UNIVERSITEIT GENT - UGent

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


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.


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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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.


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.


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.


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


2010

Egypt, Kuraymat

ISCCS PT


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.


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.


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


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.


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.


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


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.


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].


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]


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.


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


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.


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]


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].


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.


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.


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].


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.


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.


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)


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


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


CC


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).


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


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]


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


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.


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


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].


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.


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)


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)


32,9%

24,7%

17,9%

9,8%

CC


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].


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)


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.


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.


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.


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]


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.


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ANNEXES

ANNEX 1 : LIFE‐CYCLE ASSESSMENT OF GREENHOUSE GAS EMISSIONS [38]


ANNEX 2 : INCENTIVE SYSTEMS BY COUNTRY IN EUROPE

Renewable Energy Promotion Policies in Europe [28]

Documents

UNIVERSITEIT GENT - UGent