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UNIVERSITEIT GENT
FACULTEIT ECONOMIE EN BEDRIJFSKUNDE
ACADEMIEJAAR 2008 – 2009
Defining the techno‐economic optimal configuration of hybrid solar plants
Masterproef voorgedragen tot het bekomen van de graad van Master in de Bedrijfseconomie
Bosschem Siemon Debacker Alice
onder leiding van
Prof. Johan Albrecht
UNIVERSITEIT GENT
FACULTEIT ECONOMIE EN BEDRIJFSKUNDE
ACADEMIEJAAR 2008 – 2009
Defining the techno‐economic optimal configuration of hybrid solar plants
Masterproef voorgedragen tot het bekomen van de graad van Master in de Bedrijfseconomie
Bosschem Siemon Debacker Alice
onder leiding van
Prof. Johan Albrecht
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 IV
PERMISSION
The undersigned certifies that the contents of this master thesis can be consulted and/or reproduced,
if source acknowledged.
Bosschem Siemon & Alice Debacker
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 V
FOREWORD
We want to thank several people without whom we would not have been able to complete this
project so smoothly.
First of all, we would like to thank our supervisor, Prof Johan Albrecht for the time and advice he has
given us.
We also want to thank Jonas Verhaeghe for his availability and the time he spent answering our
numerous questions.
In addition, we thank CEG for all the information set at our disposal which helped us getting started
easily.
Lastly, we thank all the people who helped us find information, supported us all along and helped in
any way.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 VI
TABLE OF CONTENTS
PERMISSION ................................................................................................................................................ IV
FOREWORD .................................................................................................................................................. V
TABLE OF CONTENTS ................................................................................................................................... VI
LIST OF TABLES .......................................................................................................................................... VIII
LIST OF FIGURES ........................................................................................................................................... IX
ABBREVIATIONS ........................................................................................................................................... XI
1 INTRODUCTION ..................................................................................................................................... 1
2 HYBRID SOLAR POWER .......................................................................................................................... 3
2.1 HYBRID SOLAR POWER ................................................................................................................................ 3
2.1.1 Solar Power Technologies.................................................................................................................. 3
2.1.2 Conventional Thermal Power ............................................................................................................ 4
2.2 ISCC ........................................................................................................................................................ 7
2.3 CURRENT AND FUTURE PROJECTS ................................................................................................................... 8
2.4 ENERGY TRANSPORTATION NETWORK ........................................................................................................... 10
3 ECONOMIC ANALYSIS .......................................................................................................................... 11
3.1 INTRODUCTION ........................................................................................................................................ 11
3.2 REFERENCE PLANT ..................................................................................................................................... 12
3.3 PLANT SCALE UP ....................................................................................................................................... 14
3.4 TECHNOLOGY, COST AND BENEFIT ................................................................................................................ 15
3.4.1 Parabolic Trough ............................................................................................................................. 15
3.4.2 Central receiver systems (CRS) ........................................................................................................ 16
3.4.3 Investment costs and LEC ................................................................................................................ 17
3.4.4 Sensitivity on LEC ............................................................................................................................. 18
3.4.5 Conclusion ....................................................................................................................................... 19
3.5 THERMAL ENERGY STORAGE ....................................................................................................................... 20
3.5.1 Thermal Storage Technologies ........................................................................................................ 21
3.5.2 Impact on the costs of the power plant ........................................................................................... 24
3.6 EXTRA BURNER ........................................................................................................................................ 28
3.7 OPERATION AND MAINTENANCE .................................................................................................................. 29
3.8 FINANCIAL INCENTIVES, GRANTS .................................................................................................................. 31
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 VII
3.8.1 Feed‐in Tariffs .................................................................................................................................. 31
3.8.2 Other National incentives ................................................................................................................ 32
3.8.3 Other International Support Mechanisms ....................................................................................... 33
3.9 SITE SOLAR RESOURCES, DNI ...................................................................................................................... 35
3.10 NATURAL GAS AND ELECTRICITY PRICES ......................................................................................................... 37
4 CONCLUSION ....................................................................................................................................... 40
BIBLIOGRAPHY ............................................................................................................................................ 44
ANNEXES ..................................................................................................................................................... 47
ANNEX 1 : LIFE‐CYCLE ASSESSMENT OF GREENHOUSE GAS EMISSIONS [38] ........................................................................ 47
ANNEX 2 : INCENTIVE SYSTEMS BY COUNTRY IN EUROPE ................................................................................................ 48
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 VIII
LIST OF TABLES
Table 2‐1. List of planned hybrid solar plants [9] [17]............................................................................. 9
Table 3‐1. ISCC Reference plant properties .......................................................................................... 12
Table 3‐2. Investment costs of different ISCC technologies [18] .......................................................... 17
Table 3‐3. Investement costs of thermal storage for different solar technologies [18] ....................... 24
Table 3‐4. Operation and Maintenance costs of different ISCC Technologies and CC ......................... 29
Table 3‐5. Operation and Maintenance costs selected to calculate the LEC [1] ................................... 30
Table 3‐6. Feed‐in tariffs in Algeria [30] ................................................................................................ 32
Table 3‐7. Feed‐in laws in several countries [30] .................................................................................. 32
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 IX
LIST OF FIGURES
Figure 2‐1. Electric energy generation from solar power [2] .................................................................. 3
Figure 2‐2. Concentrated Solar Power, types of solar receivers [2] ........................................................ 4
Figure 2‐3. Combined Cycle Power Plant [4] ........................................................................................... 5
Figure 2‐4. Net efficiency of different technologies in maximum capacity factor [6] ............................ 5
Figure 2‐5. Integrated Solar Combined Cycle plant with PT [7] .............................................................. 7
Figure 3‐1. LEC and Investment costs of the ISCC reference plant ....................................................... 13
Figure 3‐2. Scale‐up effect : LEC vs Total capacity of the power plant ................................................. 14
Figure 3‐3. Scale‐up effect: Specific investment cost vs Total capacity of the power plant ................. 14
Figure 3‐4. Levelized Electricity Cost of different ISCC technology ....................................................... 17
Figure 3‐5. Investment costs of different ISCC technology ................................................................... 18
Figure 3‐6. Levelized Electricity Cost with reduction of the solar field ................................................. 19
Figure 3‐7. Solar Tower power plant using two‐tanks molten salt storage [20] ................................... 20
Figure 3‐8. Growth factor of the solar field with the hours of thermal storage in two different
locations [21] [18] ................................................................................................................................. 25
Figure 3‐9 CSP Investment Cost of 3h storage in Barstow and Seville compared with no storage. ..... 25
Figure 3‐10. Evolution of the LEC with the thermal storage time for two sites with different DNI ..... 26
Figure 3‐11. Evolution of the annual solar contribution with the thermal storage time for two sites
with different DNI .................................................................................................................................. 27
Figure 3‐12. Evolution of the CO2 emission with the thermal storage time for two sites with different
DNI ......................................................................................................................................................... 27
Figure 3‐13. Annual electric production and LEC of ISCC power plants with or without extra burner 28
Figure 3‐14. Comparison of the CO2 emissions of ISCC plants with or without extra burner and a CC
plant ...................................................................................................................................................... 28
Figure 3‐15. Direct Normal Irradiance map ........................................................................................... 35
Figure 3‐16. Levelized Electricity Cost of various DNI levels and different solar shares ....................... 36
Figure 3‐17. Carbon Dioxide Emissions for various DNI levels and different solar shares .................... 36
Figure 3‐18. Oil, coal and liquefied natural gas prices from1970 to 2007 ............................................ 37
Figure 3‐19. Gas prices for medium size industries in Europe and Spain [34] ...................................... 38
Figure 3‐20. Evolution of the LEC with the gas price for different ISCC Technologies and CC .............. 38
Figure 3‐21. Electricity prices in Spain from 1998 till 2008 [36] ........................................................... 39
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 X
Figure 4‐1 LEC vs CO2 emission for different evolutions of the solar share (green), thermal storage
(purple), DNI (dark blue), plant size (red) and extra burner (light blue) ............................................... 41
Figure 4‐2. EUA prices from January 2008 till May 2009 [37] ............................................................... 42
Figure 4‐3 LEC vs annual green energy production for different evolutions of the solar share (green),
thermal storage (purple), DNI (dark blue), plant size (red) and extra burner (light blue) .................... 43
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 XI
ABBREVIATIONS
CC Combined Cycle CLFR Compact Linear Fresnel Reflector CSP Concentrated Solar Power CRS Central Receiver System DNI Direct Normal Irradiance DSG Direct Steam Generation EUMENA Europe (EU), the Middle East (ME) and North Africa (NA) GEF Global Environment Facility GT Gas Turbine GW Gigawatt (109 watt) HRSG Heat Recovery Steam Generator HTF Heat Transfer Fluid HVAC High Voltage Alternative Current HVDC High Voltage Direct Current ISCC Integrated Solar Combined Cycle LEC Levelized Electricity Cost MENA Middle East and North American Countries MW Megawatt (106 watt) MWe Megawatt electric MWhe Megawatt hour electric MWhth Megawatt hour thermal PCM Phase Changing Materials PT Parabolic Trough RTIL Room Temperature Ionic Liquids SEGS Solar Energy Generating System ST Solar Tower TES Thermal Energy Storage
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 1
1 INTRODUCTION
The world’s resources are diminishing day by day. The worst predictions plan the depletion of main
resources like oil, natural gas and coal in the next 100 years. Besides, the climate changes due to
global warming are pushing energy producers to think of new possibilities.
Solar power is the most powerful natural resource on earth but we cannot take full advantage of it.
The first problem resides in turning this energy into electricity or heat usable in everyday life. The
second problem is linked to the fluctuating and unpredictable nature of solar power.
Actual solar plants are developed and solutions are thought of to reduce the issue of partial
production. Unfortunately these projects are not profitable and would never be brought to life
without the financial help of governments and environmentally concerned organizations.
One promising solution is the hybrid solar thermal power plant. Instead of producing solar power
only, the energy coming from the solar field is used to improve the efficiency and to lower the CO2
emissions of a common thermal power plant.
If solar power is maturating, ISCC is still young. In the literature, a few studies can be found on the
feasibility of a ISCC power plant. However, these studies are usually conveyed to determine the
viability of a certain project, in a defined place, with a defined technology…
This project aims to define the optimal configuration of hybrid solar plants.
The results presented in this master thesis are based on the work of Jonas Verhaeghe and Bram Van
Eeckhout, for Clean Energy Generation [1].
The first section describes what a hybrid solar plant is and how it works. It also describes the main
technologies that are used to produce solar‐based energy as well as how it can be combined with a
conventional thermal power plant. It follows the choice of Integrated Solar Combined Cycle.
The second section analyses the impact of the main parameters on the green production, plant costs
and CO2 emissions of the ISCC power plant. Among others, the type of solar technology, the use of
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 2
thermal energy storage, the different incentives and grants systems of several countries and the
importance of the site are studied.
Finally, optimal configurations are presented for the corresponding priorities and personal choices of
the investors.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 3
2 HYBRID SOLAR POWER
2.1 HYBRID SOLAR POWER
For ages, mankind has tried to tame the energy of the sun. Many different technologies have been
born, some efficient, others not.
To increase the efficiency of solar power and make it competitive, the concept of hybrid power plant
has been developed. By combining solar thermal energy with conventional thermal energy, a basic
electric load can be assured at all times while solar power can be used to reduce the consumption of
classic fuel and decrease greenhouse gas emissions.
2.1.1 SOLAR POWER TECHNOLOGIES
In the large‐scale production of electricity, the most developed technology is CSP, Concentrated Solar
Power. The sunlight is concentrated on a focal point by reflecting surfaces. Solar radiation is
concentrated and then converted into thermal energy. This thermal energy can be converted into
electricity by means of a thermodynamic cycle.
Solar power can be converted to electricity directly if the HTF is steam which drives a steam turbine.
To reach higher temperatures with liquid mediums, oil or high phase change temperature fluids can
be used as HTF. Then, a heat exchanger is needed to warm up the steam driving the turbine.
Figure 2‐1. Electric energy generation from solar power [2]
Defining
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Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 6
The integration of CSP technology with a combined cycle power plant is a very interesting hybrid
power plant configuration. This configuration is referred to as integrated solar combined cycle
systems (ISCCS).
The net efficiency of ISCC is higher than that of SEGS but also higher than a Combined Cycle plant
(see figure2‐4). Therefore in this project, the type of hybrid thermal solar power studied, is the
Integrated Solar Combined Cycle. The key question is how to design and optimize the integration of
the solar field and the power cycle.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 7
2.2 ISCC
Integrated solar combined cycle (ISCC) are modern combined cycle power plants with gas and steam
turbines and additional thermal input of energy from a solar field [7]. The plant concept was initially
proposed by Luz Solar International [8].
Figure 2‐5. Integrated Solar Combined Cycle plant with PT [7]
Solar thermal energy can be used in two different ways. The first use is presented in figure 2‐5. In this
schematic power plant, the heat of the HTF is transferred in the solar steam generator to produce
steam to drive the steam turbine. In case the steam cannot be warmed up enough, because of lack of
sunlight, the duct burner produces the additional heat by burning gas.
In other designs, the solar field produces an additional volume of steam, directly as HTF or through a
heat exchanger, to drive the steam turbine. This design requires the steam turbine to be oversized
and work at a partial load when the sun is not shining.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 8
2.3 CURRENT AND FUTURE PROJECTS
ISCC is a very young technology and the investments in these projects are still risky. However, a few
projects are already in construction phase and they will soon be finished. Six countries are now
constructing an ISCC plant: Algeria, Egypt, Iran, Italy, Morocco and the U.S. In Australia a Compact
Linear Fresnel Reflector field has already been finished and added to an old coal‐fired power plant [9]
[10] [11] [12].
One of the first ISCC plants to be built is Yazd Solar Thermal Power Plant, in Iran. Since 1997, the
government of Iran has been interested in the implementation of a 200.000–400.000m² parabolic
trough field into a 300MW natural‐gas‐fired combined cycle plant in the Luth desert in the area of
Yazd [3]. Later on they raised up the total capacity to 430MW with 67MW solar field plant [13]. To
finance the incremental cost of the solar field, Iran approached GEF with a request for a $50 million
grant. But as GEF was not in the position to hand out any grants, in 2005, Iran changed the plant
configuration and now intends to build a solar field equivalent to about 17MW. The total plant
capacity will be 467MW [3].
In Ain Beni Mathar, Morocco, an ISCC project of 472MW, supported by GEF is being built. The plant
includes a parabolic trough solar component of 20MW (180.000m2) with an expected annual net
production of 3.538 GWh per year. The solar output is estimated at 1,13% of the annual production
representing 40GWh per year [14]. According to the constructors (Abener), they started the works on
the 28th of March 2008 and plan to be finished in August 2010 [15].
Abener is currently building the second ISCC Power Plant in Hassi’Mel, Algeria [15]. The complex will
comprise a 130MW combined cycle, with a gas turbine power of the order of 80MW and a 75MW
steam turbine. A 25MW solar field, requiring a surface of around 180.000m2 of parabolic mirrors, will
be the source of non‐fossil energy. The investment will be nearly 140 million dollars and is the first
privately financed solar thermal plant in North Africa, based on the feed‐in law of Algeria [16]. The
construction of the ISCC is planned to finish in August 2010.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 9
In Egypt, there is a project in building phase with a total capacity of 140 MW. Also it has a large solar
contribution of 30MW and is supported by GEF with a $50 million grant. In Italy a a solar field of
30MW is being added to an existing power plant of 700MW. The U.S. is in the process of building an
ISCC plant in Victorville, CA. Three others are planned in California and Florida. In Mexico there is an
ISCC project approved by GEF in 2006 and in India a 150MW ISCC plant is being planned with a solar
contribution of 30MW. But this project is not yet approved by GEF.
Country Technology Capacity
(MWe) Solar Capacity (MWe)
Solar Share
DNI Phase Online date
Australia , Lake Lidde
Coal CLFR
2004,4 4,4 0,2% 2300‐2400
Finshed 2008
Iran, Yazd
ISCCS PT
467 17 3,6% 2500 Under construction
2010
Algeria, Hassi R’mel
ISCCS PT
150 25 16,7% 2300 Under Construction
2010
Morocco, Ain Beni Mathar
ISCCS PT
472 20 4,2% 2300 Under Construction
2010
Egypt, Kuraymat
ISCCS PT
140 40 28,6% 2400 Under Construction
2010
U.S., Victorville, CA
ISCCS PT
563 50 8,9% 2200‐2600
Under Construction
2010
U.S., Indiantown, FL
ISCCS PT
1125 75 6,7% ‐ ‐ 2010
Italy, Siracusa
ISCCS PT
730 30 4,1% 2100 Under construction
2010
U.S., Fresno County, CA
Biomass PT
187 107 57,2% ‐ ‐ 2011
U.S., Palmdale, CA
ISCCS PT
570 50 8,8% 2200‐2600
Planned 2013
Mexico, Sonora State
ISCCS PT
500 30 6,0% 2600 Approved by World Bank/GEF
‐
India , Mathania
ISCCS PT
150 30 20,0% 2250 ‐ ‐
Table 2‐1. List of planned hybrid solar plants [9] [17]
Table 2‐1 above shows that most of the projects contain a small solar share. This is because of the
high equipment cost of the solar field and the scanty support by incentives for ISCC projects. Only in
Morocco, Egypt and Mexico will the projects be supported by GEF. However several ISCC projects are
supported by private investments. This indicates that ISCC can be competitive without large grants.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 10
2.4 ENERGY TRANSPORTATION NETWORK
Many highly populated areas in the world don’t have the ability to produce competitive solar energy,
although there is a great potential for solar energy on this planet. By building a well functioning
electricity network over big distances, solar power can be transferred from thousands of kilometers.
With such a large electric infrastructure, all types of renewable energy sources can provide electricity
over huge distances.
Europe (which has little solar potential) and the MENA (high solar potential) have plans to build a
large electricity network which will interconnect the greatest power plants over the EUMENA. This
project fits into a major concept, DESERTEC. This concept describes the perspective of a sustainable
supply of electricity for Europe, the Middle East and North Africa up to the year 2050. According this
scenario, several GW of solar energy produced in the deserts of MENA can be transported towards
the less sunny regions in Europe. This electricity‐network won't be operative before 2020, but it will
be necessary for the redundancy and stability of the future power supply system.
The currently used technology (HVAC) is not sufficient to create such a large scale network without
having huge energy losses. Therefore a technology, called HVDC, can be used. These HVDC wires
have less electricity losses than the currently used AC‐grid (HVAC), particularly in the case of overseas
connections. Over smaller distances, AC‐grid can be used, which is more useful for small distances.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 11
3 ECONOMIC ANALYSIS
3.1 INTRODUCTION
The objective of this economic analysis is to assess the cost efficiency of ISCCS power plants, to
determine the economics of plants with different specifications and to compare it with the
conventional power generation system, combined cycle. The specifications that will be studied in this
analysis are the type of solar thermal technology, the number of storage hours, the use of an extra
burner, the level of DNI, the plant scale, gas prices …
For the comparative assessment, the Levelized Energy Cost (LEC) is used as the figures of merit. The
LEC is the present value of the life‐cycle costs converted into a stream of equal yearly payments. As
an advantage, the LEC figure allows an economic evaluation of different power generating
technologies with varying capacities, full load hours, lifetime, etc [7].
The LEC values for power generation systems are computed by the following methodology:
(€/MWhe)
p
Cost no fuel expenses € Total annual ca ital Cost €
Total annual Operational & Maintenance Total annual fuel expenses € Annual electricity production MWhe
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 12
3.2 REFERENCE PLANT
As reference plant for this study, a 265 MW ISCC plant is chosen with a solar contribution of 36MW.
The plant has 3 solar towers of 12 MWe peak capacity each. The Heat Transfer fluid is steam. Values
for O&M cost, solar equipment cost and efficiencies are used from CEG [1] and ECOSTAR [18].
Item Parameter Units Solar Technology Solar Tower (CRS) Fuel type Natural gas Nominal power 265 MWe Gas turbine power 146,7 MWe Steam turbine power 109,3 MWe Solar contribution 36 (3 x 12) MWe Plant Capacity factor ISCC 63 % Efficiency CC 52 % DNIannual 2100 kWh/m²/yDNIpeak 850 W/m² Thermal storage 0 hours Solar‐to‐thermal efficiency (%) 50 % Extra burner no Depreciation time 20 years Mortgage repayment time 20 years Debt capital/total capital 80 % Debt capital interest rate 6 % Capital cost venture capital 12 % Inflation 2 % Taxes 0 % Fuel price Gas 20 €/MWhth Investment CSP 57,42 € mio Investment Power block (CC) 94,03 € mio Investment Civil and structural work 4,51 € mio Investment Indirect costs 43,00 € mio Investment ISCC (total) 198,97 € mio Annual production 1411,18 GWh/yAnnual solar production 59,2 GWh/yEmissions 335,8 kg/MWheLEC (min)2 58,3 €/MWheLEC (max) 73,1 €/MWhe
Table 3‐1. ISCC Reference plant properties
2 In further calculations, the minimum LEC is always shown in graphs and texts.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 13
The biggest part of the investment cost is attributed to the power block which contains the gas and
steam turbine. The second part goes to the solar contribution (CSP), which contains costs for the
solar field, tower infrastructure, receivers,… The segment ‘indirect costs’ includes engineering,
contingencies and service during implementation.
21%
15%64%
LEC
Total Capital Cost
Total Operational Cost
Fuel Expenses
47%
2%29%
22%Investment costPower block
Civil and structural work
CSP
Indirect costs
Figure 3‐1. LEC and Investment costs of the ISCC reference plant
The Levelized Electricity Cost of the reference plant consists of 15% operational and maintenance
cost, 21% capital cost and 64% fuel expenses. Regarding the LEC, the fuel expenses are very high and
the capital cost rather low, because of the small solar share of the reference plant.
The LEC (min) is the cost of the ISCC plant in the first year of operation. The LEC (max) is the cost of
plant in the 20th year of operation. The LEC (max) is much higher, due to increasing operational costs
by inflation and increasing gas prices. An increase of the gas prices by 1,34% per year has been taken
into account for calculating the LEC (max).
The solar output is estimated at 4,2% of the annual production representing 59,2GWh green
electricity per year. The annual avoided CO2 emission of the reference plant is 20.611 tonne.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 14
3.3 PLANT SCALE UP
One of the primary opportunities to reduce costs is to increase the size of the power plant. In general,
power plant equipment costs decrease with the size of the plant. Looking at the specific investment
cost of several Combined Cycle plants, the costs drop significantly with the net plant output. This is
also the case for the ISCCS plants where more than 50% of the equipment cost of the plant (14%
solar share) goes to the Combined Cycle installation (power block). ‐Huge cost reductions would
ensue if the ISCC plant capacity doubled (figures 3‐2 and 3‐3).
A big plant however, implies great investment costs. It can be difficult to find enough financial
resources, especially for the ISCC technology which is in a premature phase.
Figure 3‐2. Scale‐up effect : LEC vs Total capacity of the power plant
58,3 56,6 55,9 55,5 55,353,554,054,555,055,556,056,557,057,558,058,559,0
256 512 768 1024 1280
Total capacitiy of plant (MW)
LEC (€/MWhe)
Figure 3‐3. Scale‐up effect: Specific investment cost vs Total capacity of the power plant
0
0,1
0,2
0,3
0,4
0,5
0,6
0,7
256 512 768 1024 1280
Total capacitiy of plant (MW)
Specific investment cost (€/W)
CIVIL STR WORK
CSP
POWER BLOCK
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 15
3.4 TECHNOLOGY, COST AND BENEFIT
To capture solar energy, there are several technologies existing today. However it cannot be
predicted which of the technologies may finally achieve what market share or which options may
eventually drop. For ISCC two interesting options have been developed: Parabolic Trough (PT) and
Solar Tower (CRS) [18].
3.4.1 PARABOLIC TROUGH
Today all ISCC projects are planned using the Parabolic Trough technology. One of the possible
reasons is because the PT technology is more commercially developed. A Trough is constructed as a
long parabolic mirror (usually coated silver or polished aluminum) with a tube running its length at
the focal point. Sunlight is reflected by the mirror and concentrated on the tube. The trough is
usually aligned on a north‐south axis, and rotated to track the sun as it moves across the sky each
day. Parabolic trough technology can only be deployed in very flat area with slope below 3%.
The collector as the dominant cost fraction of the whole plant is estimated (by ECOSTAR [18])
between 206‐190 €/ f , depending on the type of heat transfer fluid (HTF) running through
the tube. In spite of the high maturity, PT still has a potential for slight performance improvement
and significant cost reduction. ECOSTAR [18] predicts a cost drop of 10% due to technological
improvements. Sargent & Llundy [19] predicts a drop of the solar field costs around 20% between
2004 and 2020.
The parabolic trough can use two types of heat transfer fluids, Thermal Oil or DSG (Direct Steam
Generation). Trough systems using thermal oil can be considered as the most mature CSP technology.
Major limitations of today’s trough systems are caused by synthetic thermal oil, which is costly, may
raise environmental concerns and is limited in its application temperature. DSG or steam collectors
do not face the limits of the thermal oil. Also, the direct superheating of the steam increases the
efficiency. This saves costs, reduces heat losses, pumping parasitic and eliminates the temperature
limit.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 16
3.4.2 CENTRAL RECEIVER SYSTEMS (CRS)
Central receiver systems, or solar tower, use a circular array of large, individually tracking mirrors
(heliostats) to concentrate sunlight onto a central receiver mounted on top of a tower. Heat is then
transferred for power generation through a choice of transfer media. There are three types of
transfer media: molten salt3, steam and atmospheric air [18].
Today there are no planned ISCCS with a Solar Tower. The CRS technology needs 2 axis tracking,
instead of 1 axis tracking like PT. In the past, 2 axis tracking was very expensive and hard to produce.
Therefore PT was more commercially developed and is nowadays cheaper. Nevertheless the CRS has
interesting prospects. ECOSTAR [18] predicts a 20% drop of solar field cost, due to very large
heliostats or ganged heliostat concepts. Sargent & Llundy [19] estimate the cost reduction even
higher, up to a maximum of 70%.
Molten salt
With respect to Central Receiver Systems, molten salt technology is the most developed. This is
mainly attributed to very attractive costs for the thermal energy storage that benefits from a
temperature rise in the three times greater than in the parabolic trough system. Additionally a higher
annual capacity factor is possible for CRS due the smaller difference between summer and winter
performance compared to parabolic trough systems [18].
Saturated steam
Steam receivers that have been built in several demonstration plants showed operational difficulties
in the past, mainly attributed to the superheating of steam. This means it doesn’t benefit from the
high temperatures of the molten salt, which leads to a more expensive storage option. Saturated
steam is considered as a low risk approach. Design concepts are based on experience in steam
generator technology. This leads to relatively low investment costs for the receiver and combined
with the low temperature, to a high receiver performance [18].
Atmospheric air
The benefit of this technology is mainly regarded for its simple design concept based on atmospheric
air as heat transfer medium compared to synthetic oil or molten salt systems. The CRS with
3 Molten Salt is a nitrate mixture mainly of Sodium and Potassium. It has a relatively high melting point between 120 and 220 °C [41].
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 17
atmospheric air receiver technology may benefit from its simple design that promises quick start‐ups.
However, this technology is still in R&D phase and it is only being tested in pilot plants. Further
improvements are necessary to achieve cost figures similar to the other technologies presented here
[18].
Technology PT Oil PT DSG CRS M.Salt CRS Steam CRS AirSolar field (€/m²) 206 190 150 150 150 Receiver & piping (€/kWth) 0 0 125 110 115 Civil works + tower (€/tower) 2% 4 2% 4 1000000 1000000 1000000Thermal storage (€/kWhth) 31 30 14 100 60 Indirect costs 20% 20% 20% 20% 20% Land‐use factor 30% 30% 35% 35% 35% Solar to thermal eff. 46,2% 48,4% 52% 50% 47,7% HTF Temperature5 (°C) 371 411 565 260 680
Table 3‐2. Investment costs of different ISCC technologies [18]
3.4.3 INVESTMENT COSTS AND LEC
The trough option with steam has the lowest LEC (57,5 €/MWhe). The differences in LEC between the
technologies are not large, partially due to the modest solar fraction. The larger the solar fraction,
the larger the differences will be. The slight differences in LEC prove that the 5 technologies are very
competitive nowadays.
Figure 3‐4. Levelized Electricity Cost of different ISCC technology
58,3 57,5 58,3 58,3 58,949,0
51,0
53,0
55,0
57,0
59,0
61,0
ISSC PT Oil ISCC PT DSGISSC CRS M.SALT
ISSC CRS STEAM
ISCC CRS AIR
Levelized Electricity Cost (€/MWhe)
LEC
CC
4 For parabolic trough, 2% of the investment cost is charged for the civil works. 5 Temperature at field exit [18]
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 18
3.4.4 SENSITIVITY ON LEC
We can assume that the cost of the solar field and heliostats will decrease over time because of scale
effects and technological improvements. The cost fraction of the solar field for a Trough field is a lot
higher than the CRS option. This leads to a more sensitive LEC when the solar field or heliostat field
cost decreases. The second biggest cost of the CRS technology is the receiver (30‐40% of the CSP
cost).
Figure 3‐5. Investment costs of different ISCC technology
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
ISSC PT Oil ISCC PT DSGISSC CRS M.SALT
ISSC CRS STEAM
ISCC CRS AIR
Investment Cost of CSP
Land
Civil works + tower
Receiver & piping
Solar field
In the long run cost drops of more than 70% are been predicted by Sergeant & Llundy for the CRS
technology. The trough technology has less reduction prospects (20%) [19]. The figure 3‐6 below
indicates the interesting future for CRS, in particular for Molten Salt and DSG. CRS with Saturated air
is more expensive now but will benefit in the long run from the same cost reductions as DSG.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 19
Figure 3‐6. Levelized Electricity Cost with reduction of the solar field
54
55
56
57
58
59
60
0% 10% 20% 30% 40% 50% 60%
Reduction solar field/heliostat field
Levelized Electricity Cost (€/MWhe)
Parabolic trough Oil Parabolic trough DSG
CRS M.Salt CRS Steam
CRS Steam (20% reduction reciever) CRS Steam (50% reduction reciever)
CRS Air
3.4.5 CONCLUSION
If we compare the LEC now for an ISCC with Parabolic Trough and an ISCC with Solar Tower, we can
see there are slight differences. The key difference has to be sought in the potential cost reduction of
the solar field, due to scale effects and technological improvements. Also the low prices of thermal
storage for CRS with Molten Salt can result in very low costs. According to the predictions of Sargent
& Llundy, the CRS technology with DSG will become the cheapest solution.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 20
3.5 THERMAL ENERGY STORAGE
The main problem associated with solar power is its irregularity. The sun only shines for a limited
period of the day and can be obscured by clouds or others things. Therefore, solar power has mainly
been used to provide peak power.
The use of thermal storage can lengthen the working hours of a solar plant. This allows furnishing
base load instead of peak and reduces the inconveniences linked to the daily starting of the turbine.
There are two kinds of thermal storage. Short term thermal storage (a few minutes to one hour) can
prevent inefficiency of the power plant in case clouds hide the sun for some time. Long term storage
(up to 15 hours) is used to assure constant production of electricity even during night time.
A part of the heat generated by the solar field goes into the heat recovery steam generator while the
rest is stored for later use. Some systems use the heat transfer fluid to store heat, others make use of
a heat exchanger between two different fluids.
Figure 3‐7. Solar Tower power plant using two‐tanks molten salt storage [20]
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 21
3.5.1 THERMAL STORAGE TECHNOLOGIES
Thermal storage media can be solid, liquid or gaseous. The most common types of storage are [18]
• Molten salt storage and Room Temperature Ionic Liquids (RTILs) • Concrete Storage • Phase Changing Materials (PCM) • Storage using solid materials • Storage for saturated water/steam
Molten salt storage and RTILs
A state of the art storage type is the 2‐tank molten salt storage tested in the Solar Two
demonstration project in combination with a Central Receiver Solar Power Plant using solar salt as
heat transfer fluid.
This 2‐tank molten salt storage was also proposed for parabolic trough solar power plants with
synthetic oil as heat transfer fluid. Therefore it is necessary to have a heat exchanger for the heat
transfer from oil to salt. The heat exchanger between molten salt and oil leads to security issues from
possible chemical reactions and explosions in case of leaks [21].
Pacheco et al. [22] published experimental results and theoretical investigations on the usage of a
thermocline molten salt storage with a filler material in a parabolic trough power plant. The general
idea is to reduce costs through the replacement of expensive salt by cheaper materials. The authors
are nominating a cost reduction of about one third compared to a 2‐tank molten salt storage.
Therefore the 1‐tank thermocline storage for parabolic trough plants, the selection of a durable filler
material and the optimization of charging and discharging methods and devices are the main items.
The development risk for them is low. And in the short term the technology can be implemented.
The usage of new storage materials, so called Room Temperature Ionic Liquids (RTILs), may
overcome this general drawback since these materials are liquid even at low temperatures. RTILs are
organic salts with negligible vapour pressure in the relevant temperature range and a melting
temperature below 25°C [23]. Room temperature ionic liquids are quite new materials and it is rather
uncertain, whether they are stable up to the temperature level required for CSP and also whether
they may be produced at reasonable cost [24].
The two‐tanks technology is already well used. The time required for full development and
commercial implementation is estimated at less than 5 years. The 1‐tank thermocline meanwhile will
need 5 to 10 years to be commercially interesting. As for the RTILs, they will still need more than 10
years [18].
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 22
Concrete storage
The concept of using concrete or castable ceramics to store sensible heat in parabolic trough power
plants with synthetic oil as heat transfer fluid (HTF) has been investigated.
Since the steel tube register inside the storage material are rather expensive, a tubeless storage
could lead to lower specific costs, but there are still some investigations needed for this design. The
costs for the tubing are about 45‐55% of the total storage costs.
Advanced charging/discharging modes need additional investment in tubes and valves, but they may
considerably increase the storage capacity for a given size and material. The basic idea of modular
storage charging and discharging is to increase storage capacity by raising the temperature variation
between both operating modes. Computer simulations from Tamme et al. [25] showed that the
capacity of a given storage size could be increased by about 200% compared to the base case
operation.
The implementation of a concrete storage system can be realized within less than 5 years. The
uncertainties and risks are for both cases (with or without tubes) in a medium range. And in addition
the charging/discharging modes are promising [18].
Storage with Phase Change Materials (PCM)
Phase change materials (PCM) are potential candidates for latent heat storage, which is of particular
importance for systems which have to deal with large fractions of latent heat, such as direct steam
generating systems. PCM storages are not restricted to the solid‐liquid transition, they could also use
solid‐solid or liquid‐vapour transition, but actually the solid‐liquid transition has some advantages
compared to the other phase transitions. At present, two principle measures are being investigated:
• encapsulation of small amounts of PCM • embedding of PCM in a matrix made of another solid material with high heat conduction.
The first measure is based on the reduction of distances inside the PCM and the second one uses the
enhancement of heat conduction by other materials.
Storages based on PCM are in an early stage of development and many of the proposed systems are
only theoretical or laboratory scale experimental work. Therefore cost estimation is difficult, but the
cost target is to stay below 20 €/kWh based on the thermal capacity. Even the uncertainties and risks
of the PCM storage technology are in a medium range. The technology time required for full
development and commercial implementation is more than 10years. PMC storage can be used for PT
as well as ST power plants.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 23
Storage for air receivers using solid materials
Storage types using solid material for sensible heat are normally used together with volumetric
atmospheric or pressurized air systems. The heat has to be transferred to another medium, which
may be any kind of solid with high density and heat capacity. Other parameters for a solid material
storage are size and shape of the solids which may be chosen in order to minimize pressure loss (high
pressure loss cause high parasitic).
Beside fixed solid material as storage medium a new concept using silica sand as intermediate heat
transfer medium was developed by DLR to avoid the disadvantages of storage vessels filed with fixed
solid material in CSR with open volumetric air technology.
The fixed solid storage medium technology is realizable within a shorter term (less than 5 years) than
the moving solid storage medium technology (5 to 10 years) also the uncertainties and risks are in a
medium range for solid medium and in a high range for the moving storage material system.
Another innovation is to develop for pressurized closed air receivers a storage container that has to
be pressure resistant up to about 16–20 bar depending on the gas turbine pressure ratio. The
receiver and the solar field for such a system would be able to deliver thermal power in excess of the
power needed by the gas turbine during high insolation periods. This excess power is utilized to
charge the thermal storage using a second air cycle driven by an additional blower. In the discharging
mode, during non sunshine hours, the receiver is bypassed and the flow direction through the
storage is reversed. In addition it would be possible to split up the compressor air flow during low
insolation periods, in order to use thermal energy from the receiver and from the storage. For this
case the time for development and implementation is 10 year and the risks and uncertainties are in a
medium range.
Storage for saturated water/steam
In principle the steam drum, which is a common part in many steam generators, is a certain kind of
storage because it contains an amount of pressurized boiling water. Steam could be produced from
this component solely by lowering the pressure. This storage type has been built several times as
process heat storage in industries thus the time required for full development and commercial
implementation is rather low. The main problem is the size of the steam vessel for larger storage
capacity and the degradation of steam quality during discharge.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 24
3.5.2 IMPACT ON THE COSTS OF THE POWER PLANT
The investment costs for thermal storage that can be found in ECOSTAR [18] show that the cheaper
technology with the longer storage possibilities is the 2‐tank molten salt (Table 3‐3). It is more
profitable to use molten salt also as heat transfer fluid. It would reduce the losses due to the heat
exchanger between the HTF and the storage medium. Besides, a molten salt cycle can reach higher
temperatures than steam cycles.
Plant Technology‐HTF
Plant Capacity
Thermal Storage Technology
Storage Capacity
Thermal Capacity of the Storage
Spec. Investment Cost for Storage
Investment Storage (% of total investment)
PT‐thermal oil 50MW 2‐tank molten 3h 434.66MWh 31€/kWhth 7.64%
CSR‐molten salt 17MW 2‐tank molten 3h 153.80MWh 14€/kWhth 3.42% CSR‐molten salt 50MW 2‐tank molten 3h 461.41MWh 13€/kWhth 3.38% CSR‐saturated steam
11MW Water/steam 50min 15MWh 100€/kWhth 4.03%
CSR‐atmospheric air
10MW Ceramic thermocline
3h 94MWh 60€/kWhth 12.88%
Table 3‐3. Investement costs of thermal storage for different solar technologies [18]
The 17MW Solar Tres will be the first commercial molten‐salt central receiver plant in the world.
With a 15h molten‐salt storage system it will be able to furnish electricity almost constantly.
One of the other costs associated with thermal storage is the extra solar field needed to secure the
same peak production while storing heat for later use. The following figure (3‐8) compares the
growth factor of the solar field in two different locations. The DNI influences greatly the need in extra
solar field. For a plant in Barstow (DNI 2700) the solar field has to be doubled up to implement a 15h
storage (figure 3‐8). For the plant in Seville (DNI 2000‐2100) the solar field has to be tripled to add a
thermal storage of 15 hours6.
6 The growth factor for Seville is an estimation, based on data of Barstow from the document “Two‐tank molten salt storage for parabolic trough solar power plants” [21].
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 25
Figure 3‐8. Growth factor of the solar field with the hours of thermal storage in two different locations [21] [18]
0,00
0,50
1,00
1,50
2,00
2,50
3,00
3,50
0 1 3 6 9 12 15
Storage size (h)
Growth factor of the solar field
Barstow (DNI=2700)
Seville (DNI=2014)
Calculations of the impact of thermal storage on the cost of an ISCC power plant are based on two
solar tower plants using molten salt as heat transfer fluid [18]. The two sites investigated are Barstow,
in the Mojave Desert, California where the plant Solar Two [21] was built, and Seville, Spain where
Solar Tres is planned to be built.
Figure 3‐9 CSP Investment Cost of 3h storage in Barstow and Seville compared with no storage.
0 20 40 60 80
3h Storage (Seville, M.Salt)
3h Storage (Barstow, M.Salt)
0h Storage (Seville, DSG)
Millions
CSP Investment Cost (€)Civil Works Solar field Extra solar field Land Reciever & Piping Storage
As shown in figure 3‐9, adding a storage of 3h implies increasing investment costs for the CSP
installation. The biggest rise in cost of the thermal storage is the extra solar field. This cost is much
higher for Seville due to the higher growth factor. The second main extra cost is the equipment cost
for storage. The receiver and the land costs also increase.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 26
Figure 3‐10 shows that a longer storage implies a higher LEC. This is mainly due to the increasing size
of the solar field and the equipment cost of thermal storage. The lower the DNI, the higher the solar
field growth and thus the higher the LEC.
Figure 3‐10. Evolution of the LEC with the thermal storage time for two sites with different DNI
52
54
56
58
60
62
64
66
68
70
72
0 1 3 6 9 12 15
Hours storage (h)
LEC (€/MWhe)
DNI 2000 (Seville) DNI 2700 (Barstow)
The figures 3‐11 and 3‐12 show that the solar contribution and the carbon dioxide emission evolve in
desired direction as thermal storage increases. For high storage capacity (6h or more), the plant with
the smallest DNI gives better results. This can be explained by the overrated growth factor of the
solar field of Seville.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 27
Figure 3‐11. Evolution of the annual solar contribution with the thermal storage time for two sites with different DNI
0%
2%
4%
6%
8%
10%
12%
0 1 3 6 9 12 15
Hours storage (h)
Annual solar contributionDNI 2000 (Seville) DNI 2700 (Barstow)
Figure 3‐12. Evolution of the CO2 emission with the thermal storage time for two sites with different DNI
295300305310315320325330335340
0 1 3 6 9 12 15
Hours storage (h)
Carbon dioxide emissions (kg/MWhe)
DNI 2000 (Seville) DNI 2700 (Barstow)
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 28
3.6 EXTRA BURNER
To increase the efficiency of the steam cycle of a common combined cycle an extra burner is usually
added to super heat the steam already heated by the exhaust gases from the gas turbine. As these
exhaust gases still contain a sufficient level of oxygen, the added fuel can burn.
The same system can be installed in ISCC plants. However, the goal of ISCC technology being to
reduce non‐renewable resources consumption and lowering greenhouse gases emissions, we can
question the merits of an extra burner.
Figure 3‐13. Annual electric production and LEC of ISCC power plants with or without extra burner
1411 15841300
1350
1400
1450
1500
1550
1600
NO EXTRA BURNER WITH EXTRA BURNER
Anual production (GWhe/y)
58,3 59,457,5
58,0
58,5
59,0
59,5
NO EXTRA BURNER WITH EXTRA BURNER
Levelised Electricity Cost (€/MWhe)
Figure 3‐14. Comparison of the CO2 emissions of ISCC plants with or without extra burner and a CC plant
335,8 347,2 348,2325,0
330,0
335,0
340,0
345,0
350,0
NO EXTRA BURNER WITH EXTRA BURNER
CC
Carbon dioxide emissions (kg/MWhe)
Figure 3‐13 shows an increased annual production for the plant with extra burner, as anticipated.
Also the LEC is slightly higher because of extra expenses of fuel for the duct burner. The CO2 emission
per MWhe on the other side is almost the same as emitted by a combined cycle (figure 3‐14).
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 29
3.7 OPERATION AND MAINTENANCE
The operation and maintenance (O&M) of a parabolic trough power plant is very similar to
conventional steam power plants that cycle on a daily basis [6].
Parabolic trough power plants typically require the same staffing and labour skills to operate and
maintain them 24‐hours per day. However, they require additional O&M requirements to maintain
the solar fields.
Initial plants required a substantial number of mechanics, welders, and electricians to maintain
immature solar technology. Modern parabolic trough solar technology is much more robust and
requires minimal preventive or corrective maintenance. The one exception is mirror washing. The
high‐pressure demineralised water system (called Mr. Twister) has sprayers that spin as they move
down when washing the mirrors.
Experience has shown that solar field mirrors must be washed frequently during the summer. But the
increase in solar output pays for the cost of labour and water. Current power plants may wash
mirrors weekly during the peak solar times of the year. It's usually only necessary every few months
during the winter.
The reduction of O&M cost is primarily a result of the increase in annual plant capacity factor [19].
The plant capacity increases as a result of the increase in thermal storage. However, increasing the
size (MWe) and utilization (capacity factor) of the power plant incurs very little increase in O&M
expenses ($/year). This is because the quantity and complexity of the equipment remain constant
and staffing remains fairly constant.
The following table gives a comparison of O&M costs for a parabolic trough ISCC, a solar tower ISCC
and a combined cycle plant. As expected, the fixed O&M costs are much lower for a CC plant than for
solar technology while the variable costs are higher [26].
Unit HTF‐trough Air‐Tower Reference CC Fixed O&M cost $/kW/a 15.5 14.3 7.2 Variable O&M cost ¢/kWh 0.166 0.165 0.204 Total O&M cost ¢/kWh 0.398 0.379 0.313
Table 3‐4. Operation and Maintenance costs of different ISCC Technologies and CC
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 30
For the calculation of the LEC, the following O&M costs were selected.
Solar: O&M costs + contingencies Fixed O&M: Equipment costs (% of inv.) 3 % Variable O&M: water use 1,3 €/MWhe Variable O&M: other 0,5 €/MWhe Unforeseen Cost (% of Inv) 2 % Other Cost (% of Inv) 2 % CC: O&M costs + contingencies Fixed O&M: Equipment costs (% of inv.) 2 % Variable O&M: other 1,97 €/MWhe Unforeseen Cost (% of Inv) 2 % Other Cost (% of Inv) 2 %
Table 3‐5. Operation and Maintenance costs selected to calculate the LEC [1]
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 31
3.8 FINANCIAL INCENTIVES, GRANTS
Nowadays, the costs of electricity production from solar energy are still too high for the technology
to be attractive on the market. Most countries have to decrease greatly their greenhouse gases
emissions. Therefore, they develop ways to encourage firms to invest in green and renewable energy
[3] [27] [28].
3.8.1 FEED‐IN TARIFFS
The feed‐in law is the most common policy for electricity renewables [27]. It has been developed in
several countries such as Spain, the US, Denmark or Germany and has given promising results. The
PS10 plant, promoted by the company Abengoa, will benefit from the solar premium of € 180/MWh
that is supplied by Spanish Government to solar thermal installations producing electricity [29].
Feed‐in tariffs vary from country to country. They sometimes have a maximum capacity threshold
and are usually related to the cost of generation. The tariffs generally decline over time but last for
the typical lifetime of the plants.
Some policies provide a fixed tariff (Germany) while others provide fixed premiums added to market
or cost‐related tariffs (or both, in Spain). The reduction of risk surcharges on capital investments by
feed‐in laws reduces the cost of market introduction because in the case of renewables, the capital
cost is the main component of the generation cost.
The new Spanish Feed‐In Law for CSP [30]
• Cost covering with 0.27€/kWh • Bankable with 25 year guarantee • Annual adaptation to inflation • 12‐15% natural gas back up allowed to grant dispatchability and firm capacity • After implementation of first 500MW tariff will be revised for subsequent plants to achieve
cost reduction
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 32
Algeria passed a feed‐in law in 2004 including solar thermal power for both hybrid solar‐gas
operations in steam cycle as well as integrated solar, gas‐combined cycle plants. For electricity
produced by solar‐gas systems, if the solar share is 25%, the premium amounts to 200% of the
market electricity price per kWh.
Solar share (% of primary energy produced)
Premium (% of market electricity price per kWh)
25% 200%20‐25% 180%
15‐20% 160%10‐15% 140%
5‐10% 100%0‐5% 0
Table 3‐6. Feed‐in tariffs in Algeria [30]
Some countries have feed‐in laws to finance exclusively solar only projects while other support
hybrid projects [30]. In most cases, when the solar share is small, hybrid solar projects are not
supported by feed‐in laws.
Country Capacity Tariff Duration (year)
Inflation ajustement
Restricions Hybrid
Algeria ISCC 100‐200% Lifetime ‐ ‐ yesFrance max 12MW 0.30€/kWh 20+ no max 12MW,
max 1500h/a no
Germany 0.46€/kWh Lifetime no ‐ no Greece up to 5MW
over 5MW 0.23‐0.25€/kWh0.25‐0.27€/kWh
10+1010+10
nono
‐ yesyes
Israel up to 20Wover 20MW
0.20$/kWh0.16$/kWh
20+1020+10
yesyes
‐ max 30%max 30%
Portugal up to 10MW over 10MW
0.21€/kWh0.16€/kWh
1515
nono
‐ no no
Spain up to 50MW 0.27€/kWh 25+ yes max 50MW max 15%Table 3‐7. Feed‐in laws in several countries [30]
3.8.2 OTHER NATIONAL INCENTIVES
Renewable Portfolio Standards
Sweden’s or Poland’s Renewable Portfolio Standards (RPS) require consumers or electricity suppliers
to purchase a given annual percentage of renewable shares through electricity purchases or
renewable certificates purchase.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 33
Renewable Energy Funds
Some countries have established renewable energy funds used to directly finance investments,
provide low‐interest loans or facilitate markets in other ways. The largest funds of this type are the
“public benefit funds” in 4 states of the USA. These funds, applied to energy efficiency as well, are
commonly collected from a surcharge on electricity sales.
Net Metering
Net metering has been instrumental in facilitating grid‐connected solar PV markets in the US, Canada
and Japan.
Competitive Bidding
Policies for competitive bidding of specified quantities of renewable generation, originally used in the
United Kingdom now exists in at least 7 countries: Canada, China, France, India, Ireland, Poland, and
the United States.
Renewable Energy Certificates
Tradable renewable certificates are typically used in conjunction with voluntary green power
purchases or obligations under renewable portfolio standards. Many regulatory measures can be
steps towards future renewable energy markets, particularly in developing countries (Mexico and
Turkey for example). 18 European countries are member of a renewable energy certificate system.
Green Power Purchasing
Green power consumers are supported by tax exemption on green energy purchase in Finland,
Germany, Switzerland, the Netherlands and the United Kingdom.
3.8.3 OTHER INTERNATIONAL SUPPORT MECHANISMS
There are many other forms of policy support for renewable power generation including direct
capital investment subsidies, rebates, tax incentives, credits, direct production payments…
Several international funds have also been raised to enhance the renewable share in the energy
consumption. The Global Environment Facility (GEF) supports technological development and aims to
increase the market share of low greenhouse gas‐emitting technologies that are not yet commercial
but promise to be so in the future. 4 CSP projects entered the GEF CSP portfolio with a grant volume
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 34
of $ 194.2 million, managed by the World Bank [31]. Also 3 ISCC projects are being supported by the
GEF.
The German KfW bank supports several projects with soft loans like a 140MWe ISCC in Rajasthan,
India [29] [32].
The European Union department of Energy and Transportation has decided to allocate funds to
renewable energy production projects. The project PS10 for example is worth some € 16.7 million,
with an EU contribution of € 5 million. The AndaSol project is worth a total € 14.3 million, with EU
backing of € 5 million [29].
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 35
3.9 SITE SOLAR RESOURCES, DNI
The location of the plant has a large impact on a solar project economics. The amount of solar energy
shining on each location is different. The annual energy that can be captured in 1m² is expressed by
the DNI (KWh/m²/y) or Direct Normal Irradiance. In very sunny regions of southern Europe (e.g. Spain)
the DNI can reach values up to 2100KWh/m²/yr. Outside Europe, for example Africa, South America,
Central America, parts of Asia, Middle East and Australia, the DNI can reach up to 2800.
Figure 3‐15. Direct Normal Irradiance map
If the DNI of the reference plant increases, the yearly production of solar energy changes significantly,
while the specific investment cost of the solar field stays the same (figure 3‐16). This means that
more production leads to less cost per kWh produced electricity. The LEC sensitivity of the ISCC
increases if the solar share of an ISCC rises. Thus, it is not recommended to develop ISCC plants with
high Solar shares in low DNI areas. ISCC plants with small solar shares are less sensitive for DNI
variation.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 36
Figure 3‐16. Levelized Electricity Cost of various DNI levels and different solar shares
45
50
55
60
65
70
75
1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600
DNI (kWh/m²/y)
Levelized Electricity Cost (€/MWhe)
32,9%
24,7%
17,9%
9,8%
CC
Regarding the corresponding CO2 emission (figure 3‐17), we see a significant decrease of CO2
emission per MWh if the DNI rises. The larger the solar share, the more important the DNI of the
plant will be to reduce costs en CO2 production.
Figure 3‐17. Carbon Dioxide Emissions for various DNI levels and different solar shares
270
280
290
300
310
320
330
340
350
360
1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600
DNI (kWh/m²/y)
Carbon dioxide emissions (kg/MWhe)
32,9%
24,7%
17,9%
9,8%
CC
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 37
3.10 NATURAL GAS AND ELECTRICITY PRICES
The world’s natural resources are being depleted, and so is natural gas. The prices of gas, oil and coal
will increase with time. The operational cost of CC en ISCC will increase, while costs of green
technologies like wind, hydro and solar will drop because of scale effects, competition and
technological improvements. New energy generating technologies’ LEC’s are less sensitive to the gas,
oil and coal prices.
Figure 3‐18. Oil, coal and liquefied natural gas prices from1970 to 20077
The natural gas prices in Europe for industrial users doubled over the last 10 years. As the market for
gas continues to globalize and gas and coal are increasingly used to produce transport fuel and
petrochemicals, it is reasonable to expect global gas prices to converge with oil prices [33].
As base cost for the natural gas, 20 €/MWh is chosen for the reference plant. However, the cost of
natural gas for medium size industries is nowadays much higher (figure 3‐19). But the prices for
larger industries and certainly for electricity producers are 20 to 30 %8 lower than the medium size
industries.
7 Nominal prices converted to SDRs and deflated by the G7 CPI. Indexed to 1995. Prices are as at January for 1970–2007 and as at April for 2008. Table compiled by the Centre for International Economics based on IMF IFS Statistics, OECD Main Economic Indicators, Financial Times, and CIE estimates [39]. 8 Source:Eurostat, gas prices for large industries and medium industries, without taxes [34] [40].
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 38
Figure 3‐19. Gas prices for medium size industries in Europe and Spain [34]
0
0,005
0,01
0,015
0,02
0,025
0,03
0,035
199719981999200020012002200320042005200620072008
Gas prices for medium size industries Eurostats, without taxes (€/kWh), source: Eurostat
EU (27 countries)
EU (15 countries)
Spain
The figure 3‐20 shows a high sensitivity of the LEC of the CC plant. The ISCC plants have almost the
same sensitivity as CC plants because of the large fraction of gas expenses in the LEC. However the
LEC of the ISCC plants converge towards the CC‐LEC. An increasing solar share, leads to a lower LEC
sensitivity, but the LEC doesn’t seem to cross the cost of the CC plant rapidly.
Figure 3‐20. Evolution of the LEC with the gas price for different ISCC Technologies and CC
0,00
20,00
40,00
60,00
80,00
100,00
120,00
140,00
160,00
‐75% ‐50% ‐25% BASE +25% +50% +75% +100% +125% +150% +175% +200%
Gas price variation
LEC (€/MWhe)
CC ISCCS (14 % Solar share)
ISCCS (With extra burnder) ISCCS (32,9 % Solar share)
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 39
Rising gas prices will result in higher LEC for the ISCC and CC plants. Because of the high correlation
between the electricity prices and the natural gas prices, these higher LEC’s can be compensated by
selling the electricity at higher prices.
Looking at the electricity prices of the Spanish electricity market, called the OMEL, there is an
increasing trend of the average electricity price (figure 3‐21). A growing share of Europe’s electricity
trading is conducted on electricity exchanges like the OMEL, where producers, retailers, major
industrial companies and financial players conduct trading. Prices on the electricity exchanges are
determined by supply and demand, and also serve as a benchmark for other electricity trading [35].
Figure 3‐21. Electricity prices in Spain from 1998 till 2008 [36]
020,00040,00060,00080,000
100,000120,000140,000160,000180,000
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
Electricity prices OMEL Spain (€/MWh)
Minimum price
Average price
Maximum price
At the end of 2004, the average prices popped out of the 40€/MWh. In 2008 the average prices
increased even more towards 60€/MWh. This means the reference plant with a LEC of 58,3 €/MWh
can be competitive in 2008. Especially because the ISCC plant produces the most electricity at peak
hours, when the electricity prices are more than 60 €/MWh.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 40
4 CONCLUSION
Many factors have an effect on cost of power, the production of green electricity and CO2 emission.
As proven before, it is unlikely to add an extra burner to the ISCC. Indeed it would produce almost as
much CO2 as a normal CC plant. Other factors like a growing solar share and thermal storage imply a
larger LEC but also a great decrease in carbon dioxide emission. The DNI is the most interesting cost
factor, because it tends to lower the LEC and the CO2 emission. Plant scale‐up entails a significant
cost‐reduction, but no CO2 reduction.
The choice of technology, hours of storage, solar share, plant scale and more, depends on the goals
and priorities of the investment in ISCC. The more CO2 emissions need to be reduced, the more the
costs will increase. However it is advised to augment the DNI first, then the thermal storage and the
solar share. The solar share and the thermal storage are the most expensive but also the most
effective solution to decrease the carbon dioxide emission (see figure 4‐1).
If the cost of the ISCC has to be reduced, the DNI and the plant scale‐up should be increased (see
figure 4‐1). These factors imply an decrease of carbon dioxide emission and an increase of green
energy production. A strong diminishing of the LEC can be induced by lowering the solar share.
However a lower solar share implies a higher level of CO2 emission and decreases the green energy
production.
As described in the economic analysis, the preferred technology is Parabolic trough (see figure 3‐4).
This is the cheapest solution and the most commercially developed. Especially it is common to design
an ISCC plant with PT and steam as heat transfer fluid. The technology CRS with steam, chosen as
reference plant, will probably be the most interesting technology in the long term, especially if
storage is planned to be implemented.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 41
Figure 4‐1 LEC vs CO2 emission for different evolutions of the solar share (green), thermal storage9 (purple), DNI (dark blue), plant size (red) and extra burner (light blue)
DNI2600
Plant scale‐up 1100 MW
Solar share32,9%
Storage15h
Extra burner
Reference plant
CC Plant
305
310
315
320
325
330
335
340
345
350
355
50 55 60 65 70 75
Carbon
dioxide
emission
(kg/MWhe
)
LEC (€/Mwhe)
LEC vs CO2
If an ISCC project is not supported by any incentives, great thermal storage may not be an interesting
option. Thermal storage of more than 5 hours makes it possible to produce solar power during the
night, when electricity prices are low. With little thermal storage, the plant only produces energy at
peak level when the electricity sells at its highest price and so the average earnings per kWh are
higher.
With incentives, thermal storage is a very attractive way to produce more solar energy. In some
countries, the peak production of the plant has to be limited to receive incentives per kWh. In this
case long thermal storage can greatly increase the annual production of solar energy and as such
benefit proportionally from more incentives.
9 The LEC for the storage is calculated with the Molten‐Salt HTF technology, not with Steam HTF like the reference plant.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 42
Electricity producers can also profit from the avoided CO2 emission which can be sold since the
agreement of the Kyoto protocol. If the price per tonne of CO2 rises, it will become more and more
interesting to invest in ISCC projects. The annual avoided CO2 emission of the reference plant is
20.611t, and has today a value of 292.670,4 €10.
As shown on figure 4‐2, the price of a EUA has decreased at the end of 2008, probably due to the
international financial crisis.
0
5
10
15
20
25
30
2/01
/2008
2/02
/2008
2/03
/2008
2/04
/2008
2/05
/2008
2/06
/2008
2/07
/2008
2/08
/2008
2/09
/2008
2/10
/2008
2/11
/2008
2/12
/2008
2/01
/2009
2/02
/2009
2/03
/2009
2/04
/2009
2/05
/2009
EU Allowance Unit (EUA) price (€/unit)1 tonne of CO2 = 1 EUA
Figure 4‐2. EUA prices from January 2008 till May 2009 [37]
10 Based on the price of 1t of CO2 on the 04/05/2009 [37]
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 43
In some countries the green energy production is rewarded instead of taxing the CO2 emission. From
figure 4‐3, the same conclusions can be drawn as for CO2 production: a greater solar share or a
longer thermal storage increase the green energy production and, in a smaller extent, a rise of DNI.
Figure 4‐3 LEC vs annual green energy production for different evolutions of the solar share (green), thermal storage11 (purple), DNI (dark blue), plant size (red) and extra burner (light blue)
DNI2600
Plant scale‐up 1100 MW
Solar share32,9%
Storage15h
Extra burner
Reference plant
CC Plant0%
2%
4%
6%
8%
10%
12%
14%
50 55 60 65 70 75
Ann
ual green
produ
ction
(relative to th
e total produ
ction)
LEC (€/Mwhe)
LEC vs Green production
11 The LEC for the storage is calculated with the Molten‐Salt HTF technology, not with Steam HTF like the reference plant.
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 44
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Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 47
ANNEXES
ANNEX 1 : LIFE‐CYCLE ASSESSMENT OF GREENHOUSE GAS EMISSIONS [38]
Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 48
ANNEX 2 : INCENTIVE SYSTEMS BY COUNTRY IN EUROPE
Renewable Energy Promotion Policies in Europe [28]