
14-18
Amorphous silicon
16-20
20 m2 of required surface (crystalline silicon) if the PV modules are deployed
on an horizontal terrain surface, tilt angle slightly lower than the latitude and with no selfshadowing between PV module arrays Tabla 3.2 Required surface for 1-kWp if the PV modules are deployed on an horizontal terrain surface, tilt angle slightly lower than the latitude and with no self-shadowing between PV module arrays. Note: the figures gathered here are somewhat overestimated. More accurate calculations for each specific latitude may lead to smaller values of the required surface Technology
Surface (m2)
Monocrystalline silicon
20
Polycrystalline silicon
27
Copper Indium Diselenide (CIS)
32
Cadmium Telluride (CdTe)
40
Both inverter and PV modules manufacturers supply the most characteristic electrical parameters of their products. The most relevant ones are shown in Tables 3.3 and 3.4. As it will be shown hereafter, these parameters are paramount for the system design. Some other features such as weight, dimensions, etc. are also usually enclosed in the manufacturer data sheets
33
Table 3.3. Most relevant electrical parameters of a PV module usually supplied by its manufacturer Parameter Short circuit current temperature coefficient (mA·ºC-1) Open circuit voltage temperature coefficient (mV·ºC-1) Current at the MPP at STC (A) Short circuit current at STC (A) Parallel connected cells Series connected cells Maximum power at STC (Wp) Nominal operation cell temperature (ºC) Voltage at the MPP at STC (V) Open circuit voltage at STC (V)
Symbol IMOD,SC VMOD,OC IMOD,M,STC IMOD,SC,STC Ncp Ncs PMOD,M,STC NOTC VMOD,M,STC VMOD,OC,STC
Table 3.4. Most relevant electrical parameters of an inverter usually supplied by its manufacturer
Parameter
Symbol
Maximum efficiency (adim)
INV,M
Power factor (adim)
cos f
Grid frequency (Hz) Maximum input DC current (A)
IINV,M,DC
Nominal output AC current (A)
IINV,AC
Lowest voltage at which the inverter tracks the MPP (V)
VINV,m,MPP
Highest voltage at which the inverter tracks the MPP (V)
VINV,M,MPP
Nominal input power (W)
PINV,DC
Nominal output power (W)
PINV,AC
Maximum input voltage (V)
VINV,M
Nominal output voltage (V)
VINV,AC
3.2. Sizing the nominal power of the PV generator Planning the nominal power of a PV generator (the sum of the maximum power at STC of the modules used) may depend on two criteria. It is up to the owner to select the most restrictive one:
- Available area: this is especially crucial, and table 3.2 must be kept in mind
34
-
Cost of the installed PVGCS. Nowadays, a rough estimate of the initial investment on the system may range from some 3,000 to 6,000 Euro. Anyway, the cost of crystalline silicon modules has experienced a sharp decline during the years 2007-09 and it seems this downward trend will continue in the short-term.
The PV generator is composed by arranging parallel connections between seriesconnected modules (strings). Consequently, the voltage of the PV generator equals the voltage of one string, whilst its current equals the sum of the current of all parallel connected strings.
3.3. Sizing the nominal power of the inverter Prior to provide some guidance aimed at sizing the nominal power of the inverter, some advice must be provided regarding its location. In general, the inverter must be close to the AC protective devices (surge arresters, residual current circuit breaker, etc.) and the energy meter. It is also advised to place the DC connection box –where the strings are parallel connected-as near as possible to the inverter, so that voltage drops through cables are minimized. Despite many inverters comply with IP-code 65, a weatherproof hut is advisable to preserve these devices from the environment. Obviously, all the manufacturer recommendations concerning temperature and humidity must be strictly followed. As commented in a previous section, in general, only three-phase inverters are available over 5 kW.
A useful parameter addressed to size the nominal input power (PINV,DC) of the inverter is the sizing factor FS = PINV,DC / PGFV,M,STC , where PGFV,M,STC is the maximum power of the PV generator at STC. A widespread recommendation of FS according to the latitude is shown in Table 3.5. These figures are suggested provided that an equator-facing PV generator with a tilt angle close to the latitude is planned.
35
Table 3.5. Recommended values for Fs in Europe as a function of the latitude (Source: Jantsch M., Schmidt H., Schmid, J., 1992. Results on the concerted action on power conditioning and control. Proceedings of the XI European PV Solar Energy Conference and Exhibition, Montreux, Switzerland, pp. 1589-1592) Fs
Zone Northern Europe (lat. 55 - 70º)
0,65 – 0,8
Central Europe (lat. 45 - 55º)
0,75 – 0,9
Southern Europe (lat. 35 - 45º)
0,85 – 1,0
Fs must be lowered down as latitude increases. This is due to the fact that STC rarely occur outdoors and the PV generator power output hardly exceeds PGFV,M,STC in Europe as a whole. However, the sunny climate of Southern Europe cause the electricity generated by a PVGCS to be generated at high levels of irradiance. These high levels of irradiance imply PV generator power output is close to PGFV,M,STC and sometimes exceeds it. Then, it is advised that 0,8·PGFV,M,STC
PINV,DC
PGFV,M,STC (0,8
Fs
1) so that the inverter is
not overloaded for a long time. Obviously, lower values of Fs for Northernmost latitudes increases the energy performance and leads to select inverters with a smaller power for the same nominal power of the PV generator.
Apart from the above considerations, there is a considerable degree of freedom when choosing Fs. In practical terms, and provided that Fs is not too low, the influence of Fs in the performance of the PVGCS is scarcely relevant. In this sense, it has been identified a trend in designers of PVGCS in sunny climates, who often choose Fs = 1.
3.4. Sizing the number of PV modules
In principle, if a nominal power of the PV generator given by PGFV,M,STC is to be achieved using modules with a nominal power of PMOD,M,STC, the number of these modules to be installed may be written as:
N
Int
PGFV , M , STC PMOD , M , STC
(3.1)
36
Eq. (3.1) is a first approach to the number of modules required, as sizing the PV generator requires to determine the number of series connected modules or strings (Nms) which are to be parallel connected connected (Nmp). Both figures depend on the specific PV module and the voltage range where the inverter tracks the MPP. Additionally, special care must be taken not to exceed the maximum input voltage of the inverter. As shown hereafter, not always N equals Nmp 路 Nms. More specifically: a) Nms must be chosen so that the sum of voltages at the MPP of all the modules in a string lies within the voltage range where the inverter tracks the MPP in the V-I curve of the PV generator. Nms must be sized so that the voltage at the inverter input never exceeds the maximum voltage that this device can withstand (VINV,M) b)
Some strings must be parallel-connected (Nmp) until the nominal power of the PV generator is approximately achieved. Nmp must be sized so that the current fed at the inverter input does not exceed its maximum rating (IINV,M,DC)
3.5. Sizing the number of series-connected modules Nms must lie within a minimum and maximum limit. The calculation of these limits is detailed below.
3.5.1. Maximum number of series-connected modules
Low temperatures make the open circuit voltage of the PV generator increase. The most dangerous situation may take place in a cold winter day when the inverter is disconnected (owing to a grid failure, for example). A high voltage appears at the inverter input that could seriously harm the device if this voltage exceeds the maximum voltage that this device can withstand (VINV,M). Despite being conservative, a widespread criterion assumes that the cell temperature (Tc ) may drop down to -10潞C. In this case, the maximum number of series-connected modules that can be fed to the inverter is given by:
37
máx ( N ms )
Int
V INV , M V MOD ,OC (Tc
(3.2) 10º C )
The PV module data sheets do not supply its open circuit voltage at Tc = -10ºC, but these data sheets usually show the open circuit voltage temperature coefficient VMOD,OC (usually expressed in mV·ºC-1), so that ( VMOD,OC < 0):
VMOD ,OC (Tc
7 70º C)
VMOD ,OC , STC
(3.3)
3 35º· VM MOD ,OC
If VMOD,OC is expressed in ºC-1, eq. (3.3) turns into:
VMOD ,OC (Tc
70 7 º C)
(3.4)
VMOD ,OC , STC (1 35 3 º· VM MOD ,OC )
The following approximation might be used for mono and policrystalline silicon:
VMOD ,OC (Tc
10 1 º C)
(3.5)
1, 1,14·VMOD ,OC , STC
3.5.2. Minimum number of series-connected modules
High temperatures make both the open circuit and the MPP voltage of the PV generator decrease. If the latter drops below the lowest voltage at which the inverter tracks the MPP (VINV,m,MPP), this device cannot get the maximum power from the PV generator and it could even shut off. A widespread criterion assumes that the cell temperature (Tc ) may rise up down to 70ºC: in this case, a minimum number of series connected modules must be ensured to avoid the situation described above:
mín ( N ms )
Int In
V INV ,m, MPP V MOD , M (Tc
(3.6)
1
70 7 ºC)
The quotient VINV,m,MPP / VMOD,M(Tc=
70ºC)
must be increased in one unit to ensure in
excess rounding. As commented earlier, the PV module data sheets do not supply its
38
voltage at MPP at Tc = 70ºC, but it may be calculated as follows (remember that VMOD,OC < 0):
VMOD , M (Tc
7 70º C)
VMOD , M , STC
45 4 º· VM MOD ,OC
(3.7)
If VMOD,OC is expressed in ºC-1, eq. (3.7) turns into:
VMOD , M (Tc
7 70º C)
VMOD , M , STC (1 4 45º· VM MOD ,OC )
(3.8)
The following approximation might be used for mono and policrystalline silicon:
VMOD , M (Tc
7 70º C)
0,82·VMOD , M , STC
(3.8)
Figure 3.1 is addressed to clarify the above considerations and calculations. Once the minimum and maximum number of series connected modules is ascertained, a figure between them must be selected.
3.6. Sizing the number of parallel connected modules
Once Nms has been determined, the number of parallel connected modules is calculated as: N mp
Int
N N ms
(3.9)
As commented earlier, usually N
Nms · Nmp. Further, the inverter input current must
never exceed its maximum rating (IINV,M,DC). Consequently, the following inequation has to be verified:
Nmp I MOD , SC, STC
I INV , M , DC
(3.10)
If inequation (3.10) is not true, a higher figure for Nms should be chosen, so that a lower value for Nmp is obtained by means of eq. (3.9). This new lower value of Nmp must comply with eq (3.10). 39
Voltage window where the inverter tracks the PV generator MPP
I (A)
Tc = 25ºC
Tc = -10ºC
Tc = 70ºC
Maximum input voltage at the inverter input
V (V) Inverter shut-off voltage
Lowest voltage at which the inverter tracks the MPP
Highest voltage at which the inverter tracks the MPP
Fig. 3.1. Voltage-current curves of a PV generator at different cell temperatures (Tc) and identical irradiance (G) together with characteristic voltages of the inverter. N.B.: the second-order influence that the cell temperature exerts on the short circuit current has been neglected in the figure
... Fuses
…
…
...
...
+
DC main switch
Residual current circuit breaker
Magnetothermic switch Inverter enclosure
DC main cable
-
…
Metal works (supporting structure)
DC connection box
Energy meter
L1
=
~
130,5
kWh
N
Inverter Surge arresters
Surge arresters
Grid
Surge arresters
...
PE
Earth bar
PV generator
Figure 3.2. Detailed scheme of a PVGCS (it has been assumed a single-phase inverter, although this scheme also applies basically to a three-phase one)
40
3.7. Sizing the cabling Figure 3.2 depicts a detailed PVGCS scheme. PV modules are series connected in strings which are parallel connected in the DC connection box by means of cables whose length may vary depending on how far module strings are from this box. The DC main cable connects the DC connection box to a main DC switch located at the inverter input. The DC main cable cross-section is obviously larger than those of the strings, since it carries the sum of the currents that are carried by each string cable. A magnetothermic switch is placed at the inverter output, together with a residual current circuit breaker. Then, the electricity is fed to the grid through the energy meter device. Regarding more detailed engineering details, each project partner must ensure that the PVGCS complies with its national low voltage regulation code by reviewing it.
Sizing the cabling implies taking into account three crucial criteria: a) the withstand voltage, b) the current carrying capacity and c) limiting the voltage drops through cables at STC so that losses are minimized. Most marketed cables usually withstand voltages up to 1000 V, which is a figure that is not exceeded in general by PV systems. Additionally, many cables are prepared to be laid outdoors, so this does not pose any problem in PV systems. Consequently, sizing the cables mainly implies taking into account criteria b) and c) so that the most restrictive of them imposes the cable crosssection to be selected.
3.7.1. Current carrying capacity
The maximum current that can flow through cables depends mostly on their crosssection, and also on ambient temperature, their layout, if they are bundled or not, etc. Values for the maximum currents vs. cross-section can be consulted in standard IEC 60512 part 3, although some countries have their own adapted standards (in Spain, the standard AENOR EA 0038 applies). Additionally, IEC 60512 prescribes that PV cables must be earth-fault proof and short-circuit proof.
41
According to IEC 60364-7-712 –at its operation temperature- each string cable must be able to carry 1.25 times the short circuit current at STC of the string (the same current as that of a single module) provided that fuses are available to avoid reverse currents, as commented earlier. The same current carrying criterion applies to both the DC main cable and the AC cable at the inverter output.
3.7.2. Limiting the voltage drops through cables at STC
Each project partner must review their national regulations concerning allowed or recommended voltage drops at STC through cables (both in the DC and AC parts). In the case of Spain, it is recommended a 1.5% of the voltage of the PV generator at MPP at STC for the DC part, while not exceeding this figure for the inverter nominal output voltage is compulsory in the AC part. The calculation of the minimal cable cross-section of a string cable (Sm,string, in mm2) in DC as a function of the voltage drop allowed in a string ( Vstring, as a fraction of the voltage of the PV generator –which equals that of the string- at MPP at STC) is derived from the following equation, for a string of a simple cable length Lstring (m):
2·L S
m, string
Symbol
·I string MOD, M , STC
V ·N ·V · string ms MOD, M , STC
stands for conductivity, which in the case of copper equals 56 m·
(3.11)
-1
·mm-2.
The term Nms·VMOD,M,STC is the voltage of the PV generator at MPP at STC. If the DC main cable has a simple cable length Lmain (m), its minimal cross-section (Sm,main, in mm2) as a function of the voltage drop allowed in this cable ( Vmain, as a fraction of the voltage of the PV generator at MPP at STC) is derived from the following equation, very similar to eq. (3.11):
S m,main
2·Lmain ·N mp ·I MOD ,M ,STC Vmmain ·N ms ·VMOD ,M ,STC ·
(3.12)
42
Regarding the minimal cross-section of the cable in the AC part (Sm,AC, in mm2) as a function of the voltage drop allowed in this part ( VAC, as a fraction of the nominal inverter output voltage), it may be written as:
S m, AC
S m , AC
2·L AC ·I INV , AC ·cos V AAC ·VINV , AC ·
3·L AC ·I INV , AC ·cos V AC A ·V INV , AC ·
(isingle - phaseinverter)
(3.13)
( three - phaseinverter)
(3.14)
Where LAC (m) es la simple AC cable length and IINV,AC (A) is the nominal inverter output current
3.8. Sizing some protective measures
A comprehensive review of the sizing of all required and advisable protective measures for PVGCS lies out of the aims and scope of this document. So that it is strongly suggested that the readers should review the sections of their national low voltage regulation codes that deal with this important issue. Anyway, a short review of highly advisable protective measures depicted in figure 3.2 is detailed below:
PV modules are manufactured with built-in bypass diodes to avoid local overheatings (hot spots) that may seriously harm the module in case of severe shadowing, cracked cells, faulty V-I module curve, etc.
Despite being widely used in the past, blocking diodes addressed to prevent reverse currents have been nearly replaced by fuses completely, due to the drawbacks that posed blocking diodes. In this sense, string cables must be protected against reverse currents by means of gR fuses (standard IEC 60269) inserted in both poles2. These reverse currents may take place when a string experiences an isolation fault, for example, and they could seriously harm the string cables.
The floating configuration is the safest one (both poles isolated from ground). However all the metal works of the installation must be grounded. More specifically:
2
This protection is highly advised when three or more string are parallel connected 43
module frames, supporting structures, DC connection box, and metal enclosures that house both the main DC switch and the inverter must be connected to the earth bar.
Large area cable loops appear in PV generators, which in turn may cause voltage surges when a lightning strike hits close to the PVGCS. Consequently, voltage surge arresters between both positive and negative poles and earth is an advisable practice. These devices must be installed in the DC connection box. If the distance between this box and the inverter exceeds 10 m, they also must be installed in the inverter input, unless this device has its own protective devices. Voltage surge arresters must be available at the inverter output.
3.8.1. Sizing fuses
As commented above, gR fuses are housed inside the DC connection box and are series connected to each module string. Then, string cables are protected by fuses against reverse currents caused by faulty operation conditions. A common and widespread criterion to determine the fuse nominal current (Ifuse) is the following one:
I MOD , SC , STC
I fuse
2·I MOD , SC , STC
(3.15)
So that it can be assumed that: 1,5·I MOD , SC , STC
I fuse
(3.16)
The fuse nominal current is standardized in accordance with IEC 60269. Last, fuses must be suited for DC current and must withstand 1.1. times the open circuit voltage of the PV generator at STC (Nms·VMOD,OC,STC). 3.8.2. DC connection box and sizing the DC main switch
Some weatherproof (IP-54 code) DC connection boxes are marketed at present so that a limited number of strings can be easily connected in parallel with their corresponding fuses. Voltage surge arrestors can be connected inside these boxes (see figure 1.6, in section 1)
44
A DC main switch must be installed between the PV generator and the inverter according to IEC 60364-7-712. This DC main switch must withstand: a) the open circuit voltage of the PV generator at a cell temperature of -10ºC and b) 1.25 times the short circuit current of the PV generator at STC (1,25·Nmp·IMOD,SC,STC)
3.9 Some characteristic data concerning implemented PVPPs Two examples of real and successfully implemented PVPPs will be described hereafter to help get an idea of the range of voltage, current, power, electricity yield, etc. that some present state-of-the art systems deal with. Some of their features will also be superficially discussed. Leaving aside the different levels of irradiation that can be collected throughout Europe, it is worth saying once again that the existing huge variety of manufactures of PV devices makes it difficult to provide some “typical” figures for many of the above parameters.
3.9.1. A 101.2-kWp PVPP in Herreruela de Oropesa (Toledo province, Spain)
This PVPP is located in Herreruela de Oropesa (Toledo province, Spain) on an infertile plot of land, as depicted in figure 3.3. This site has a latitude 39º 53’N, longitude 5º 14’ and height 355 m. The local meteorological conditions of the site are characterised by an annual average daily horizontal irradiation of 4.6 kWh·m-2 together with an annual average daily temperature of 14ºC. The PVPP is deployed by means four ADESTM two-axis trackers -25.3 kWp-rated eachso that the complete PV field adds up to 101.2 kWp. The latter comprises 440 SuntechTM WXS230S monocrystalline modules 230 Wp-rated each. The DC-AC conversion is carried out by a XantrexTM GT100E 3-phase 100-kW central inverter. This PVPP was put into commission in early 2008 and has yielded an average of 2030 kWh·kWp-1·year-1 since then. Table 3.6 gathers some characteristic electrical parameters of the system.
45
Table 3.8. Main electrical characteristics at STC of the PV generator of the PVPP located in Herreruela de Oropesa described in this subsection Nominal
Series-
Parallel-
Open-circuit
Short-
Voltage at
Current at
power
connected
connected
voltage (V)
circuit
maximum
maximum power
(Wp)
modules
modules
current (A)
power point (V)
point (A)
101 200
11
40
611
226
475
212
Figure 3.3. PVPP in Herreruela de Oropesa (Toledo province, Spain). The photograph depicts on the left a two-axis tracker of a neighbouring PVPP
3.9.2. A 9.2-MWp PVPP in Jaén (Jaén province, Spain) The 9.2-MWp solar farm ‘Olive tree fields’ (Olivares) is located in a 16-hectare land plot in Jaén (Jaén province, Spain, latitude 38’N, longitude 3ºW, height 520 m). This land plot presents a nearly shadow-free skyline with negligible elevations over the horizon. Last, a high-voltage transformer centre (20 kV / 132 kV) neighbours on the site, so an easy access to grid connection is available.
46
The local meteorological conditions of the site are characterised by an annual average daily horizontal irradiation of 4·9 kWh·m-2 together with an annual average daily temperature of 16ºC. Nearly half the above area was a garbage dump, while the other half was a low profitable olive tree plantation, as depicted in figure 3.4. The owner of this area was not happy either with the degraded condition of part of this area or with the low profitability achieved by producing olive oil. Consequently, he felt enthusiastic when requested by the future owners of the PVPP to rent out his land plot to deploy the solar farm. The olive trees were to be pulled up and then the ground conditioned, together with that of the neighbouring garbage dump, so as to install the PV plant. High voltage transformer centre (20 kV / 132 kV)
Former garbage dump
Former low-profitable olive tree plantation
Figure 3.4. Aerial view of the land plot prior to the deployment of the solar farm ‘Olive tree fields’
Only 220-Wp monocrystalline silicon (m-Si) modules IsofotónTM IS-220 have been used in the solar farm ‘Olive tree fields’. Semi-fixed supporting structures allow changing the tilt angle ranging from 15º to 35º according to the season of the year. Its design comprises seventy two subplants rated 121·4 kWp each, together with four more ones, rated 105·6 kWp each, adding up to seventy six subplants. The 121·4-kWp and 105·6-kWp PV fields are connected to the grid by means of IngeConTM Sun 100-kVA and IngeConTM Sun 90-kVA 3-phase central inverters, respectively. This PVPP was put
47
into commission in August 2008 and has yielded an average slightly over 1600 kWh·kWp-1·year-1 since then. Figure 3.5. shows a partial view of the solar farm.
Figure 3.5. Partial view of the 9.2-MWp PVPP located in Jaén (solar farm ‘Olive tree fields’)
Table 3.9 gathers the layout of the PV field according to each type of subplant. Their electrical characteristics in STC are shown in table 3.10 Table 3.9. Electrical layout of both existing types of subplant PV fields Subplant 121·4-kWp PV field
Subplant 105·6-kWp PV field
Number of modules connected in parallel
46
40
Number of modules connected in series
12
12
Table 3.10. Electrical characteristics at STC of both existing types of subplant PV fields Parameter
Subplant 121.4-kWp PV field
Subplant 105.6-kWp PV field
Open-circuit voltage (V)
691
691
Short-circuit current (A)
234
204
Voltage at maximum power point (V)
553
553
Current at maximum power point (A)
219
191
121 400
105 600
Nominal power (Wp)
48
BRIEF SUMMARY OF SECTION 3 Required surface for 1-kWp PVPP if the PV modules are deployed on an horizontal terrain surface, tilt angle slightly lower than the latitude and with no self-shadowing between PV module arrays. Note: the figures gathered here are somewhat overestimated. More accurate calculations for each specific latitude may lead to smaller values of the required surface Technology
Surface (m2)
Monocrystalline silicon
20
Polycrystalline silicon
27
Copper Indium Diselenide (CIS)
32
Cadmium Telluride (CdTe)
40
Sizing the nominal power of a PV generator mainly depend on two criteria. It is up to the owner to select the most restrictive one: available area and cost of the installed PVGCS (if attractive financial incentives are available, a more in-depth economic analysis must be accomplished) Sizing the inverter implies selecting a figure for the ratio between the inverter nominal power and the PV generator nominal power. Some tables are provided for this parameter according to the local latitude, though there is a considerable degree of freedom when choosing a figure for it. A PV generator is compounded of parallel-connected strings of modules. The number of parallel-connected strings and the number of modules in a string is driven by the inverter maximum ratings, so as the latter device is not damaged during the normal operation of the PV generator Sizing the cabling implies taking into account two crucial criteria: the withstand voltage and the current carrying capacity. It is highly advised to limit the voltage drops through cables at STC in the PV generator so that losses are minimized. The same applies to cable losses in the AC part. Needless to say, both DC and AC parts must comply with national electrical regulation codes It is strongly suggested that the readers should review the sections of their national low voltage regulation codes that deal with protective measures in PV installations. Some of them are dealt with in this section Leaving aside the different levels of irradiation that can be collected in each country, the existing wide variety of manufactures of PV devices makes it 49
difficult to provide some “typical” figures for electrical characteristics of PVPPs. Despite this, two exemplary state-of the art PVPPs have been reviewed APPENDIX OF SECTION 3: TERMINOLOGY IMOD,SC = Short circuit current temperature coefficient of a PV module (mA·ºC-1) VMOD,OC = Open circuit voltage temperature coefficient of a PV module (mV·ºC-1) VAC (adim) = Voltage drop as a fraction of the nominal inverter output voltage Vstring (adim) = Voltage drop in a string as a fraction of the voltage of the PV generator at MPP at STC Vmain(adim) = Voltage drop in the DC main cable as a fraction of the voltage of the PV generator at MPP at STC INV,M (adim)
(m· cos
-1
= Maximum inverter efficiency
·mm-2) = Conductivity
(adim) = Inverter power factor
f (Hz) = Frequency of the grid Fs(adim) = Sizing factor G (Wm-2) = Incident irradiance GSTC (Wm-2) = Incident irradiance at STC (1000 Wm-2) Gda
(kWh·m-2 day-1) =Annual daily average daily irradiation on horizontal surface
Gda(
(kWh·m-2 día-1) = PV generator on-plane annual daily average irradiation
Ifuse (A) = Nominal fuse current IINV,AC (A) = Nominal inverter output current IINV,M,DC (A) = Inverter input maximum DC current IMOD,M,STC (A) = PV module current at MPP at STC IMOD,SC,STC (A) = PV module short-circuit current at STC LAC (m) = AC cable simple length Lmain (m) = DC main cable simple length Lstring (m) = String cable simple length N (adim) = Total number of modules of the PV generator Ncs (adim) = Series connected cells in a module Ncp (adim) = Parallel connected cells in a module 50
Nmp (adim) = Parallel connected number of strings Nms (adim) = Series connected PV modules in a string NOCT (ยบC) = Nominal operation cell temperature (ยบC) PGFV,M,STC (Wp) = Maximum power of a PV generator at STC or nominal power of a PV generator PINV,AC (W) = Inverter output nominal power PINV,DC (W) = Inverter input nominal power PMOD,M,STC (Wp) = Maximum power of a PV module at STC or nominal power of a PV module PR (adim.) = Performance ratio Sm,AC (mm2) = Minimal cable cross-section of an AC cable as a function of the allowed voltage drop Sm,main. (mm2) = Minimal cable cross-section of the DC main cable (Sm,string, in mm2) as a function of the allowed voltage drop Sm,rstring (mm2) = Minimal cable cross-section of a string cable as a function of the allowed voltage drop Ta (ยบC) = Ambient temperature Tc (ยบC) = Cell temperature VINV,AC (V) = Inverter output nominal voltage VINV,M (V) = Inverter input maximum voltage VINV,m,MPP (V) = Lowest voltage at which the inverter tracks the MPP of the PV generator VINV,M,MPP (V) = Highest voltage at which the inverter tracks the MPP of the PV generator VMOD,M,STC (V) = PV module voltage at MPP at STC VMOD,OC,STC (V) = PV module open circuit voltage at STC
51
4. Matching PVPP Typologies to Specific Terrains Given the wide variety of existing PVPP system typologies and the numerous peculiarities that characterize a marginal terrain type, providing some guidance to assess which PVPP system typologies may suit best a specific marginal terrain type could be found useful. Thus, a specific multivariable table might be completed using this guidance. The following text has been extracted from the Strategic Vision Document
Rocky, sandy or subsidency terrain consistency is not advisable for any PVPP typology. Obviously, terrains with risk presence â&#x20AC;&#x201C;geological, hydro or seismic- should be rejected. Regarding cliviometry, high land slope -above 5%- hinders the deployment of PVPP that use tracking techniques, but under certain boundaries, high land slope is a neutral item in the case of static and semi static modules.
Terrains with indented surfaces must be avoided: this is a powerful barrier for the necessary civil works to deploy a PVPP. Additionally, subsequent operation and maintenance turns into a difficult task. Wet or waterlogged grounds do not pose an obstacle for PVPPs. Regular surfaces are obviously the preferred ones.
As it may be easily understood, sites with high irradiation profiles will lead to a substantial solar electricity production. Terrains with an annual average horizontal irradiation below 900 kWh/m2 should be disregarded. If concentrator photovoltaic (CPV) is to be installed, at least some annual average normal direct irradiation of 1800 kWh/m2 is required.
Severe shadowing should certainly be avoided, but energy losses caused by tiny shadowing at the down and sunset in winter are negligible: in this case, the terrain would be acceptable.
Solar cell performance benefits from cooling through forced convection by means of wind, so in the case of static and semi static PVPP, moderate windy areas (maximum wind speed of some 30-40 km/h) favour solar electricity production. However, highly windy zones (frequent wind peaks above 60 km/h) are not suitable for PVPP that use tracking techniques. In such zones, at best, the tracking systems will frequently change 52
their operation to the stow position and the energy yield will be negatively affected. At worst, some of these systems can be seriously damaged.
The negative effect of dust was underestimated in PVPPs in the past. Recent studies prove that energy losses up to some 15-20% might take place due to dust and dirtiness. Consequently, dusty marginal terrains should be avoided. Besides, special attention must be paid to the neighbouring areas of the marginal terrain where the PVPP is to be deployed. For instance, arable surrounding areas in dry climates are not advisable.
If the marginal terrain climate is not too cloudy â&#x20AC;&#x201C;this would affect the annual average horizontal irradiation- rain may help to keep the PV modules clean. Consequently, moderate monthly average rainfall values (5-7 cm) are beneficial for any PVPP typology.
Easy access to grid connection is highly advisable.
Easy road access to the marginal area is advisable for two reasons. First, transportation of all the necessary material to deploy any PVPP will be much easier and less costly. The same applies to the operation and maintenance tasks to be carried out through the useful life of the PVPP.
Communication coverage â&#x20AC;&#x201C;Internet access availability, GPRS, etc- is increasingly becoming important. Electric companies â&#x20AC;&#x201C;which in the end, buy the generated electricity- usually force owners of large and relatively isolated PVPP in marginal terrains to provide remote access to their energy meters
BRIEF SUMMARY OF SECTION 4
There is wide variety of possible PVPP system typologies whilst the peculiarities that characterize a marginal terrain type are numerous. This turns matching the former with the latter into a cumbersome task when approached using multivariable tables.
53
This section is aimed at providing some guidance to assess which PVPP system typologies may suit best a specific marginal terrain type.
54
5. Economic assessment on PV Grid-Connected systems On-ground photovoltaic grid窶田onnected systems (PVGCS) are becoming the most popular application of the photovoltaic technology in developed countries. This is mainly due to the governmental support programmes and policies launched by these countries and a continuous decrease trend in photovoltaic (PV) cost. These policies are implemented with financial incentives broadly fall into investment-focused (initial investment subsidy, soft loans, income tax incentives, etc.) and generation-based (feedin tariffs (FIT), net metering, etc.) ones.
Firstly, in this section some available supporting measures for PVGCS and indicative installed system prices of them in each project partner country are shortly reviewed. Besides, some profitability indices of investment project applied of PVGCS have been reviewed. More specifically, the internal rate of return (IRR), that provides some straightforward meaningful information for the investor of these PV systems. Estimation the IRR must be solved through non-analytical methods. This is why some easy-to-use tables addressed to estimate the value of IRR are proposed in this section.
Finally, in this section it has been carried out an economic analysis of the PVGCS, through the profitability index IRR. This analysis provides some figures for the IRR that may enlighten a prospective PVGCS owner decision. In this analysis, for the sake of simplicity, only initial investment subsidy, soft loans for the whole remaining initial cost after the initial investment subsidy to be repaid in equal annual installments, feedin tariffs and the annual increase rate of the PV electricity price are considered in a first approach for three specific cases (cases A, B and C, from now on) of possible investments on PVGCS. In these cases, the effect of taxation has not been considered. However, as ignoring completely the tax influence may lead to unrealistic results, a brief analysis concerning the impact of taxation in these three cases (A,B and C) is carried out. Last, some figures of IRR are shown for some cases of PVGCS with the same initial investment and different financial incentives (soft loans, initial investment subsidy and feed-in tariffs).
55
5.1.
Representative figures of the cost of PVGCS in some countries
Table 5.1 provides some indicative installed system prices in some selected countries in 2008. However, it has to be kept in mind that on-ground PVGCS prices -such as those the PVs in Bloom project deals with- have dramatically been reduced by some 35% during the years 2007-2009. Some 3-6 Eur/Wp might be assumed as a more realistic range for the cost of PVPPs in the project partner countries. Table 5.1. Indicative installed PVGCS prices per Wp in various countries in 2008 (source: IEA, Trends in photovoltaic applications survey report of selected IEA countries between 1992 and 2008, Report IEAPVPS T1-18:2009)
Country
Grid-connected (EUR or USD per W) <10 kW >10 kW EUR
USD
EUR
USD
AUS
5,1 – 7,3
7,5 – 10,8
3,9 – 5,6
5,8 – 8,3
AUT
4,8 – 5,8
7,1 – 8,5
4,8 – 5,5
7,1 – 8,1
CAN
3,8 – 4,4
5,6 – 6,5
3,8 – 5,1
5,6 – 7,5
CHE
6,0 – 6,4
8,8 – 9,4
5,2 – 5,4
7,6 – 7,9
DEU
3,9 – 4,5
5,7 – 6,6
3,7
5,4
DNK
4,7 – 11,4
6,9 – 16,7
6,7 – 13,3
9,8 – 19,6
ESP
7 – 7,5
10,3 – 11,0
5,7 – 6
8,4 – 8,8
FRA
7 – 8,3
10,3 – 12,2
5,1 – 6
7,5 – 8,8
GBR
4,2 – 12,6
6,2 – 18,5
5,0 – 9,9
7,3 – 14,5
ISR
4,1 – 5,1
6,0 – 7,5
ITA
5,5 – 6,5
8,1 – 9,6
4,2 – 5,5
6,2 – 8,1
JPN
4,7
6,9
3,5
5,2
KOR
4,1 – 5,7
6,1 – 8,4
5,7
8,4
MEX
8,4
12,4
5,8
8,5
MYS
4,9
7,2
4,9
7,2
NOR
10,8 – 14,4
15,9 – 21,2
PRT
5–6
7,4 – 8,8
4,2
6,2
SWE
9,9
14,5
6,9
10,2
TUR
4,5
6,6
4
5,9
USA
4,8 – 6,1
7–9
4,4
6,5
Notes: Excludes VAT and sales taxes. More expensive grid-connected system prices are often associated with roof integrated slates or tiles or one-off building integrated designs or single projects, and figures can also relate to a single project.
5.2 Existing supporting measures for PVPPs in each partner country Some financial incentives for PVPPs, such as granting a subsidy per kWp capacity installed or a payment per kWh produced and sold are available in developed countries. In other words, these financial incentives broadly fall into investment-focused (buydown subsidy, soft loans, income tax incentives, etc.) and generation-based (enhanced 56
feed-in tariffs (FIT), net metering, etc.) ones. More specifically, some PV financial incentives are detailed below:
Feed-in tariff: an explicit monetary reward is provided for producing PV electricity; paid (usually by the electricity utility) at a rate per kWh somewhat higher than the retail electricity rates being paid by the customer. Capital subsidies: direct financial subsidies aimed at tackling the up-front cost barrier, either for specific equipment or total installed PV system cost. PV-specific green electricity schemes: allows customers to purchase green electricity based on PV electricity from the electricity utility, usually at a premium price. Income tax credits: allows some or all expenses associated with PV installation to be deducted from taxable income streams. Commercial bank activities (Low-interest loans): includes activities such as preferential home mortgage terms for houses including PV systems and preferential green loans for the installation of PV systems. Net metering: in effect the system owner receives retail value for any excess electricity fed into the grid, as recorded by a bi-directional electricity meter and netted over the billing period. Net billing: the electricity taken from the grid and the electricity fed into the grid are tracked separately, and the electricity fed into the grid is valued at a given price. In general, the last two financial incentives do not apply to PVPPs as all the PVgenerated electricity is fed and sold to the grid. More concretely, some available supporting measures for PVGCS in each project partner country are shortly reviewed below: Austria The Ökostromverordnung 2009 (eco electricity degree) set the following new tariffs for 2009 (only for PV systems covered by the Ökostromgesetz (Eco Electricty Law). ■ System size < 5 kW: 0.4598 €/kWh ■ System size 5 to 10 kW: 0.3998 €/kWh ■ System size > 10 kW: 0.2998 €/kWh
57
For installations supported under the feed-in tariff scheme, 100 % of the specific tariff is paid for the first 10 years. Afterwards, the tariff is cut to 75 % in year 11 and finally 50 % in year 12. After this period, only the gross sale price for electricity is paid. Some of the Federal States have additional investment support schemes.
Greece In January 2009 a new feed-in-tariff regime was introduced in Greece. The tariffs will remain unchanged until August 2010 and are guaranteed for 20 years. However, if a grid connection agreement is signed before that date, the unchanged FIT will be applied if the system is finalized within the next 18 months.
Already filed applications for permits (> 3 GW) had to be served until the end of 2009. The regime for new applications is not yet known.
Feed-in tariff [€/kWh]: Start of operation
Mainland Grid
Autonomous island grids
> 100 kWp ≤ 100 kWp
> 100 kWp
≤ 100 kWp
February 2009:
0.40
0.45
0.45
0.50
August 2009:
0.40
0.45
0.45
0.50
February 2010:
0.40
0.45
0.45
0.50
0.392
0.441
0.441
0.49
August 2010:
From then on the degression of the tariffs for new systems will be 5% each half year. A 40% grant will still be available on top of the new FITs for most of the systems (minimum investment eligible for grant is € 100,000).
New since 4 June 2009: rooftop PV systems up to 10 kWp (both for residential users and small companies) receive 0.55 €/kWh. Annual degression of 5% is foreseen for newcomers as of 2012. This does not apply to PVPPs, obviously.
Regarding changes of PV’s legislation, the pricing of electricity produced by photovoltaic power is based on the data shown in Table 5.2
58
Table 5.2. Feed-in tariffs (€/MWh) in Greece according to the date of commission of the PVGCS YEAR
MONTH
GRID CONNECTED (> 100 kW) > 100kW
GRID CONNECTED (<= 100 kW) <=100kW
NOT GRID CONNECTED
2010
February
400,00
450,00
450,00
2010
August
392,04
441,05
441,05
2011
February
372,83
419,43
419,43
2011
August
351,01
394,88
394,88
2012
February
333,81
375,53
375,53
2012
August
314,27
353,56
353,56
2013
February
298,87
336,23
336,23
2013
August
281,38
316,55
316,55
2014
February
268,94
302,56
302,56
2014
August
260,97
293,59
293,59
X 1,3
X 1,4
X 1,4
2015 => Previous year middle price of system
Italy Feed-in tariffs are guaranteed by the GSE (Gestore Servizi Elettrici – National Electrical Services Management Body) for 20 years. According to article 6, comma 2, of the Decree 19 february 2007, tariffs have been reduced by 2% from 2009 to 2010. 2009 Tariffs: Nominal Power Ground installation 1 – 3 kWp 0.392 €/kWh 3 – 20 kWp 0.372 €/kWh > 20 kWp 0.353 €/kWh 2010 Tariffs: Nominal Power Ground installation 1 – 3 kWp 0.384 €/kWh 3 – 20 kWp 0.365 €/kWh > 20 kWp 0.346 €/kWh
Partially integrated 0.431 €/kWh 0.412 €/kWh 0.392 €/kWh
Partially integrated 0.422 €/kWh 0.403 €/kWh 0.384 €/kWh
Integrated in buildings 0.480 €/kWh 0.451 €/kWh 0.431 €/kWh
Integrated in buildings 0,470 €/kWh 0,442 €/kWh 0,422 €/kWh
Focusing on ground installations, the target of PVs in BLOOM, for 2010 a bonus of 5% of the tariff value exists for special cases (the bonuses cannot add up to each other):
59
in the case of a ground system where the 70% of the electricity is used up directly by the producer or societies controlled by the producer for plants that are owned by a public school or public health structure for plants which are owned by local administrations with less than 5.000 inhabitants Reduction of VAT from 20% to 10% The incentive rates are combined with certain public benefits and contributions (capital contributions up to 30% of investment cost) and the soft loans of 0.50% under the Kyoto Fund (Article 1, paragraph 1111, 2007 Financial Law). Enjoying the reduction of VAT cannot combine with tax deductions. For 2011 the Government has announced the possibility of cutting back the tariffs by another 20% maximum. Such percentage is currently under discussion by the Italian Ministry for Economic Development and stakeholders from the PV national industry, and it seems that the parties are reaching a compromise around a solution that could foresee a gradual reduction of the tariff by 6% every 4 months, following the German model.
Therefore, the installations connected to the grid by April 2011 could have tariff reductions among 6.5 to 8.1%; those between April and August from 10% and 12.8%, while those between August and December 2011 among 15% and 17.6%.
Also under discussion, for ground PV plants, is the bonus of 5% for installations in marginal areas (the proposal of Decree mentions exhausted quarries, areas of relevance to landfills, etc.).
Another 6 or 8% should be cut back every year starting from 2012. Innovative plants could however benefit from a lower cut back (around 2% every year).
That of ‘innovative plants’ (the category ‘integrated photovoltaic systems with innovative features’) is a novelty that has been recently introduced and will benefit from incentive rates (divided in three intervals of power) higher than the other categories. The 60
tariffs for “innovative plants” could be cut by 2% per year (instead of 6%) in 2012 and 2013. By 1 January 2011, the GSE will develop a guide on the features that these innovative systems must have.
Also an increase in the total power for which incentives can be provided is under discussion: it is foreseen that the ceiling will be raised from 2,000 MW in 2015 and 3,000 MW in 2016, with other 150 MW added for additional installations of plants with concentration technology. The objective of national power to be installed by 2020 is set at 8,000 MW.
Another change foreseen is the division of power plants in 5 classes: between 1 and 3 kW, between 3 to 20 kW, between 20 and 200 kW, between 200 to 1000 kW and over 1000 kW.
Moreover, welcoming the suggestion of producers to simplify the types of installation (removing the category of partially integrated plants) the draft ministerial decree foresees only two types: ‘photovoltaic systems integrated in buildings’ and ‘other photovoltaic installations’
Poland There is no Feed in Tariff in Poland at this moment. Legislation considering Legislation considering Energetic Law (Regulation of Minister for the Economy Coll. U. Nr 122, poz. 1336, dated 15 December 2000; http://www.ure.gov.pl/portal.php?serwis= pl&dzial= 195&id=882& search=25421) makes an obligation to the government to buy any amount of green energy without any quantity restrictions. For selling such energy, the producer is granted ‘a green certificate’ which is sold in the stock exchange. The average price of the green certificate equals 0.26 PLN/kWh (0.07 €cent/kWh1).
As a result of actions taken under the ‘PVs in Bloom’ project in Lublin’s region some subsidies were introduced for those who want to invest on renewable energies.
Amount of subsidies for local governments is 3 million PLN for each investment. 1
Exchange rate: 1 € = 3.88 PLN 61
Spain Financial incentives applied to PVGCS at present (royal decree 1578/2008) are briefly described below: Installation types: 1.1. Systems in or on top of buildings with at most 20kW power 1.2. Systems in or on top of buildings with more than 20kW of power
2. Systems on undeveloped areas
Systems installed on the ground with more than 10MW and rooftop systems with more than 2MW of power will not receive feed-in tariffs.
Cap for every type of installation (per year but quarterly sufficed): 1.1.
26.7MW
1.2.
240.3MW
2.
133MW, with an additional 100MW of installed power in 2009 and 60MW in 2010.
Tariffs (paid over 25 years): 1.1. 34 euro cents/kWh 1.2. 32 euro cents/kWh 2. 32 euro cents/kWh
Changes to the cap and tariff rates: If at least 75% of a particular quarterly cap is exhausted, the tariff for the corresponding installation type is decreased by at most 2.5%, while at the same time the amount of available installable power is increased by the same amount.
If less than 50% of a cap is exhausted, the corresponding tariff increases, while the cap decreases by an equal amount (without consideration of addition power). If the cap is exhausted by between 50 and 75%, the tariffs and the amount of installable power
62
remains the same. Adjustments for installable power will be made on an annual basis and the tariffs will be adjusted quarterly. Slovakia Feed-in tariff is set by Regulator each year. The new feed-in tariff for 2009 is 13.2 SKK/kWh (0.434 â&#x201A;Ź/kWh2) guaranteed for 12 years. In addition, PV, like all other RES, qualifies for investment subsidies under the framework of the EU Structural funds.
2
Exchange rate: 1 â&#x201A;Ź = 30.396 SKK
5.3 Review of the most meaningful and understandable profitability indices: the internal rate of return (IRR) 5.3.1. Introduction From a strictly economic viewpoint, the purchase of a PVPP means an expenditure of capital resources at a given time with the expectation of benefits in the form of solar electricity yield to be paid/saved to/by the user over the useful life of the system.
As commented in other sections of this document, many financial mechanisms are available in developed countries intended to promote PVPPs. However, for the sake of simplicity, only initial investment subsidy, soft loans for the whole remaining initial cost after the initial investment subsidy to be repaid in equal annual installments, feedin tariffs and the annual increase rate of the PV electricity price are considered in a first approach for three specific cases (cases A, B and C, from now on) of possible investments on PVPPs, leaving aside the effect of taxation. However, as ignoring completely the tax influence may lead to unrealistic results, a brief analysis concerning the impact of taxation in these three cases puts an end to this study.
5.3.2. A review of four profitability indices The simple payback time (SPBT) of an investment project is the required number of years for the inflows to equal the outflows of this project. Despite being easily understandable, this profitability index does not take into account the moment over the life of the project when these inflows and outflows take place, so it is a rather unrealistic 63
index (e.g.: a 3,000-Euro income in 2009 has more worth than a 3,000-Euro income in 2019). In this sense, it is preferred to deal with the discounted payback time (DPBT), stated as the required number of years for the present worth of the inflows to equal the present worth of the outflows (the present worth implies using an annual discount rate and taking into account the annual inflation rate). Evidently, profitability means that the discounted payback time should not exceed the serviceable life of the system. Although it is also easily understandable and straightforward, this parameter does not consider the cash flows that are produced after the DPBT. Hence, it may hide sound financial opportunities for those deciding to invest on a PV system3.
The net present value (NPV, in â&#x201A;Ź) of an investment project is the sum of present values of all cash inflows (PW[CIF(N)], in â&#x201A;Ź, where N is the useful life of the PV system, in years) and outflows related to the investment4 . Therefore, the parameter NPV equals the present worth of the cash inflows from the system minus the life-cycle cost from the user standpoint (LCCUSP). Thus:
NPV
PW CIF( N )
(5.1)
LCC L USP
Obviously, a PVGCS should be viewed favourably if NPV > 0. However, this parameter fails to choose among two projects with the same NPV but different initial costs and duration.
The internal rate of return (IRR) of an investment project equals the actual interest rate at which the project initial investment should be lent during its useful life to achieve the same profitability5. Also, the internal rate of return (IRR) of an investment project is the value of the interest rate that leads to NPV = 0. This is to say:
NPV
PW P CIF( N )
LCCUSP
0
(5.2)
3
Perez R, Burtis L, Hoff T, Swanson S, Herig C. Quantifying residential PV economics in the USpayback vs cash flow determination of fair energy value. Solar Energy 2004;77:363-366. 4
Lasnier F, Ang T. Photovoltaic engineering handbook. Great Yarmouth: Adam Hilger; 1990. p. 371399. 5 Chabot B. From cost to prices: economic analysis of photovoltaic energy and services. Progress in Photovoltaics: Research and Applications 1998;6:55-68. 64
From an economic point of view, the PV system should be accepted if the IRR exceeds a profitability threshold fixed by the future owner. In this sense, this parameter is very important for the investor since it provides a meaningful estimation of the return of their investment. The actual internal rate of return (IRRa) is derived from IRR by IRRa= (IRRg)/(1+g), where g is the annual inflation rate.
The value of the internal rate of return (IRR) for a given PV system, may be calculated through both parameters LCCUSP and PW[CIF(N)]. When the life-cycle cost of the system from the user standpoint and the present worth of cash inflows from the system are equal, at the same value of d, the solution is found (IRR = d).
5.4 Easy-to-use tables to estimate the IRR Unfortunately, equation (5.2) must be solved through non-analytical methods. This is why some easy-to-use tables addressed to estimate the value of IRR are proposed in this subsection (see Annex enclosed to this section). In fact, the internal rate of return (IRR) equals the value of discount rate d that verifies equation (5.2). Values of IRR > 0 will be feasible solutions from an economic point, provided that a certain profitability hurdle set by the investor is reached.
Tables are used following the steps detailed below:
1. Choose the tables for the calculation of LCCUSP, according to the type of loan â&#x20AC;&#x201C;if any, this is determined by the loan interest (il) and the loan duration (Nl)- addressed to partly finance the initial investment. For the specific values of the initial investment (PVIN) and the initial buy-down or subsidy (PVIS), find a group of values LCCUSP for several values of discount rate d. Choose a value of d so that from this value of d, it follows a value of LCCUSP. 2. Choose the tables for the calculation of PW[CIF(N)], according to the annual increase rate of energy price (
pu).
For the specific values of EPV and pu, find a group of values
PW[CIF(N)] for several values of discount rate d. Also choose the same value of d that was chosen in step 1. Select the corresponding value of PW[CIF(N)]. 3. Substract PW[CIF(N)] minus LCCUSP 4. Three cases may appear depending on the result of step 3:
65
4.1. If the result of step 3 is equal to zero, then IRR = d. 4.2. If the result of step 3 is negative, the discount rate d that is sought has a lower value than that chosen in step 1. Therefore, return to step 1 and choose the nearest lower value of d in this column. Iterations are continued until the difference obtained in step 3 turns into positive. Then, the solution is found: the value of IRR lies within the values of d of the last two iterations. The difference obtained in step 3 might not turn into positive at the lowest value of d = 0路01 considered in the tables. This would mean that the PVGCS project should be rejected since IRR < 0. 4.3. If the result of step 3 is positive, the discount rate d that is sought has a higher value than that chosen in step 1. Therefore, return to step 1 and choose the nearest higher value of d in this column. Iterations are continued until the difference obtained in step 3 turns into negative. Then, the solution is found: the value of IRR lies within the values of d of the last two iterations. The difference obtained in step 3 might not turn into negative at the highest value of d considered in the tables. In this case, the tables only provide a lower bound for IRR which is equal to the last tried value of d.
5.4.1 Some examples Giving a tutorial on how to calculate the IRR lies out of the scope of this document, but the method to do this may be found in literature6,7. Nevertheless, providing some figures for this profitability index in three specific cases may enlighten a prospective PVPP owner decision. In this sense, some factors are involved in the calculation of the IRR and -as it can easily be anticipated- they are mainly related to costs, incentives, electricity yields and the annual increase rate of the PV electricity price. Finally, in Table 5.3 are presented values of IRR for some cases of PVGCS with the same initial investment and different financial incentives (soft loans, initial investment subsidy and feed-in tariffs). The figures that configure each one of the three cases mentioned earlier which refer to costs, incentives and electricity yields are commonly normalised-per-
6
Talavera DL, Nofuentes G, Aguilera J, Fuentes M. Tables for the estimation of the internal rate of
return of photovoltaic grid-connected systems. Renewable & Sustainable Energy Reviews 2007; 11:447466. 7
Nofuentes G, Aguilera J. and Mu帽oz FJ. Tools for the Profitability Analysis of Grid-Connected
Photovoltaics. Progress in Photovoltaics: Research and Applications, 2002;10:555-570. 66
kWp. Some values that characterize each one of the cases are given below, together with the corresponding figure for the IRR:
Case A: The normalised annual PV electricity yield ([EPV]kWp) is assumed equal to 1400 kWh kWp-1 year-1 . The normalised initial investment in the PVGCS ([PVIN]kWp) is assumed equal to 6000 € kWp-1 . The corresponding price per kWh for PV-generated electricity sold to the grid (pu), is fixed by law in different countries. It is assumed equal to 0.30 € kWh-1 The annual increase rate of the PV electricity price (
pu)
is assumed equal to 2%.
The normalised initial investment subsidy ([PVIS]kWp) is assumed equal to 17% of [PVIN]kWp therefore [PVIS]kWp is assumed equal to 1000 €·kWp-1. It is worth mentioning some countries provide capital subsidies ranging from 10 to 50 percent 8,9. Consequently, the remaining sum [PVIN]kWp–[PVIS]kWp is to be paid by the owner. This amount is assumed to be borrowed at an annual loan interest il= 5% while the loan term Nl is assumed equal to 10 years. Use of the tables provided in the annex for this example: 1.- From table 2, column 4 (6000 € kWp-1 ) and rows where [PVIS]kWp = 1000 €·kWp-1 are considered. Let us choose a value of d = 0·09, so that [LCCUSP]kWp = 4745 €·kWp-1 . 2.- From table 5, column 5 and rows where pu = 0·3 €·kWh-1 are considered. It follows from the row corresponding to the same value of d = 0·09 that PW[CIF(N)]]kWp= 4956 €·kWp-1. 3.- Let us subtract PW CIF( N ) 4.-Since PW CIF( N )
8
LCC L USP
LCC USP
-1 211 2 €·kWp .
> 0, parameter IRR has a higher value. Therefore, let us
Martinot E. Renewable: Global status report. REN21 Renewable Energy Policy Network by The
Worldwatch Institute, 2005. Available at:http://www.martinot.info/RE2005_Global_Status_Report.pdf(accessed November 2006). 9
Martinot E. Renewable: Global status report, Update. REN21 Renewable Energy Policy Network, 2006. Available at:http://www.ren21.net/globalstatusreport/download/RE_GSR_2006_Update.pdf (accessed September 2007). 67
return to step 1 and try with d = 0·11. 1.- From table 2, column 4 and rows where [PVIS]kWp = 1000 €·kWp-1 are considered again. Let us choose a value of d = 0·11, so that [LCCUSP]kWp = 4319 €·kWp-1 . 2.- From table 5, column 5 and rows where pu = 0·3 €·kWh-1 are considered again. It follows from the row corresponding to the same value of d = 0·11 that PW[CIF(N)]]kWp= 4185 €·kWp-1. 3.- Let us subtract
PW CIF( N )
LCC USP
-1 1 €·kWp 134
.
4.- Since the difference obtained in step 3 turns into negative, the solution is found: the value of IRR lies within 9-11%.
IRR in case A lies within a very attractive 9 - 11%. Let us choose a value of IRR=9% (most unfavorable case).
Case B: [EPV]kWp is assumed equal to 1200 kWh kWp-1 year-1. [PVIN]kWp is assumed equal to 5000 € kWp-1. The corresponding price per kWh for PV-generated electricity paid/saved to/by the owner (pu) is assumed equal to 0.20 € kWh-1. pu
is assumed equal to 2% .
[PVIS]kWp is assumed equal to 1500 € kWp-1. Consequently, the remaining sum [PVIN]kWp–[PVIS]kWp is to be paid by the owner. This amount is assumed to be borrowed at an annual loan interest il= 5%, while the loan term Nl is assumed equal to 20 years. Tables 3 and 5 provided in the annex should be used for the calculation of LCCUSP and PW[CIF(N)]. If the procedure described for case A is followed, IRR in case B equals an attractive 5 - 7%. Let us choose a value of IRR=5% (most unfavorable case).
Case C: [EPV]kWp is considered equal to 1000 kWh kWp-1 year-1 . [PVIN]kWp is assumed equal to 4000 € kWp-1 . The corresponding price per kWh for PV-generated electricity paid/saved to/by the owner (pu) is assumed equal to 0.20 € kWh-1. 68
pu
is assumed equal to 1%.
[PVIS]kWp is assumed equal to 25% of [PVIN]kWp, therefore [PVIS]kWp is assumed equal to 1000 € kWp-1 [7,9]. Consequently, the remaining sum [PVIN]kWp–[PVIS]kWp is to be paid by the owner. This amount is assumed to be borrowed at annual interest rate il= 5% over a term equal to Nl= 20 years. Tables 3 and 4 provided in the annex should be used for the calculation of LCCUSP and PW[CIF(N)]. IRR in case C equals a fairly good 3 - 5%. Let us choose a value of IRR=3% (most unfavorable case). The analysis of some other cases may help achieve a better understanding. Table 5.3 shows values the IRR for PV Grid-Connected Systems with same initial investment and different support measures. Table 5.3. IRR for PVGCS with the same initial investment and different financial incentives.
[EPV]kWp
[PVIN]kWp
pu
-1 -1 (kWh kWp-1 year-1) (€ kWp ) (€ kWh )
pu
(%)
[PVIS] kWp
Soft loans
IRR
(€ kWp-1)
Nl (years) il (%)
(%)
No available
5-7
Nl=10 il=5
7-9
Nl=10 il=5
3-5
1000 0.2 1200 4000
1400
2
Non available
0.3
Non available Non available
5-7
0.2
Non available Non available
5-7
5.5. Short review of the taxation impact As commented previously, the above cases have ignored the tax influence. However, some basic issues concerning this influence will shortly be dealt with below to help achieve an approach that tries not to conceal the effect of taxation. Anyway, it should be kept in mind that the general assumptions that follow are reasonable, but taxation differs considerably from country to country. However, tax exemptions have been left aside, due to the wide differences concerning this issue also from country to country.
69
In general, most existing tax laws, consider that every owner of a PVPP must pay an amount per annum, mostly attributable to the gains of the previous year. This amount depends on the law defined tax coefficient, investment revenue, the annual operation and maintenance cost, the debt repayment method, the asset amortization, etc.
The diversity of taxation systems according to each country makes it complex to encompass this issue in our analysis. Anyway, several tax coefficient values -ranging from 0% up to 40%- have been considered.10 In this subsection an analysis of the IRR has been made by means of taking into account a tax coefficient, for the three considered cases. In order to estimate the taxes, this coefficient has been applied to the cash inflow from the PVPP, once the asset amortization, the interest payments of the loan, and the operation and maintenance cost of the PVGCS are deducted. The asset amortization has been considered lineal over the life cycle of the PVPP (25 years) and it has been excluded from taxation. The results of the analysis in the base cases for scenarios A, B and C are shown in figure 5.4. In this figure, the internal rate of return is depicted vs the percentage tax coefficient. The IRR experiences a smooth and almost linear decrease as the taxation coefficient increases. More specifically, when the latter rises to 40%, the former is only decreased by 2.7% for case A, 1.4% for case B and 0.8% for case C.
10
Kaldellis JK, Vlachou DS, Korbakis G. Techno-economic evaluation of small hydro power plants in Greece: a complete sensitivity analysis. Energy Policy 2005;33:1969-1985.
70
Figure 5.4. IRR (%) as a function of the percentage tax coefficient values for cases A (uppermost line), B (medium line) and C (lowermost line)
71
BRIEF SUMMARY OF SECTION 5 A continuous decrease trend in PV costs together with a wide variety of supporting measures have turned photovoltaic grid-connected systems (PVGCS) into a profitable investment when some economic conditions are met. On-ground PVGCS prices -such as those the PVs in Bloom project deals with- have dramatically been reduced by some 35% during the years 2007-2009. Some 3-6 Eur/Wp might be assumed as a realistic range for the cost of PVPPs in the project partner countries. In Europe, different forms of financing for PVGCS have been defined and put into effect in the last years. The most popular one in Europe are the feed-in tariff, capital subsides and soft loans. The internal rate of return (IRR) provides some straightforward meaningful information for the investor of these PV systems. This section presents some easy-to-use tables addressed to estimate the IRR avoiding cumbersome calculations. This analysis provides some figures for the IRR that may enlighten a prospective onground PVGCS owner decision. Some figures are shown below, according to some different scenarios: [EPV]kWp
[PVIN]kWp
pu
-1 -1 (kWh kWp-1 year-1) (€ kWp ) (€ kWh )
1000
[PVIS] kWp
Soft loans
IRR
(%)
(€ kWp-1)
Nl (years) il (%)
(%)
1
1000
Nl=20 il=5
3-5
Non available
5-7
Nl=10 il=5
7-9
Nl=10 il=5
3-5
pu
0.2
1000
4000 1200
Non available 0.3 5000
1400 1400
0.2 0.2
6000
0.3
2
Non available Non available 1500
Nl=20 il=5
Non available Non available 1000
Nl=10 il=5
5-7 5-7 5-7 9-11
The analysis regarding taxation shows that IRR experiences a smooth and almost linear decrease as the taxation coefficient increases from 0 to 40%.
72
APPENDIX I OF SECTION 5. TABLES ADDRESSED TO ESTIMATE THE IRR Table 1. Life-cycle cost of the system per kWp from the user standpoint [LCCUSP]kWp, as a function of the initial investment in the PVGCS per kWp ([PVIN]kWp), the nominal discount rate d and the initial investment subsidy per kWp ([PVIS]kWp). No loans available.
[PVIN]kWp (€/kWp)
[PVIS]kWp (€/kWp) d 0 0,01
1000
1500
2000
2500
0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15
3000
4000
5000
6000
7000
3661 3522 3423 3350 3295 3253 3220 3194 3173 3156 3142 3130 3120 3111 1440 2522 2423 2350 2295 2253 2220 2194 2173 2156 2142 2130 2120 2111 2161 2022 1923 1850 1795 1753 1720 1694 1673 1656 1642 1630 1620 1611 1661 1522 1423 1350 1295 1253 1220 1194 1173 1156 1142 1130 1120 1111 1161 1022 923 850 795 753 720 694
4881 4697 4564 4466 4393 4337 4293 4259 4231 4208 4189 4173 4159 4148 2661 3697 3564 3466 3393 3337 3293 3259 3231 3208 3189 3173 3159 3148 3381 3197 3064 2966 2893 2837 2793 2759 2731 2708 2689 2673 2659 2648 2881 2697 2564 2466 2393 2337 2293 2259 2231 2208 2189 2173 2159 2148 2381 2197 2064 1966 1893 1837 1793 1759
6101 5871 5705 5583 5491 5421 5366 5323 5288 5260 5236 5216 5199 5185 3881 4871 4705 4583 4491 4421 4366 4323 4288 4260 4236 4216 4199 4185 4601 4371 4205 4083 3991 3921 3866 3823 3788 3760 3736 3716 3699 3685 4101 3871 3705 3583 3491 3421 3366 3323 3288 3260 3236 3216 3199 3185 3601 3371 3205 3083 2991 2921 2866 2823
7321 7045 6846 6699 6589 6505 6440 6388 6346 6312 6283 6259 6239 6222 5101 6045 5846 5699 5589 5505 5440 5388 5346 5312 5283 5259 5239 5222 5821 5545 5346 5199 5089 5005 4940 4888 4846 4812 4783 4759 4739 4722 5321 5045 4846 4699 4589 4505 4440 4388 4346 4312 4283 4259 4239 4222 4821 4545 4346 4199 4089 4005 3940 3888
8542 8219 7987 7816 7688 7590 7513 7452 7404 7364 7330 7303 7279 7259 6321 7219 6987 6816 6688 6590 6513 6452 6404 6364 6330 6303 6279 6259 7042 6719 6487 6316 6188 6090 6013 5952 5904 5864 5830 5803 5779 5759 6542 6219 5987 5816 5688 5590 5513 5452 5404 5364 5330 5303 5279 5259 6042 5719 5487 5316 5188 5090 5013 4952
8000 9762 9393 9128 8932 8786 8674 8586 8517 8461 8416 8378 8346 8319 8296 7542 8393 8128 7932 7786 8517 7586 7517 7461 7416 7378 7346 7319 7296 8262 7893 7628 7432 7286 7174 7086 7017 6961 6916 6878 6846 6819 6796 7762 7393 7128 6932 6786 6674 6586 6517 6461 6416 6378 6346 6319 10034 7262 6893 6628 6432 6286 6174 6086 6017
(Continued overleaf) 73
[PVIS]kWp (€/kWp)
[PVIN]kWp(€/kWp) d
2500 0,17
3000
3500
4000
4500
0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27 0,01 0,03 0,05 0,07 0,09 0,11 0,13 0,15 0,17 0,19 0,21 0,23 0,25 0,27
3000
4000
5000
6000
7000
8000
673 656 642 630 620 611 661 522 423 350 295 253 220 194 173 156 142 130 120 111
1731 1708 1689 1673 1659 1648 1881 1697 1564 1466 1393 1337 1293 1259 1231 1208 1189 1173 1159 1148 1381 1197 1064 966 893 837 793 759 731 708 689 673 659 648 881 697 564 466 393 337 293 259 231 208 189 173 159 148
2788 2760 2736 2716 2699 2685 3101 2871 2705 2583 2491 2421 2366 2323 2288 2260 2236 2216 2199 2185 2601 2371 2205 2083 1991 1921 1866 1823 1788 1760 1736 1716 1699 1685 2101 1871 1705 1583 1491 1421 1366 1323 1288 1260 1236 1216 1199 1185 1601 1371 1205 1083 991 921 866 823 788 760 736 716 699 685
3846 3812 3783 3759 3739 3722 4321 4045 3846 3699 3589 3505 3440 3388 3346 3312 3283 3259 3239 3222 3821 3545 3346 3199 3089 3005 2940 2888 2846 2812 2783 2759 2739 2722 3321 3045 2846 2699 2589 2505 2440 2388 2346 2312 2283 2259 2239 2222 2821 2545 2346 2199 2089 2005 1940 1888 1846 1812 1783 1759 1739 1722
4904 4864 4830 4803 4779 4759 5542 5219 4987 4816 4688 4590 4513 4452 4404 4364 4330 4303 4279 4259 5042 4719 4487 4316 4188 4090 4013 3952 3904 3864 3830 3803 3779 3759 4542 4219 3987 3816 3688 3590 3513 3452 3404 3364 3330 3303 3279 3259 4042 3719 3487 3316 3188 3090 3013 2952 2904 2864 2830 2803 2779 2759
5961 5916 5878 5846 5819 5796 6762 6393 6128 5932 5786 5674 5586 5517 5461 5416 5378 5346 5319 5296 6262 5893 5628 5432 5286 5174 5086 5017 4961 4916 4878 4846 4819 4796 5762 5393 5128 4932 4786 4674 4586 4517 4461 4416 4378 4346 4319 4296 5262 4893 4628 4432 4286 4174 4086 4017 3961 3916 3878 3846 3819 3796
74
Table 2. Life-cycle cost of the system per kWp from the user standpoint [LCCUSP]kWp, as a function of the initial investment in the PVGCS per kWp ([PVIN]kWp), the nominal discount rate d and the initial investment subsidy per kWp ([PVIS]kWp). Loan duration Nl = 10 years, il = 5%.
[PVIS]kWp (€/kWp) 0
1000
1500
2000
2500
[PVIN]kWp (€/kWp) d
3000
4000
5000
6000
7000
8000
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15
4340 3836 3423 3078 2788 2541 2328 2144 1983 1842 1717 1606 1507 1418 3114 2732 2423 2169 1957 1778 1625 1494 1380 1280 1192 1114 1044 982 2501 2179 1923 1714 1541 1397 1274 1169 1078 999 929 868 813 764 1887 1627 1423 1259 1126 1015 923 844 776 718 667 622 582 547 1274 1075 923 804 710 634 571 519
5787 5115 4564 4104 3717 3388 3104 2858 2644 2455 2289 2141 2009 1891 4561 4011 3564 3195 2886 2625 2401 2208 2041 1894 1764 1649 1547 1455 3947 3458 3064 2740 2471 2244 2050 1883 1739 1613 1501 1403 1315 1237 3334 2906 2564 2285 2055 1862 1699 1558 1437 1332 1239 1157 1084 1019 2721 2354 2064 1831 1640 1481 1347 1233
7234 6394 5705 5131 4647 4234 3880 3573 3305 3069 2861 2676 2511 2363 6007 5289 4705 4221 3816 3472 3177 2923 2702 2507 2336 2184 2049 1928 5394 4737 4205 3766 3400 3090 2826 2598 2400 2226 2074 1938 1818 1710 4781 4185 3705 3311 2984 2709 2475 2273 2098 1945 1811 1692 1586 1492 4168 3632 3205 2857 2569 2328 2123 1948
8681 7673 6846 6157 5576 5081 4656 4288 3966 3683 3433 3212 3013 2836 7454 6568 5846 5247 4745 4319 3953 3638 3363 3121 2908 2720 2551 2400 6841 6016 5346 4792 4329 3937 3602 3313 3061 2840 2646 2473 2320 2182 6228 5464 4846 4338 3914 3556 3251 2988 2759 2559 2383 2227 2089 1964 5614 4911 4346 3883 3498 3175 2899 2663
10128 8952 7987 7183 6505 5928 5432 5002 4627 4297 4006 3747 3516 3309 8901 7847 6987 6273 5674 5166 4729 4352 4023 3735 3481 3255 3053 2873 8288 7295 6487 5818 5259 4784 4378 4027 3722 3454 3218 3009 2822 2655 7675 6742 5987 5364 4843 4403 4027 3702 3420 3173 2956 2763 2591 2437 7061 6190 5487 4909 4428 4022 3675 3377
11574 10231 9128 8209 7435 6775 6208 5717 5288 4911 4578 4282 4018 3781 10348 9126 8128 7299 6604 5717 5505 5067 4684 4349 4053 3790 3556 3345 9735 8574 7628 6845 6188 5631 5154 4742 4383 4068 3790 3544 3324 3128 9121 8021 7128 6390 5773 5250 4803 4417 4081 3787 3528 3298 3093 6884 8508 7469 6628 5935 5357 4868 4451 4092
(Continued overleaf) 75
[PVIN]kWp (€/kWp)
[PVIS]kWp(€/kWp) 2500
3000
3500
4000
4500
d
3000
4000
5000
6000
7000
8000
0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
475 437 404 376 351 329 661 522 423 350 295 253 220 194 173 156 142 130 120 111
1136 1051 976 911 853 801 2108 1801 1564 1376 1224 1100 996 909 834 770 714 665 622 583 1494 1249 1064 921 808 718 645 584 532 489 451 419 391 366 881 697 564 466 393 337 293 259 231 208 189 173 159 148
1797 1665 1549 1446 1355 1274 3554 3080 2705 2402 2153 1946 1772 1623 1495 1384 1286 1200 1124 1056 2941 2528 2205 1947 1738 1565 1421 1298 1193 1103 1024 954 893 838 2328 1975 1705 1492 1322 1184 1069 973 892 822 761 708 662 620 1714 1423 1205 1037 907 802 718 648 590 541 499 462 430 403
2458 2278 2121 1981 1857 1747 5001 4359 3846 3428 3083 2793 2548 2338 2156 1997 1858 1735 1626 1529 4388 3807 3346 2973 2667 2412 2197 2013 1854 1716 1596 1489 1395 1311 3775 3254 2846 2518 2252 2031 1845 1688 1553 1436 1333 1243 1164 1093 3161 2702 2346 2064 1836 1649 1494 1363 1251 1155 1071 997 933 875
3119 2892 2693 2517 2360 2219 6448 5638 4987 4454 4012 3640 3324 3052 2817 2611 2431 2271 2129 2001 5835 5085 4487 3999 3596 3259 2973 2727 2515 2330 2168 2025 1897 1784 5221 4533 3987 3545 3181 2878 2621 2402 2214 2049 1906 1779 1666 1566 4608 3981 3487 3090 2765 2496 2270 2077 1912 1768 1643 1533 1435 1348
3780 3506 3265 3052 2862 2692 7895 6917 6128 5480 4941 4487 4100 3767 3478 3225 3003 2806 2631 2474 7281 6364 5628 5025 4526 4106 3749 3442 3176 2944 2740 2560 2400 2256 6668 5812 5128 4571 4110 3724 3397 3117 2875 2663 2478 2314 2168 2038 6055 5260 4628 4116 3695 3343 3046 2792 2573 2382 2215 2068 1937 1821
76
Table 3. Life-cycle cost of the system per kWp from the user standpoint [LCCUSP]kWp, as a function of the initial investment in the PVGCS per kWp ([PVIN]kWp), the nominal discount rate d and the initial investment subsidy per kWp ([PVIS]kWp). Loan duration Nl = 20 years, il = 5%.
[PVIS]kWp(€/kWp) 0
1000
1500
2000
2500
[PVIN]kWp (€/kWp) d
3000
4000
5000
6000
7000
8000
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15
5005 4104 3423 2900 2492 2170 1911 1701 1528 1384 1263 1160 1071 995 3557 2910 2423 2050 1760 1531 1347 1198 1076 974 889 816 754 700 2833 2313 1923 1625 1393 1211 1065 947 850 770 702 645 595 553 2109 1716 1423 1200 1027 892 784 696 625 565 515 473 437 406 1385 1119 923 775 661 572 502 445
6673 5472 4564 3867 3323 2893 2548 2268 2037 1845 1684 1546 1428 1327 5225 4278 3564 3016 2590 2254 1984 1765 1585 1436 1310 1203 1111 1032 4501 3681 3064 2591 2224 1934 1702 1514 1360 1231 1123 1031 953 885 3777 3084 2564 2166 1858 1615 1421 1263 1134 1026 936 860 794 737 3053 2487 2064 1741 1492 1295 1139 1012
8341 6840 5705 4833 4154 3616 3185 2835 2546 2306 2104 1933 1786 1658 6893 5646 4705 3983 3421 2977 2621 2332 2095 1897 1731 1589 1468 1364 6169 5049 4205 3558 3055 2658 2339 2081 1869 1692 1544 1418 1310 1216 5445 4452 3705 3133 2689 2338 2058 1830 1643 1488 1357 1246 1151 1069 4721 3855 3205 2708 2322 2019 1776 1579
10010 8208 6846 5800 4984 4339 3822 3401 3055 2768 2525 2319 2143 1990 8561 7014 5846 4950 4252 3700 3258 2899 2604 2358 2152 1976 1825 1695 7837 6417 5346 4525 3886 3381 2976 2648 2378 2154 1965 1804 1667 1548 7113 5820 4846 4100 3519 3061 2695 2397 2152 1949 1778 1633 1508 1400 6389 5223 4346 3675 3153 2742 2413 2146
11678 9576 7987 6766 5815 5063 4459 3968 3565 3229 2946 2706 2500 2322 10230 8382 6987 5916 5083 4424 3895 3466 3113 2819 2572 2363 2183 2027 9506 7785 6487 5491 4716 4104 3613 3215 2887 2615 2386 2191 2024 1879 8782 7188 5987 5066 4350 3785 3332 2964 2662 2410 2199 2019 1865 1732 8058 6591 5487 4641 3984 3465 3050 2713
13346 10944 9128 7733 6646 5786 5096 4535 4074 3690 3367 3092 2857 2653 11898 9750 8128 6883 5913 4535 4532 4033 3622 3281 2993 2749 2540 2358 11174 9153 7628 6458 5547 4827 4250 3782 3397 3076 2807 2577 2381 2211 10450 8556 7128 6033 5181 4508 3969 3531 3171 2871 2620 2406 2222 5555 9726 7959 6628 5608 4815 4188 3687 3280
(Continued overleaf)
77
[PVIS]kWp(€/kWp) 2500
3000
3500
4000
4500
[PVIN]kWp (€/kWp) d
3000
4000
5000
6000
7000
8000
0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
399 361 328 301 278 258 661 522 423 350 295 253 220 194 173 156 142 130 120 111
908 822 749 688 635 590 2329 1890 1564 1316 1125 976 857 761 682 617 563 516 477 442 1605 1293 1064 891 759 656 575 510 456 412 376 345 318 295 881 697 564 466 393 337 293 259 231 208 189 173 159 148
1417 1283 1170 1074 992 921 3997 3258 2705 2283 1956 1699 1494 1328 1191 1078 983 903 834 774 3273 2661 2205 1858 1590 1380 1212 1077 966 874 797 731 675 627 2549 2064 1705 1433 1224 1060 930 825 740 669 610 559 517 479 1825 1468 1205 1008 857 741 648 574 514 464 423 388 358 332
1927 1744 1591 1461 1350 1253 5665 4626 3846 3249 2787 2422 2131 1895 1701 1540 1404 1289 1191 1106 4941 4029 3346 2824 2421 2103 1849 1644 1475 1335 1217 1118 1032 958 4217 3432 2846 2399 2054 1783 1567 1392 1249 1130 1031 946 874 811 3493 2835 2346 1974 1688 1464 1285 1141 1023 926 844 774 715 664
2436 2206 2012 1848 1707 1585 7334 5994 4987 4216 3618 3146 2768 2462 2210 2001 1825 1676 1548 1437 6610 5397 4487 3791 3251 2826 2486 2210 1984 1796 1638 1504 1389 1290 5886 4800 3987 3366 2885 2507 2204 1959 1758 1592 1451 1333 1231 1143 5162 4203 3487 2941 2519 2187 1922 1708 1533 1387 1265 1161 1072 995
2945 2667 2433 2234 2064 1916 9002 7362 6128 5183 4448 3869 3405 3028 2719 2462 2246 2062 1905 1769 8278 6765 5628 4758 4082 3549 3123 2777 2493 2257 2059 1891 1747 1622 7554 6168 5128 4333 3716 3230 2841 2526 2268 2053 1872 1719 1588 1474 6830 5571 4628 3908 3350 2910 2559 2275 2042 1848 1686 1548 1429 1327
78
d
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
(Continued overleaf)
0.3
0.2
0.1
pu (€/kWh)
[EPV]kWp (kWh/(kWp.year))
1500 1174 941 771 645 549 474 416 369 331 300 273 251 232 3000 2348 1883 1543 1290 1098 949 832 738 662 599 547 503 465 4500 3522 2824 2314 1935 1646 1423 1248 1107 993 899 820 754 697
600
2000 1566 1255 1028 860 732 633 555 492 441 400 365 335 310 4000 3131 2510 2057 1720 1463 1265 1109 984 883 799 729 670 620 6000 4697 3765 3085 2579 2195 1898 1664 1477 1324 1199 1094 1005 929
800
2500 1957 1569 1286 1075 915 791 693 615 552 499 456 419 387 5000 3914 3138 2571 2149 1829 1582 1387 1231 1104 999 912 838 774 7500 5871 4706 3857 3224 2744 2372 2080 1846 1655 1498 1367 1256 1162
1000
3000 2348 1883 1543 1290 1098 949 832 738 662 599 547 503 465 6000 4697 3765 3085 2579 2195 1898 1664 1477 1324 1199 1094 1005 929 9000 7045 5648 4628 3869 3293 2847 2496 2215 1987 1798 1641 1508 1394
1200
3500 2740 2196 1800 1505 1281 1107 971 861 773 699 638 586 542 7000 5479 4393 3600 3009 2561 2214 1941 1723 1545 1399 1276 1173 1084 10500 8219 6589 5399 4514 3842 3321 2912 2584 2318 2098 1914 1759 1626
1400
4000 3131 2510 2057 1720 1463 1265 1109 984 883 799 729 670 620 8000 6262 5020 4114 3439 2927 2531 2219 1969 1766 1598 1458 1340 1239 12000 9393 7530 6171 5159 4390 3796 3328 2953 2649 2398 2188 2010 1859
1600
4500 3522 2824 2314 1935 1646 1423 1248 1107 993 899 820 754 697 9000 7045 5648 4628 3869 3293 2847 2496 2215 1987 1798 1641 1508 1394 13500 10567 8471 6942 5804 4939 4270 3744 3322 2980 2697 2461 2261 2091
1800
5000 3914 3138 2571 2149 1829 1582 1387 1231 1104 999 912 838 774 10000 7828 6275 5142 4299 3659 3163 2773 2461 2207 1998 1823 1675 1549 15000 11741 9413 7714 6448 5488 4745 4160 3692 3311 2997 2735 2513 2323
2000
5500 4305 3451 2828 2364 2012 1740 1525 1354 1214 1099 1003 921 852 11000 8610 6903 5657 4729 4024 3480 3051 2707 2428 2198 2005 1843 1704 16500 12915 10354 8485 7093 6037 5219 4576 4061 3642 3297 3008 2764 2555
2200
6000 4697 3765 3085 2579 2195 1898 1664 1477 1324 1199 1094 1005 929 12000 9393 7530 6171 5159 4390 3796 3328 2953 2649 2398 2188 2010 1859 18000 14090 11295 9256 7738 6586 5694 4992 4430 3973 3596 3281 3015 2788
2400
79
Table 4. Present worth of cash inflows per kWp of a PVGCS ([PW[CIF(N)]]kWp) as a function of the annual yield per kWp of the system ([EPV]kWp)· the discount rate d and the unitary price per kWh (pu) to be paid/saved to/by the user (annual increase rate of energy price pu = 0·01).
0.6
0.5
0.4
pu (€/kWh)
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
d
[EPV]kWp (kWh/(kWp.year))
6000 4697 3765 3085 2579 2195 1898 1664 1477 1324 1199 1094 1005 929 7500 5871 4706 3857 3224 2744 2372 2080 1846 1655 1498 1367 1256 1162 9000 7045 5648 4628 3869 3293 2847 2496 2215 1987 1798 1641 1508 1394
600 8000 6262 5020 4114 3439 2927 2531 2219 1969 1766 1598 1458 1340 1239 10000 7828 6275 5142 4299 3659 3163 2773 2461 2207 1998 1823 1675 1549 12000 9393 7530 6171 5159 4390 3796 3328 2953 2649 2398 2188 2010 1859
800 10000 7828 6275 5142 4299 3659 3163 2773 2461 2207 1998 1823 1675 1549 12500 9784 7844 6428 5374 4573 3954 3467 3076 2759 2497 2279 2094 1936 15000 11741 9413 7714 6448 5488 4745 4160 3692 3311 2997 2735 2513 2323
1000 12000 9393 7530 6171 5159 4390 3796 3328 2953 2649 2398 2188 2010 1859 15000 11741 9413 7714 6448 5488 4745 4160 3692 3311 2997 2735 2513 2323 18000 14090 11295 9256 7738 6586 5694 4992 4430 3973 3596 3281 3015 2788
1200 14000 10959 8785 7199 6019 5122 4429 3883 3446 3090 2797 2552 2345 2168 17500 13698 10981 8999 7523 6403 5536 4853 4307 3863 3496 3190 2932 2710 21000 16438 13178 10799 9028 7683 6643 5824 5168 4635 4196 3828 3518 3252
1400 16000 12524 10040 8228 6878 5854 5061 4437 3938 3532 3197 2917 2680 2478 20000 15655 12550 10285 8598 7317 6327 5547 4922 4415 3996 3646 3350 3098 24000 18786 15060 12342 10318 8781 7592 6656 5907 5297 4795 4375 4020 3717
1600 18000 14090 11295 9256 7738 6586 5694 4992 4430 3973 3596 3281 3015 2788 22500 17612 14119 11570 9673 8232 7117 6240 5537 4966 4495 4102 3769 3485 27000 21134 16943 13884 11607 9878 8541 7488 6645 5960 5394 4922 4523 4182
1800 20000 15655 12550 10285 8598 7317 6327 5547 4922 4415 3996 3646 3350 3098 25000 19569 15688 12856 10747 9147 7908 6933 6153 5518 4995 4558 4188 3872 30000 23483 18825 15427 12897 10976 9490 8320 7383 6622 5994 5469 5026 4646
2000 22000 17221 13805 11313 9458 8049 6959 6101 5414 4856 4395 4011 3685 3407 27500 21526 17256 14141 11822 10061 8699 7627 6768 6070 5494 5013 4607 4259 33000 25831 20708 16970 14187 12073 10439 9152 8122 7284 6593 6016 5528 5111
2200 24000 18786 15060 12342 10318 8781 7592 6656 5907 5297 4795 4375 4020 3717 30000 23483 18825 15427 12897 10976 9490 8320 7383 6622 5994 5469 5026 4646 36000 28179 22590 18512 15476 13171 11388 9984 8860 7946 7193 6563 6031 5576
2400
80
d
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
(Continued overleaf)
0.3
0.2
0.1
pu (€/kWh)
[EPV]kWp (kWh/(kWp.year))
1709 1325 1052 854 708 598 513 447 395 352 318 289 264 244 3419 2649 2103 1708 1416 1196 1027 895 790 705 635 577 529 488 5128 3974 3155 2562 2124 1794 1540 1342 1184 1057 953 866 793 731
600 2279 1766 1402 1139 944 797 684 596 526 470 423 385 353 325 4558 3532 2804 2277 1888 1594 1369 1193 1053 940 847 770 705 650 6837 5298 4207 3416 2832 2392 2053 1789 1579 1409 1270 1155 1058 975
800 2849 2208 1753 1423 1180 996 856 746 658 587 529 481 441 406 5698 4415 3506 2847 2360 1993 1711 1491 1316 1175 1059 962 881 813 8546 6623 5258 4270 3540 2989 2567 2237 1974 1762 1588 1444 1322 1219
1000 3419 2649 2103 1708 1416 1196 1027 895 790 705 635 577 529 488 6837 5298 4207 3416 2832 2392 2053 1789 1579 1409 1270 1155 1058 975 10256 7948 6310 5124 4248 3587 3080 2684 2369 2114 1906 1732 1587 1463
1200 3988 3091 2454 1993 1652 1395 1198 1044 921 822 741 674 617 569 7977 6181 4908 3985 3304 2790 2396 2087 1842 1644 1482 1347 1234 1138 11965 9272 7362 5978 4956 4185 3594 3131 2764 2467 2223 2021 1851 1706
1400 4558 3532 2804 2277 1888 1594 1369 1193 1053 940 847 770 705 650 9116 7065 5609 4555 3776 3189 2738 2386 2106 1879 1694 1540 1410 1300 13674 10597 8413 6832 5664 4783 4107 3578 3158 2819 2541 2310 2116 1950
1600 5128 3974 3155 2562 2124 1794 1540 1342 1184 1057 953 866 793 731 10256 7948 6310 5124 4248 3587 3080 2684 2369 2114 1906 1732 1587 1463 15383 11921 9465 7686 6372 5381 4620 4026 3553 3171 2858 2599 2380 2194
1800 5698 4415 3506 2847 2360 1993 1711 1491 1316 1175 1059 962 881 813 11395 8831 7011 5693 4720 3986 3422 2982 2632 2349 2117 1925 1763 1625 17093 13246 10517 8540 7079 5979 5134 4473 3948 3524 3176 2887 2644 2438
2000 6267 4857 3856 3131 2596 2192 1882 1640 1448 1292 1165 1059 970 894 12535 9714 7712 6263 5192 4384 3765 3280 2895 2584 2329 2117 1939 1788 18802 14571 11568 9394 7787 6577 5647 4920 4343 3876 3494 3176 2909 2682
2200 6837 5298 4207 3416 2832 2392 2053 1789 1579 1409 1270 1155 1058 975 13674 10597 8413 6832 5664 4783 4107 3578 3158 2819 2541 2310 2116 1950 20511 15895 12620 10248 8495 7175 6160 5368 4737 4228 3811 3465 3173 2925
2400
81
Table 5. Present worth of cash inflows per kWp of a PVGCS ([PW[CIF(N)]]kWpp) as a function of the annual yield per kWp of the system ([EPV]kWp)· the discount rate d and the unitary price per kWh (pu) to be paid/saved to/by the user (annual increase rate of energy price pu = 0·02).
0.6
0.5
0.4
pu (€/kWh)
0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27 0.01 0.03 0.05 0.07 0.09 0.11 0.13 0.15 0.17 0.19 0.21 0.23 0.25 0.27
d
[EPV]kWp (kWh/(kWp.year))
6837 5298 4207 3416 2832 2392 2053 1789 1579 1409 1270 1155 1058 975 8546 6623 5258 4270 3540 2989 2567 2237 1974 1762 1588 1444 1322 1219 10256 7948 6310 5124 4248 3587 3080 2684 2369 2114 1906 1732 1587 1463
600 9116 7065 5609 4555 3776 3189 2738 2386 2106 1879 1694 1540 1410 1300 11395 8831 7011 5693 4720 3986 3422 2982 2632 2349 2117 1925 1763 1625 13674 10597 8413 6832 5664 4783 4107 3578 3158 2819 2541 2310 2116 1950
800 11395 8831 7011 5693 4720 3986 3422 2982 2632 2349 2117 1925 1763 1625 14244 11038 8764 7117 5900 4982 4278 3728 3290 2936 2647 2406 2204 2031 17093 13246 10517 8540 7079 5979 5134 4473 3948 3524 3176 2887 2644 2438
1000 13674 10597 8413 6832 5664 4783 4107 3578 3158 2819 2541 2310 2116 1950 17093 13246 10517 8540 7079 5979 5134 4473 3948 3524 3176 2887 2644 2438 20511 15895 12620 10248 8495 7175 6160 5368 4737 4228 3811 3465 3173 2925
1200 15953 12363 9816 7971 6607 5580 4791 4175 3685 3289 2964 2695 2468 2275 19942 15454 12269 9963 8259 6975 5989 5219 4606 4111 3705 3368 3085 2844 23930 18544 14723 11956 9911 8370 7187 6262 5527 4933 4446 4042 3702 3413
1400 18232 14129 11218 9109 7551 6377 5476 4771 4211 3759 3388 3080 2821 2600 22790 17661 14022 11387 9439 7972 6845 5964 5264 4698 4235 3850 3526 3250 27348 21194 16827 13664 11327 9566 8214 7157 6317 5638 5082 4620 4231 3900
1600 20511 15895 12620 10248 8495 7175 6160 5368 4737 4228 3811 3465 3173 2925 25639 19869 15775 12810 10619 8968 7701 6710 5922 5286 4764 4331 3967 3657 30767 23843 18930 15372 12743 10762 9241 8052 7106 6343 5717 5197 4760 4388
1800 22790 17661 14022 11387 9439 7972 6845 5964 5264 4698 4235 3850 3526 3250 28488 22077 17528 14233 11799 9965 8556 7455 6580 5873 5293 4812 4407 4063 34185 26492 21033 17080 14159 11958 10267 8946 7896 7047 6352 5775 5289 4876
2000 25069 19427 15424 12525 10383 8769 7529 6561 5790 5168 4658 4235 3878 3575 31337 24284 19281 15657 12979 10961 9412 8201 7238 6460 5823 5293 4848 4469 37604 29141 23137 18788 15575 13153 11294 9841 8685 7752 6987 6352 5818 5363
2200 27348 21194 16827 13664 11327 9566 8214 7157 6317 5638 5082 4620 4231 3900 34185 26492 21033 17080 14159 11958 10267 8946 7896 7047 6352 5775 5289 4876 41023 31790 25240 20496 16991 14349 12321 10735 9475 8457 7622 6929 6347 5851
2400
82
APPENDIX II OF SECTION 5: TERMINOLOGY
[EPV]kWp
Normalised (per kWp) annual PV electricity yield (kWh·kWp -1·yr-1).
[LCCUSP]kWp
Normalised (per kWp) life – cycle cost of the PVGCS from the user standpoint (€·kWp-1).
[PVIS ]kWp
Normalised (per kWp) initial buy-down or subsidy (€·kWp-1).
[PVIN]kWp
Normalised (per kWp) initial investment on the PVGCS (€·kWp-1).
[PW[CIF(N)]]kWp Normalised (per kWp) present worth of the cash inflows from a PVGCS through its useful life (€·kWp-1). d
Nominal discount rate.
EPV
Annual PV electricity yield (kWh).
il
Annual loan interest.
g
Annual inflation rate.
IRR
Internal rate of return.
LCCUSP
Life - cycle cost of the PVGCS from the user standpoint (€).
N
Useful life of the PVGCS (years).
Nl
Time duration of loan (years).
NPV
Net present value (€).
pu
PV-electricity unitary price paid/saved to/by the user (€·kWh-1)
PVIS
Initial buy-down or subsidy (€).
PVIN
Initial investment on the PVGCS (€).
PW[CIF(N)]
Present worth of the cash inflows from a PVGCS through its useful life (€).
pu
Annual increase rate of the energy price consumed/sold from/to the grid
APPENDIX: MAIN TECHNICAL AND CONTRACTUAL POINTS TO BE CHECKED AND COMPARED WHEN EXAMINING A PROPOSAL FROM AN EPC SUPPLIER
This appendix is aimed at verifying through cross-checks if the EPC (engineering, procurement and construction) supplier proposal is sound. It must be borne in mind the high important of this hot issue. Making sure that a proposal guarantees a minimum production, a long-lasting durability and reliability is the key to avoid misunderstandings and future litigations. Some examples of these cross-checks are provided below: Is the EPC supplier experienced and skilled? Unskilled PVPPs EPC suppliers are not infrequent, unfortunately
83
Is a minimum electricity production per kWp guaranteed? Is this production clearly linked to an easily measurable parameter (e.g.: irradiation measured by an external and independent body)? Avoid production warranties related to performance indices which are difficult and not straightforward to understand and measure (e.g.: performance ratio) Are protective measures suitably sized and planned in the proposal? Fuses, voltage surge arrestors, good metal works earthening, etc. sometimes are omitted or wrongly sized Is the operation and maintenance contract (O&M, usually offered by the EPC supplier) clear and rigorous? Does the contract include a reliable insurance (min.100% insurance coverage: theft, natural disasters, vandalism, etc.)? Is the EPC supplier willing to let the PVPP undergo a quality check (careful visual inspection, measuring the actual PV generator peak power, measuring earth electrode resistance, IR imaging analysis, etc. by an external body (University, Accredited Independent Laboratory, etc.) once this PVPP has been deployed? Do PV modules comply with IEC 60215 standard? Are modules undetachably labeled with their serial number? Is (Are) the inverter(s) TĂ&#x153;V certified? Is the module manufacturer acceptable for taking money on loan from a bank? Prospective owners are usually refused credit if emerging technologies are used in the EPC proposal (thin film, concentrating PV, etc.)
ACKNOWLEDGEMENTS The authors wish to thank the following people for their valuable help to prepare this text: D. Bedin and E. Holland (Union of Veneto Chambers of Commerce) G. Dovigi (Italian-Slovak Chamber of Commerce)
84
J. Olchowik, K. Cyeslak and M. Sordyl (Institute of Physics of Lublin University of Technology) G. Agrigiannis (Development Company of Municipality of Milies)
85
*4#/