Solar Energy 77 (2004) 171–178
www.elsevier.com/locate/solener
Technical and economical system comparison
of photovoltaic and concentrating solar thermal power
systems depending on annual global irradiation
Volker Quaschning
*
FHTW Berlin, Berlin University of Applied Sciences, Marktstr. 9, D-10317 Berlin, Germany
Received 30 July 2003; received in revised form 30 March 2004; accepted 22 April 2004
Available online 31 May 2004
Communicated by: Associate Editor David Mills
Abstract
Concentrating solar thermal power and photovoltaics are two major technologies for converting sunlight to electricity. Variations of the annual solar irradiation depending on the site influence their annual efficiency, specific output
and electricity generation cost. Detailed technical and economical analyses performed with computer simulations point
out differences of solar thermal parabolic trough power plants, non-tracked and two-axis-tracked PV systems. Therefore,
61 sites in Europe and North Africa covering a global annual irradiation range from 923 to 2438 kW h/m2 a have been
examined. Simulation results are usable irradiation by the systems, specific annual system output and levelled electricity
cost. Cost assumptions are made for today’s cost and expected cost in 10 years considering different progress ratios. This
will lead to a cost reduction by 50% for PV systems and by 40% for solar thermal power plants. The simulation results
show where are optimal regions for installing solar thermal trough and tracked PV systems in comparison to non-tracked
PV. For low irradiation values the annual output of solar thermal systems is much lower than of PV systems. On the
other hand, for high irradiations solar thermal systems provide the best-cost solution even when considering higher cost
reduction factors for PV in the next decade. Electricity generation cost much below 10 Eurocents per kW h for solar
thermal systems and about 12 Eurocents/kW h for PV can be expected in 10 years in North Africa.
2004 Published by Elsevier Ltd.
Keywords: Concentrating solar power; Photovoltaics; Global irradiation; Electricity generation cost; Computer simulation;
Economics; Photovoltaic systems; Solar thermal power systems
1. Introduction
Concentrating solar thermal systems such as parabolic trough power plants or solar tower power plants
and photovoltaic systems can convert sunlight to electricity. Recommended sites for the installation of
*
Corresponding author. Tel.: +49-30-55134-256; fax: +4930-55134-199.
E-mail address: volker.quaschning@fhtw-berlin.de (V.
Quaschning).
URL: http://www.volker-quaschning.de.
0038-092X/$ - see front matter 2004 Published by Elsevier Ltd.
doi:10.1016/j.solener.2004.04.011
concentrating solar systems are situated in the sunbelt of
the earth, where the direct irradiation is high. On the
other hand, many calculations have shown that concentrating solar thermal systems are more cost-effective
than photovoltaic systems not only in the sunbelt (Trieb
et al., 1997). However, until the year 2003 commercial
solar thermal systems have been only built in the Mojave
desert in California where the annual global solar irradiation is higher than 2100 kW h/m2 . It is not easy to
estimate the minimum irradiation for concentrating
solar thermal systems to be operated more economically
than PV. Furthermore, conditions will change in the
next decade. This paper shall deal with these open
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V. Quaschning / Solar Energy 77 (2004) 171–178
Nomenclature
G
Gb
Gd
Gd30
Gdn
Gr30
Grn
H1ax
global irradiance in W m2
beam irradiance in W m2
diffuse irradiance in W m2
diffuse irradiance on a 30 sloped Southoriented surface in W m2
diffuse irradiance on normal plane facing to
the sun in W m2
ground reflected irradiance on a 30 sloped
South-oriented plane in W m2
ground reflected irradiance on a normal
plane facing to the sun in W m2
direct irradiation on a one-axis tracked
plane in W h m2
questions carrying out detailed technical and economical analyses of these two technologies. Therefore, the
greenius simulation software has been used. This software was developed especially for carrying out such
investigations and offers the possibility to compare different types of solar electricity generation systems at
different sites. Two types of photovoltaic and solar
thermal parabolic trough systems have been simulated
at 61 sites. Altogether 183 simulation runs assuming
today’s cost and expected cost in 10 years provide the
basis for this paper.
1.1. Examined photovoltaics systems
Since cost estimations for concentrating PV installations have a high uncertainty, only non-concentrating
PV systems were considered. For the simulations in this
paper two types of photovoltaic systems have been
chosen:
• non-tracking system with 30 slope angle,
• two-axis tracking system.
For the following calculations, the nominal efficiencies of both systems are the same, whereas the annual
efficiencies are site dependent. During the simulations
the hourly output of a reference PV system was calculated to obtain the annual efficiency. Part-load behaviour of PV modules and inverters were calculated
with empirical models. The annual self-consumption
of the two-axis tracking system was estimated with
10 kW h/m2 .
1.2. Examined solar thermal power plant
354 MW of solar electric generating systems (SEGS)
parabolic trough power plants have been connected to
the grid in Southern California since the mid-1980s.
H30
Hb
Hgn
Greeks
a
b
c
cax
h
irradiation on a 30 sloped South-oriented
plane in W h m2
beam irradiation on a normal plane facing
to the sun in W h m2
global normal irradiation on a normal plane
facing to the sun in W h m2
sun altitude
tilt angle
sun azimuth
azimuth angle of tracking axis
angle of incidence
Therefore, they represent the most mature solar thermal
power technology (Quaschning and Blanco, 2001). To
date, there are more than 100 plant-years of experience
from the nine operating plants, which range in size from
14 to 80 MW. Most of the currently planned solar
thermal power projects are also parabolic trough power
plants. For this reason, this paper considers state of the
art parabolic trough power plants as shown in Fig. 1.
The output for these power plants was simulated using
hourly meteorological data. The optical and thermal
collector efficiency, the field losses and the power block
efficiency were calculated for the whole year to estimate
the annual system efficiency as described by Quaschning
et al. (2002).
1.3. Use of simulation software
Only a powerful simulation tool can provide the results of the system analyses presented in this paper.
Many computer programs for simulating photovoltaic
systems are available, but only a few software codes exist
to simulate concentrating solar thermal power systems,
e.g. the TRNSYS STEC library (Jones et al., 2001).
However, since no available simulation software can
perform detailed technical and economical calculations
of both PV and solar thermal systems DLR has developed the new simulation environment greenius for the
technical and economical analysis of renewable power
projects such as photovoltaic, solar thermal or wind
power plants. The inputs for the simulation are hourly
solar irradiance, ambient temperature and other meteorological data. With this meteo data, site information,
technical system data and economical specifications, this
simulation environment calculates the system output,
system efficiencies and other technical parameters and
provides various economical key values (Quaschning
et al., 2001).
V. Quaschning / Solar Energy 77 (2004) 171–178
173
Fig. 1. Scheme of a parabolic trough power plant.
The greenius software has already been used for the
calculations at other studies (Quaschning et al., 2002).
Thus, the greenius simulation environment was also
used to perform the technical and economical calculations presented in this paper.
2. Site, system and cost specifications
Hb ¼
8760
X
ð1Þ
The chosen one-axis tracking concentrating solar thermal power system can use the direct irradiation H1ax on a
single-axis tracking device (trough collector). Therefore,
the beam irradiance Gb must be projected into the collector area:
8760
X
H1ax ¼
Gb cos h 1 h:
ð2Þ
t¼1
2.1. Solar irradiance
The further simulations have been carried out for 61
sites in Europe and North Africa. These sites cover a
global annual irradiation range from 923 kW h/m2 a in
Dublin (Ireland) until 2438 kW h/m2 a in Luxor (Egypt).
The databases Satellight (Satel-light, 1998) and Meteonorm (Meteotest, 2003) provided mean hourly global G,
diffuse Gd and direct normal or beam Gb irradiance
values for the simulations. The free Satellight database
contains irradiance data for whole Europe and Africa
north of the 34th latitude using half-hourly images of
weather satellites. The Meteonorm database was used
for including irradiance data also of other North Africa
sites, for instance Egypt. Meteonorm contains an
extensive database of monthly irradiation values. It
applies statistical models for estimating the hourly
irradiance. Both databases show differences in the annual irradiation of more than 10% for single sites.
Hence, there is always a relative high uncertainty for
solar irradiation even when using sophisticated meteorological databases.
A two-axis tracking concentrating solar system can
use the annual beam irradiation Hb that is the sum of the
hourly beam irradiance Gb :
Gb 1 h:
t¼1
Hereby the angle of incidence h (Stine and Harrigan,
1985) is calculated in dependence on sun elevation a, sun
azimuth c, tilt angle b the azimuth angle cax of the
tracking axis at the middle of each time interval
h¼
arccos
qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi
2
1 ðcosða bÞ cos b cos a ð1 cosðc cax ÞÞÞ :
ð3Þ
Methods to calculate the angles a and c for position of
the sun are given by (Quaschning, 2003) or (Duffie and
Beckman, 1991). The tilt angle b and azimuth angle cax
of a horizontal trough collector oriented in N–S direction are zero.
The fixed PV system with a tilt angle of 30 can use
the global irradiation H30 on a fixed, 30 sloped surface
oriented to the South:
H30 ¼
8760
X
ðGb cos h þ Gd30 þ Gr30 Þ 1 h:
ð4Þ
t¼1
Therefore, the hourly beam irradiance Gb the angle of
incidence h on the sloped surface, the diffuse irradiance
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V. Quaschning / Solar Energy 77 (2004) 171–178
2.2. System efficiencies
Gd30 on a 30 sloped surface and the ground reflection
Gr30 must be calculated for every hour of the year.
Methods to calculate the angle of incidence h and the
diffuse and ground-reflected irradiation on a tilted plane
are given by (Quaschning, 2003) or (Duffie and Beckman, 1991). Hourly diffuse irradiance and ground
reflection are calculated using the hourly global irradiance that is provided by the above-described databases.
The annual diffuse irradiation depends significantly on
the diffuse irradiation model. Here, the model of Perez
et al. (1990) was used.
Finally, the two-axis tracking PV system can use the
global normal irradiation Hgn This is calculated similar
to the 30 sloped surface. However, the surface orientation must be changed hourly so that it is perpendicular
to the direction of the solar irradiance
8760
X
ðGb þ Gdn þ Grn Þ 1 h:
ð5Þ
t¼1
Fig. 2 shows the different irradiations depending on the
global irradiation for the chosen 61 sites. For global
horizontal irradiations below 2300 kW h/m2 a the direct
irradiation on the one-axis-tracking system is lower than
the global irradiation on a fixed system. This indicates
clearly that the use of tracked and concentrated solar
systems is difficult in Middle and North European regions. The incident irradiation on 2-axis-tracked systems
is the highest for all sites. The absolute difference between the annual irradiations for all tracking variants is
nearly the same over the full irradiation range. Hence,
the advantage of two-axis-tracking systems compared to
one-axis-tracking systems decreases with increasing annual irradiations. On the other hand, tracking systems
have a much higher output than non-tracking systems
especially at regions with high irradiation values.
Luxor
Cairo
Oujda
El Aricha
Palermo
Milan
Porto
Bern
Zurich
Toulouse
3500
Frankfurt
Dublin
kWh/m²a
Hamburg
4000
Almería
Hgn ¼
The used simulation software has calculated the
hourly output of the investigated solar systems. The
output of the PV systems depends on the site, position of
sun, irradiance and ambient temperature. Humidity and
air pressure influence additionally the output of the solar
thermal system. Parameters of state of the art systems
have been chosen for the simulation. The annual system
efficiency of the monocrystalline silicon PV system of
about 11% is almost constant with the site irradiation
decreasing a little at higher irradiation values due to the
negative influence of correlated higher ambient temperature (Fig. 3). This result is not astonishing, because
PV module efficiency is almost constant over large
irradiance ranges and decreases with higher temperatures.
In contrast to PV systems, the annual system efficiency of parabolic trough systems increases significantly
with the annual irradiation. The part load efficiency of a
steam turbine cycle is much lower than the nominal
efficiency. The efficiency is also reduced during days with
fluctuating irradiance values due to the capacitive
behaviour of the thermal system. Furthermore, sites
with lower irradiation values are situated at higher latitudes where the solar altitude is also lower. This increases the optical losses of one-axis tracked trough
collectors and therefore reduces the efficiency. Lower
ambient temperatures at sites with lower irradiations
increase the thermal losses of the collector and field and
thus reduce the solar thermal collector efficiency. All
these effects were taken into account for the annual
performance analysis. The results show that the annual
system efficiency of a today’s solar thermal trough
power plant varies between 10% and 14% for the considered irradiation range.
3000
2500
2000
1500
global normal irradiation, 2 axis tracking system
direct normal irradiation, 2 axis tracking system
direct irradiation on 1 axis tracking system
global irradiation on 30° tilt, non-tracking system
1000
500
900
1100
1300
1500
1700
1900
2100
2300
2500
global horizontal irradiation in kWh/(m² a)
Fig. 2. Direct normal irradiation, direct irradiation on a 1-axis tracked collector, global irradiation on a 30 tilted surface and global
irradiation on a 2-axis tracked surface as function of the global horizontal irradiation.
V. Quaschning / Solar Energy 77 (2004) 171–178
175
14 %
annual system efficiency
12 %
10 %
8%
6%
standard non-concentrated photovoltaic system
4%
standard parabolic trough system
2%
0%
900
1100
1300
1500
1700
1900
2100
2300
2500
global horizontal irradiation in kWh/(m² a)
Fig. 3. Annual system efficiency of photovoltaic systems and 1-axis tracked concentrating parabolic trough systems as function of the
global horizontal irradiation.
2.3. Cost assumptions
For comparability reasons all costs are related to
square meters of effective system area. Assuming a PV
module efficiency of 13.5% one square meter can hold
PV panels with a capacity of 135Wp . Finally, overall
system cost of 4500 a/kWp result in area related cost of
610 a/m2 . Operation results of existing PV systems have
provided net present values of the cost for operation and
maintenance of about 170 a/m2 . Installation and operation cost of tracked PV systems are higher than the cost
of non-tracking systems. The cost assumptions of about
3000 a/kW for the parabolic trough power plant are
valid for a system with a capacity of 30 MW without
thermal storage. These costs are much lower than the
cost of PV systems (see Table 1) but still in the same
magnitude as in the 1990s, since the installation rates for
solar thermal power plants are not very high today. For
all systems a lifetime of 30 years and an overall discount
rate of 7% were assumed.
Looking at the PV learning curve, there is a cost
reduction by 20% when doubling the market volume
(Woditsch, 2000 or IEA, 2000). In the past, this doubling was achieved almost every 4 years. Assuming the
same growth rates for the next decade, there will be a
cost reduction by 50%.
For solar thermal parabolic trough power plants the
progress ratio is about 0.88 (Enermodal, 1999). In other
words, a price reduction by 12% can be expected when
doubling the market volume. On the other hand, possible growth rates of solar thermal power are higher.
Their power plant installation numbers start from a
lower annual production rate and they have not the
same production limits as PV. Combining lower price
Table 1
Assumptions for today’s system costs
Net present value in
a/m2 for system
Installation
Operation
Total
Non-tracking PV
system
2-axis-tracked PV
system
Parabolic trough
power plant
610
170
780
800
230
1030
450
180
630
Table 2
Assumptions for system costs in 10 years
Net present value in
a/m2 for system
Installation
Operation
Total
Non-tracking PV
system
2-axis-tracked
PV system
Parabolic trough
power plant
305
85
390
400
115
515
270
108
378
reduction and higher growth rates leads to an overall
cost reduction for parabolic trough power plants of
about 40% within the next 10 years. Table 2 summarizes
the assumptions for solar thermal power and PV.
3. Simulation results
Fig. 4 shows the specific annual system output of the
non-tracking and two-axis-tracking PV system as well of
the solar thermal power plant. Up to annual global
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V. Quaschning / Solar Energy 77 (2004) 171–178
irradiation values of about 1700 kW h/m2 a the output of
the solar thermal system is the lowest because efficiency
and usable irradiation are disproportional low. Since the
system efficiency of solar thermal power plants in regions with very high irradiations is higher than the efficiency of PV systems, the specific annual output of the
solar thermal system becomes nearly the same as of the
two-axis-tracked PV system there.
Fig. 5 shows the resulting levelled electricity cost
combining the specific output of Fig. 4 and the specific
400
cost assumptions of Table 1. Since today’s cost of solar
thermal power plants are lower than of PV systems,
levelled electricity cost are also lower above global
irradiations of 1300 kW h/m2 a although the specific
output of the PV system is higher until 1700 kW h/m2 a.
Nevertheless, there is a high uncertainty in the simulation results of solar thermal power plants at very low
irradiations. Due to high investment cost for multimegawatt solar thermal power plants, sites with higher
annual irradiations are recommended.
kWh/m²
350
specific annual output
300
250
200
150
100
2-axis tracking photovoltaic system
parabolic trough system
50
non-tracked 30° tilted photovoltaic system
0
900
1100
1300
1500
1700
1900
2100
2300
2500
global horizontal irradiation in kWh/(m² a)
Fig. 4. Specific annual output of fixed and tracked photovoltaic systems and 1-axis tracked concentrated parabolic trough systems as
function of the global horizontal irradiation.
1
c/kWh
2-axis tracking photovoltaic system
today’s levelled electricity generation cost
0.9
parabolic trough system
0.8
non-tracked 30° tilted photovoltaic system
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
900
1100
1300
1500
1700
1900
2100
2300
2500
global horizontal irradiation in kWh/(m² a)
Fig. 5. Today’s Levelled electricity generation cost for photovoltaic systems and 1-axis tracked concentrated parabolic trough systems
as function of the global horizontal irradiation.
V. Quaschning / Solar Energy 77 (2004) 171–178
levelled electricity generation cost in 10 years
1
177
c/kWh
0.9
2-axis tracking photovoltaic system
parabolic trough system
0.8
non-tracked 30° tilted photovoltaic system
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
900
1100
1300
1500
1700
1900
2100
2300
2500
global horizontal irradiation in kWh/(m² a)
Fig. 6. Levelled electricity generation cost in 10 years for photovoltaic systems and 1-axis tracked concentrated parabolic trough
systems as function of the global horizontal irradiation.
In 10 years, the break-even irradiation for the generation cost of non-concentrating and solar thermal
systems moves to higher irradiation values as shown in
Fig. 6. In South Europe both technologies can operate
with cost below 20 Eurocents/kW h. Solar thermal
power plants remain the best-cost solution in South
Europe and North Africa with possible generation cost
below 10 Eurocents/kW h. Tracked PV systems have
some cost advantages in North Africa.
4. Conclusions
Simulation runs of non-tracking PV systems, twoaxis-tracking PV systems and solar thermal trough
power plants have provided detailed results of technical
and economical parameters for 61 sites in Europe and
North Africa. These results demonstrate the high performance of simulation tools and indicate clearly the
optimal operating ranges for solar thermal power and
PV systems. Today, solar thermal power plants are more
economically at sites with annual global irradiations of
more than 1300 kW h/m2 . Below this value levelled
electricity cost of PV systems are lower. The break-even
irradiation will move to about 1600 kW h/m2 in 10 years
due to higher achievable cost reductions for PV systems.
Tracked PV systems show some slight cost advantages
in regions with high global irradiations above 1800
kW h/m2 . The cost estimations have shown that levelled
electricity cost can come down to a reasonable range
significantly below 10 Eurocents/kW h for solar thermal
power at about 12 Eurocents/kW h for PV systems in
North Africa within the next 10 years. Thus, solar
electricity will get a more important role in the struggle
against global warming.
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