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 3 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 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 4 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 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 ABBREVIATIONS CC CLFR CSP CRS DNI DSG EUMENA GEF GT GW HRSG HTF HVAC HVDC ISCC LEC MENA MW MWe MWhe MWhth PCM PT RTIL SEGS ST TES Combined Cycle Compact Linear Fresnel Reflector Concentrated Solar Power Central Receiver System Direct Normal Irradiance Direct Steam Generation Europe (EU), the Middle East (ME) and North Africa (NA) Global Environment Facility Gas Turbine Gigawatt (109 watt) Heat Recovery Steam Generator Heat Transfer Fluid High Voltage Alternative Current High Voltage Direct Current Integrated Solar Combined Cycle Levelized Electricity Cost Middle East and North American Countries Megawatt (106 watt) Megawatt electric Megawatt hour electric Megawatt hour thermal Phase Changing Materials Parabolic Trough Room Temperature Ionic Liquids Solar Energy Generating System Solar Tower Thermal Energy Storage XI 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] Definingg the techno‐‐economic optimal configguration of h
hybrid solar p
plants | 2009
9 4 The mosst common C
CSP technolo
ogies are the parabolic trough, centtral solar recceiver or sollar tower and the parabolic dissh or dish Stiirling. Parabolic troughs an
nd solar towers can be d
developed in large fields with a poweer block quitte similar to thosee of conventtional power plants. These are used for large‐scale production of ene
ergy. The power block b
of paraabolic dishess is situated at the focall point of the dish. Therrefore, the electricity e
that can be produced is greatly liimited. Recceiver
Figure 2‐2.. Concentrated Solar Power, ttypes of solar re
eceivers [2] 2.1.2
CONVENTION
O
NAL THERMA
AL POWER
Solar po
ower can bee combined with different types of conventionaal thermal p
power generration. In Australiaa, solar poweer is used to
o enhance th
he efficiency of existing ccoal power p
plants [3]. De
epending on the availability a
different kind
ds of fuel are chosen to power new
w plants. Most of the new hybrid power plants are bassed on comb
bined cycles.
om the exhaust of a gass turbine to generate A combiined cycle power plant uses the waaste heat fro
steam by passing it through a heat recoveryy steam generator (HRSG
G). Then, thee Steam of tthe HRSG feeds a ssteam turbin
ne from a Ran
nkine cycle. Definingg the techno‐‐economic optimal configguration of h
hybrid solar p
plants | 2009
9 5 Figure 2‐3. Combined Cycle P
Power Plant [4]] w from 30‐40
0% to 60% ffor the production of Such a tthermal cyclee allows the plant efficieency to grow
electricitty. If the com
mbined cycle is used for ccogeneration
n of electricitty and heat, the overall e
efficiency of the plant can add up to 85% [5
5]. wer plants can assure base load as well as peak production. Besides their high Combineed cycle pow
efficienccy, they havve relatively low investm
ment costs, long life cyycle and low
w greenhou
use gases emission
ns (see figuree 2‐4). The emission of to
oxic gases likke SO2 and NOx is also mu
uch lower th
han diesel, heavy oil or bitumino
ous coal 1 . Figurre 2‐4. Net efficciency of differrent technologiies in maximum
m capacity factor [6] 1
Annex 1 : Life‐cycle asseessment of greeenhouse gas em
missions [38] 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 2.2
7 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 2.3
8 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 Solar (MWe) Capacity Solar Share DNI
Phase Online date Australia , Lake Lidde Iran, Yazd Algeria, Hassi R’mel Morocco, Ain Beni Mathar Egypt, Kuraymat U.S., Victorville, CA U.S., Indiantown, FL Italy, Siracusa U.S., Fresno County, CA U.S., Palmdale, CA Mexico, Sonora State Coal CLFR ISCCS PT ISCCS PT ISCCS PT ISCCS PT ISCCS PT ISCCS PT ISCCS PT Biomass PT ISCCS PT ISCCS PT 2004,4
4,4
0,2%
Finshed 2008
467
17
3,6%
2300‐
2400 2500
2010
150
25
16,7%
2300
472
20
4,2%
2300
140
40
28,6%
2400
563
50
8,9%
1125
75
6,7%
2200‐
2600 ‐
Under construction Under Construction Under Construction Under Construction Under Construction ‐
730
30
4,1%
2100
2010
187
107
57,2%
‐
Under construction ‐
570
50
8,8%
Planned 2013
500
30
6,0%
2200‐
2600 2600
‐ 150
30
20,0%
2250
Approved by World Bank/GEF ‐
India , Mathania ISCCS PT (MWe)
2010
2010
2010
2010
2010
2011
‐ 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 2.4
10 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) Total annual capital Cost € Total annual Operational & Maintenance Cost no fuel expenses € Total annual fuel expenses € Annual electricity production MWhe Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 3.2
12 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 Solar Technology Fuel type Nominal power Gas turbine power Steam turbine power Solar contribution Plant Capacity factor ISCC
Efficiency CC DNIannual DNIpeak Thermal storage Solar‐to‐thermal efficiency (%) Extra burner Depreciation time Mortgage repayment time
Debt capital/total capital
Debt capital interest rate
Capital cost venture capital Inflation Taxes Fuel price Gas Investment CSP Investment Power block (CC) Investment Civil and structural work Investment Indirect costs
Investment ISCC (total) Annual production Annual solar production Emissions LEC (min) 2
LEC (max) Parameter
Solar Tower (CRS)
Natural gas
265
146,7
109,3
36 (3 x 12)
63
52
2100
850
0
50
no
20
20
80
6
12
2
0
20
57,42
94,03
4,51
43,00
198,97
1411,18
59,2
335,8
58,3
73,1
Table 3‐1. ISCC Reference plant properties 2
In further calculations, the minimum LEC is always shown in graphs and texts. Units MWe MWe MWe MWe % % kWh/m²/y
W/m² hours % years years % % % % % €/MWhth
€ mio € mio € mio € mio € mio GWh/y
GWh/y
kg/MWhe
€/MWhe
€/MWhe
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%
64%
15%
LEC
Total Capital Cost
Total Operational Cost
Fuel Expenses
Investment cost
22%
Power block
47%
29%
Civil and structural work
CSP
2%
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 3.3
14 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. LEC (€/MWhe)
59,0
58,5
58,0
57,5
57,0
56,5
56,0
55,5
55,0
54,5
54,0
53,5
58,3
56,6
55,9
55,5
55,3
256
512
768
1024
1280
Total capacitiy of plant (MW)
Figure 3‐2. Scale‐up effect : LEC vs Total capacity of the power plant Specific investment cost (€/W)
0,7
0,6
0,5
0,4
CIVIL STR WORK
0,3
CSP
0,2
POWER BLOCK
0,1
0
256
512
768
1024
1280
Total capacitiy of plant (MW)
Figure 3‐3. Scale‐up effect: Specific investment cost vs Total capacity of the power plant Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 3.4
15 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 3.4.2
16 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 salt 3 , 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 Solar field (€/m²) Receiver & piping (€/kWth) Civil works + tower (€/tower) Thermal storage (€/kWhth) Indirect costs Land‐use factor Solar to thermal eff. HTF Temperature 5 (°C) PT Oil 206 0 2% 4
31 20% 30% 46,2% 371 PT DSG
190
0
2% 4
30
20%
CRS M.Salt
150
125
1000000
14
20%
CRS Steam 150 110 1000000 100 20% 30%
48,4%
411
35%
52%
565
35% 50% 260 CRS Air
150 115 1000000
60 20% 35% 47,7% 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. Levelized Electricity Cost (€/MWhe)
61,0
59,0
57,0
55,0
LEC
53,0
CC
51,0
58,3
57,5
58,3
58,3
58,9
49,0
ISSC PT Oil ISCC PT DSGISSC CRS ISSC CRS M.SALT STEAM
ISCC CRS AIR
Figure 3‐4. Levelized Electricity Cost of different ISCC technology 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 3.4.4
18 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). Investment Cost of CSP 100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Land
Civil works + tower
Receiver & piping
Solar field
ISSC PT Oil ISCC PT DSGISSC CRS ISSC CRS M.SALT STEAM
ISCC CRS AIR
Figure 3‐5. Investment costs of different ISCC technology 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 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
60
59
58
57
56
55
54
0%
10%
20%
30%
40%
50%
Reduction solar field/heliostat field
Figure 3‐6. Levelized Electricity Cost with reduction of the solar field 60%
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 3.5
20 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 3.5.1
21 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 Plant Technology‐HTF Capacity Thermal Storage Technology Storage Thermal Capacity Capacity of the Storage 434.66MWh
153.80MWh
461.41MWh
15MWh
Spec. Investment Cost for Storage 31€/kWhth 14€/kWhth 13€/kWhth 100€/kWhth Investment Storage (% of total investment) 7.64% 3.42% 3.38% 4.03% PT‐thermal oil CSR‐molten salt CSR‐molten salt CSR‐saturated steam 50MW
17MW
50MW
11MW
2‐tank molten 2‐tank molten 2‐tank molten Water/steam
3h
3h
3h
50min
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 hours 6 . 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 Growth factor of the solar field
3,50
3,00
2,50
2,00
1,50
Barstow (DNI=2700)
1,00
Seville (DNI=2014)
0,50
0,00
0
1
3
6
9
12
15
Storage size (h)
Figure 3‐8. Growth factor of the solar field with the hours of thermal storage in two different locations [21] [18] 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. CSP Investment Cost (€)
Civil Works
Solar field
Extra solar field
Land Reciever & Piping
Storage
0h Storage (Seville, DSG)
3h Storage (Barstow, M.Salt)
3h Storage (Seville, M.Salt)
0
20
40
60
80 Millions
Figure 3‐9 CSP Investment Cost of 3h storage in Barstow and Seville compared with no 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. LEC (€/MWhe)
DNI 2000 (Seville)
DNI 2700 (Barstow)
72
70
68
66
64
62
60
58
56
54
52
0
1
3
6
9
12
15
Hours storage (h)
Figure 3‐10. Evolution of the LEC with the thermal storage time for two sites with different DNI 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 Annual solar contribution
DNI 2000 (Seville)
DNI 2700 (Barstow)
12%
10%
8%
6%
4%
2%
0%
0
1
3
6
9
12
15
Hours storage (h)
Figure 3‐11. Evolution of the annual solar contribution with the thermal storage time for two sites with different DNI Carbon dioxide emissions (kg/MWhe)
DNI 2000 (Seville)
DNI 2700 (Barstow)
340
335
330
325
320
315
310
305
300
295
0
1
3
6
9
12
15
Hours storage (h)
Figure 3‐12. Evolution of the CO2 emission with the thermal storage time for two sites with different DNI Defining the techno‐economic optimal configuration of hybrid solar plants | 2009 3.6
28 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. Anual production Levelised Electricity Cost (GWhe/y)
(€/MWhe)
1600
59,5
1550
59,0
1500
1450
58,5
1400
1350
58,0
1411
1584
1300
58,3
59,4
NO EXTRA BURNER
WITH EXTRA BURNER
57,5
NO EXTRA BURNER
WITH EXTRA BURNER
Figure 3‐13. Annual electric production and LEC of ISCC power plants with or without extra burner Carbon dioxide emissions (kg/MWhe)
350,0
345,0
340,0
335,0
330,0
325,0
335,8
347,2
348,2
NO EXTRA BURNER
WITH EXTRA BURNER
CC
Figure 3‐14. Comparison of the CO2 emissions of ISCC plants with or without extra burner and a CC plant 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 3.7
29 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]. Fixed O&M cost Variable O&M cost
Total O&M cost Unit $/kW/a ¢/kWh ¢/kWh HTF‐trough
15.5
0.166
0.398
Air‐Tower
14.3
0.165
0.379
Reference CC 7.2 0.204 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.) Variable O&M: water use Variable O&M: other Unforeseen Cost (% of Inv) Other Cost (% of Inv) CC: O&M costs + contingencies Fixed O&M: Equipment costs (% of inv.) Variable O&M: other Unforeseen Cost (% of Inv) Other Cost (% of Inv) 3
1,3
0,5
2
2
% €/MWhe €/MWhe % % 2
1,97
2
2
% €/MWhe % % 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 FINANCIAL INCENTIVES, GRANTS 3.8
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% 20‐25% 15‐20% 10‐15% 5‐10% 0‐5% 200%
180%
160%
140%
100%
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 France ISCC max 12MW 100‐200% 0.30€/kWh
Lifetime
20+
‐
no
‐
max 12MW, max 1500h/a yes
no Germany Greece up to 5MW over 5MW 0.46€/kWh
0.23‐0.25€/kWh
0.25‐0.27€/kWh Lifetime
10+10
10+10 no
no
no ‐
‐
no yes
yes Israel up to 20W
over 20MW 0.20$/kWh
0.16$/kWh 20+10
20+10 yes
yes ‐
max 30%
max 30% Portugal up to 10MW over 10MW 0.21€/kWh
0.16€/kWh 15
15 no
no ‐
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 3.9
35 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 Levelized Electricity Cost (€/MWhe)
75
70
65
32,9%
60
24,7%
55
17,9%
9,8%
50
CC
45
1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600
DNI (kWh/m²/y)
Figure 3‐16. Levelized Electricity Cost of various DNI levels and different solar shares 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. Carbon dioxide emissions (kg/MWhe)
360
350
340
330
32,9%
320
24,7%
310
300
17,9%
290
9,8%
280
CC
270
1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600
DNI (kWh/m²/y)
Figure 3‐17. Carbon Dioxide Emissions for various DNI levels and different solar shares 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 2007 7 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 Gas prices for medium size industries Eurostats, without taxes (€/kWh), source: Eurostat
0,035
0,03
0,025
0,02
0,015
0,01
0,005
0
EU (27 countries)
EU (15 countries)
Spain
199719981999200020012002200320042005200620072008
Figure 3‐19. Gas prices for medium size industries in Europe and Spain [34] 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. LEC (€/MWhe)
CC
ISCCS (14 % Solar share)
ISCCS (With extra burnder)
ISCCS (32,9 % Solar share)
160,00
140,00
120,00
100,00
80,00
60,00
40,00
20,00
0,00
‐75% ‐50% ‐25% BASE +25% +50% +75% +100% +125% +150% +175% +200%
Gas price variation Figure 3‐20. Evolution of the LEC with the gas price for different ISCC Technologies and CC 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]. Electricity prices OMEL Spain (€/MWh)
180,000
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
Minimum price
Average price
Maximum price
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
Figure 3‐21. Electricity prices in Spain from 1998 till 2008 [36] 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 LEC vs CO2
Carbon dioxide emission (kg/MWhe )
355
350
CC Plant
Extra burner
345
340
Plant scale‐up 335
Reference plant
1100 MW
DNI
330
2600
325
320
Solar share
315
32,9% 310
Storage
15h
305
50
55
60
65
70
75
LEC (€/Mwhe)
Figure 4‐1 LEC vs CO2 emission for different evolutions of the solar share (green), thermal storage 9 (purple), DNI (dark blue), plant size (red) and extra burner (light blue) 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. EU Allowance Unit (EUA) price (€/unit)
1 tonne of CO2 = 1 EUA
30
25
20
15
10
5
2/05/2009
2/04/2009
2/03/2009
2/02/2009
2/01/2009
2/12/2008
2/11/2008
2/10/2008
2/09/2008
2/08/2008
2/07/2008
2/06/2008
2/05/2008
2/04/2008
2/03/2008
2/02/2008
2/01/2008
0
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. LEC vs Green production
0%
CC Plant
Annual green production (relative to the total production)
2%
Reference plant
Plant scale‐up 4%
Extra burner
1100 MW
DNI
6%
2600
8%
10%
Storage
15h
12%
Solar share
32,9% 14%
50
55
60
LEC (€/Mwhe)
65
70
75
Figure 4‐3 LEC vs annual green energy production for different evolutions of the solar share (green), thermal storage 11 (purple), DNI (dark blue), plant size (red) and extra burner (light blue) 11
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