FEASIBILITY STUDY OF 100 MWe SOLAR POWER PLANT

Dan Sagie Rotem Industries Ltd.

P.O. Box 9046 Beer-Sheva, ISRAEL 84190

dsagie@bezeqint.net

ABSTRACT This study was undertaken for the Israeli Government and includes an updated cost evaluation, configuration optimization, and mode of operation, for a 100MWe solar power plant, the first of five similar plants to be erected at one location. Regarding the preferred technology, the central receiver concept, although potentially more efficient then trough since it fits into a combined cycle plant - is neither technologically mature enough nor proven for commercial application. The Fresnel concept is in a similar development stage. The trough technology, used for the SEGS plants, is the only mature and proven technology ready for application today. The current trough plants use the solar steam to directly drive the turbine at 371oC, due to the thermal oil limitations. This paper analyzes the option of further superheating the steam to 540oC - the optimal temperature for commercial steam turbine. Higher cycle efficiency improves the plant cost effectiveness, since a smaller solar field is required. Solar fraction reduction can be compensated by thermal storage. The power cost is evaluated as a function of the solar fraction, for several operational modes. High solar fraction would increase the power cost significantly. Since the solar plant power generation largely overlaps the hours of high demand, and consequently high power cost - the plant becomes marginally economical for Israel at its present power cost level. The expected increase in power cost would make thus plant even more economically attractive. With the environmental and location premium, the plant becomes economical at the current power tariff. Located away from water resources, an air-cooled condenser was chosen instead of a cooling tower. Wet cooling would add 7% to annual power generation, however, for the specified location, would hardly compensate for the expenses of pumping and desalinating brackish water, as well as the disposal of the concentrates.

1. INTRODUCTION The solar-thermal power plants operating in the Mohave Desert in Southern California (SEGS) are proof positive of the technological and economical potential of the trough solar collector technology. With a combined generation capacity of 354 MWe, these plants, built by Luz Industries between 1984 and 1991, have been operating successfully up to the present. They have already provided over 8 billion kWh of electricity, unparalleled to other solar technologies. The technological developments since the erection of these plants, together with the renewed interest worldwide in Renewable Sources for electricity, triggered the Israeli Ministry of National Infrastructure to carry out an updated feasibility study, in order to evaluate the techno-economical potential of this technology as compared to other renewable sources. The study is especially pertinent to the Middle East where wind and tidal resources are limited, and solar radiation is readily available. The study included an updated, detailed cost evaluation, and optimization for configuration and mode of operation, for a 100MWe solar power plant, the first of five similar plants to be erected at the same location. 2. THE PREFERRED TECHNOLOGY As mentioned above wind and tidal resources are not available for the region in consideration, solar photovoltaic and solar thermal are then the optional technologies. Tender study shows that photovoltaic technologies are still too expensive to apply. MST of Israel’s approach [1], even with the most optimistic estimate still suggests a minimum total plants capacity of 10 GWp in order to be economically feasible, and there are many other technological issues that remain unsolved. The cogeneration approach by Millennium Electric [2] demands that the thermal energy consumer will consume 600 GWhth annually all supplied as water at 65oC to 70oC. This does not seem to be realistic. International Corporations would build a plant for a total installation cost

of about 4$/Wp. Large grid connected PV plants operating today have a nominal installed power of 20 to 30kW and total annual energy generation of 40MWh/year, still only 1:5000 fraction of the required power and energy for the plant. "Multi-MW" PV plants are still on the drawing desk, with no solid data for their real performance and power cost. The conclusion remains that PV technology is not economically mature for commercial application in a full-scale power plant. With regard to solar thermal technology, the central receiver concept is potentially more efficient than the trough concept, since it fits into a combined cycle plant. However, being well acquainted with the Rotem Industries central receiver, which was tested at the Weizmann Institute during the early 90's [3,4], and even relating to the DLR receiver recently tested at Almeria, Spain [5]- the technology is still not mature enough nor is it proven for commercial application. Concentrating dish is yet another dual-axis tracking technology. Although a few companies, Governmental institutes, and academic institutes have been developing this approach for many years – it does not appear that any commercial product is available on the market. The largest dishes, manufactured in Australia, have effective reflecting area of 400 m2, which possibly could provide the best available heat engines up to 75 kW. Typical efficiency is about 30% for these small engines. About 1350 units would be required for the first 100MWe plant, with no potential for breakthrough for the following plants. An array of dishes generating steam also makes no better economy [6]. The benefits of mass production are not going to reduce the cost enough for a large field of dishes to come down to an economically feasible scale. Being left with single-axis tracking, we note that only three solar collectors vendors are available on the market. All propose trough technology similar to the original LUZ International collector. Solel Solar Systems of Israel is the LUZ legal successor. Solel acquired Luz technology, and most of its professional staff came originally from Luz. Other companies now active in the field are Solargenix Energy (N.C., USA) and Solar Millennium (Germany). It is doubtless that the SEGS Plants are the leading example of a commercial solar plant. Luz Industries built the nine solar plants in the Mohave Desert, in Southern California between 1984 and 1991. These plants have been operating successfully for almost 20 years, providing over 8 billion kWh of electricity to half a million residents in the region, and are still operating economically to date. The plants displace the need for 1.5 million barrels of heavy fuel oil a year and about 500,000 Tons of CO2 and NO2. For the Fresnel concept, Solar Heat and Power Pty of Sydney, Australia, claims to have plans to erect a 36 MWe Plant [7]. At the time of submitting the report to the Israeli government (early 2004) - the available data still point to

the conclusion that this technology is not mature, not proven technology. The trough technology, used for the SEGS plants, is the only mature and proven technology ready for application today. The 350MWe total installed power, with accumulating energy production of over 8 billion kWh of electricity, and a continuous reliable power supply up to date - are solid proof for the maturity of this technology. 3. METHODOLOGY Since the design of the SEGS Plants is available to Solel down to the final details, and the performance is known as well - installation and operational cost data are all available. The last to install, SEGS IX was defined as the "basic" plant, and analyzed component by component. Based on the original design drawings and specifications, an updated cost was given. For the more expensive components the price was set by a bid. Then the cost of the modifications as compared to the "basic" plant was evaluated. Performance and operational costs were also estimated based on SEGS IX data with adjustment for the improvements. The power cost was evaluated as a function of the solar fraction, for several operational modes. Realistic assumptions were taken for longevity, interest rate and financing cost. . 4. THE "BASIC" SOLAR PLANT Going with the above methodology we choose the last 80MWe SEGS Plant as the "basic" solar plant design for reference. With updated collector efficiency, only 8.8% field extension was required to achieve the 100MWe nominal power to the grid. Table 1 shows the basic design plant parameters A schematic view of the solar plant is shown in Fig. 1. The plant constitutes of three main subsystems: The solar field including the heat transfer fluid system, the power block system, and the condenser cooling system. For the cost evaluation the balance of plant installation cost is also included. The solar field delivers the solar thermal energy to the power block when the solar energy is available and after the HTF is heated up to its working temperature range. Oil heaters are used as a-back up and operate according to the defined operating strategy. The plant is designed to operate along the entire range from only solar to only fuel up to the full power. The turbine operates with constant pressure with variable steam flow according to its partial working load. The minimum partial load for turbine start up is 10% from its nominal capacity. Blanketing for the steam pipeline and turbine is done for no operating mode, as a maintenance operation.

TABLE 1: BASIC PLANT DESIGN PARAMETERS

Southern Israel 1.8

Site Location Land area (sq. km) Annual water consumption (m3) 1,000,000

Power block Turbine Generator Output (gross MWe) 112 Output to Utility (net MWe) 100 Solar Reheater Capacity (gross MWt) 45 Turbine-Generator Set Solar Steam Conditions Inlet Pressure (Bara) 101 Maximum steam flow (Ton/h) 460 Reheat Pressure (Bara) 17.7 Inlet/Reheat Temperature (ºC) 371 Gas Mode Steam Conditions Identical to solar steam

Electrical Conversion efficiency (%) Solar Mode 37.6 Gas Mode 37.6 Solar Field SCA: Solel #1 (281 m²) 1876 Field Aperture (collectors) Area (m²) 527,000 Field Inlet Temperature (ºC) 297 Field Outlet Temperature (ºC) 391 Annual Thermal Efficiency (%) 50 Peak Optical Efficiency (%) 80 System Thermal Losses (% of peak) 15 Heat Transfer Fluid Type VP-1 Inventory (gal) 500,000 Thermal Storage Capacity (MMBtu) --- Nominal design thermal output (MWt) 297.1

Fig. 1: A schematic view of the solar plant 4.1 The Solar Field 4.1.1 Solar Collector Assembly The basic component of Solar Field is the Solar Collector Assembly (SCA). Each SCA has its own parabolic trough solar collector, positioning system, and local control system. The parabolic trough solar collector is a mirrored glass reflector, which focuses direct solar radiation on an efficient evacuated receiver, or heat collection element (UVAC). The

other primary components of an SCA are the metal support structure, the heat collection element, and the tracking system (drive, sensors, controls). Solel the owner of LUZ technology has continued the line of development of Solar Collectors and developed a new generation of collectors, which combine key features of both the LS-2 and LS-3.

4.1.2 The Reflector Panels The reflector is made up of hot-formed mirrored glass panels, supported by a truss system that gives the SCA its structural integrity. The glass is produced by the conventional float-glass method in which molten glass is conveyed onto a bath of molten metal, such as tin. The high temperature of the molten metal smoothes out irregularities on the surface, resulting in a flat, even sheet. As the glass floats on top of the bath, the temperature of the molten metal is gradually reduced until the glass solidifies. Ceramic pads for attaching to the collector structure are installed with a special adhesive. The precision shape of selected glass panels is tested for accuracy with a laser test device. 4.1.3 The heat collection element (UVAC) Solel’s UVAC Vacuum collector is a technologically advanced heat-collecting element for parabolic troughs. The collector is composed of a coated stainless steel tube enclosed within an evacuated glass tube. The UVAC achieves very high levels of thermal energy output. This output is a result of unique selective coatings, as well as improved anti-reflective coatings on the glass tube that allow more effective solar radiation transmission. Additionally a new patented radiation heat shield system improves the glass to metal connection. The UVAC tube is successfully implemented at the Kramer Junction power plants in Southern California. See Fig 2.

Fig. 2: The UVAC Vacuum Collector The UVAC incorporates glass-to-metal seals and metal bellows to achieve the vacuum-tight enclosure. This enclosure serves primarily to reduce heat losses at the high operating temperatures and to protect the selective surface.

4.1.4 Tracking System Solar tracking is achieved through a closed loop tracking system which relying on a sun sensor for the precise alignment required to focus the sun on the UVAC in operation, periodically sending commands to a hydraulic drive system or to a gear motor to position the SCA. The reflector panel structure and drive system are designed for normal operation in winds, complying 50 years of local wind data. During high winds or during other times when the solar field is not operating the SCAs are stowed in a face-down position at -30° for protection. The SCAs withstand a maximum wind velocity of 50% over the maximum operating wind speed while in the stow position.

4.2 Field Control System The solar field control system consists of a field supervisory controller (FSC) located in the central control building and local microprocessor controllers (LOCs) located on each SCA. The FSC monitors insolation, wind velocity, and HTF pump/flow status, and communicates with all of the LOCs. When the appropriate conditions exist, the FSC initiates the commands to send the SCAs to track the sun, and at the end of the day stows the solar field. If major alarm conditions occur during operation, the FSC or LOCs automatically take action to protect the Solar Field equipment. From the FSC, the operators can monitor the status of each SCA in the solar field. Once the FSC sends an appropriate command to the solar field, the LOCs take over and control the actions of the individual SCAs. The LOC utilizes positioning components to accurately focus its SCA. Interactive screens and graphics make the system operator-friendly and responsive 4.3 Heat Transfer Fluid (HTF) System

The HTF system is a closed loop through which the Heat Transfer Fluid, a eutectic mixture of diphenyl and diphenyl oxide, is used as in previous operational Solar Power Stations. The loop begins at the HTF expansion vessel, which allows for thermal expansion of the HTF. A nitrogen service unit maintains a 165 psia inert atmosphere above the fluid level in the expansion vessel. HTF degradation gases are removed from the expansion vessel through the Ullage venting system. The HTF pumps draw fluid from the expansion vessel for circulation to the cold headers in the solar field. During the flow through a single loop of the Solar Field, the HTF is heated up to 391º C, then transported via the hot headers to two parallel identical trains heat exchangers. The HTF flows counter-current to the feed water flow of the turbine steam-water system. First the HTF passes through a heat exchanger that superheats the inlet steam to the turbine. The HTF then flows through a steam generator and lastly to the preheater, respectively generating saturated steam and preheating the feed water to the steam generator. In parallel with these trains of heat exchangers, a portion of the HTF flows to two heat exchangers that reheat the steam that is flowing from the high-pressure to the low pressure stage of the turbine. The HTF temperature drops from 391ºC to 297ºC as its energy is transferred to the steam cycle in the heat exchangers. The HTF flow can bypass the heat exchangers through a bypass line. The bypass is used during warm-up operation until the solar field heats the HTF to a temperature sufficient to generate turbine steam. The bypass also opens after a turbine trip while in solar mode in order to shut off the supply of turbine steam. The HTF then flows from the heat exchangers to the expansion vessel to repeat the cycle.

Fixed orifices or manual flow control valves accomplish flow balancing of HTF in the solar field loops. Engineering analysis shows that good flow balance will be achieved over the operating flow rate range, and that loop-specific factors influencing temperature misdistributions will have little effect on performance. 4.4 Non Solar Plant Subsystems The other main subsystems of the plant include steam generation equipment; a steam turbine, and generator; a cooling water system; a cooling tower; and a water supply and treatment system. Additionally, the electrical and the control systems as well as siteworks, buildings, roads, gas, water, and power interfaces to the country infrastructure, etc. were all included. Since all these are basically similar to conventional power plant this paper will not discuss them in detail. More information concerning the field design is available from Solel Solar Systems [8]. 5. PLANT MODIFICATIONS Two major modifications were considered in order to improve the solar plant performance:

Superheated steam Air-cooled condenser

5.1 Superheated steam Current trough technology is limited to a thermal oil temperature of not over 400oC, mostly due to the thermal oil limitations. With the steam generator essential temperature gradient the practical highest steam temperature out of the solar field reaches about 370oC. The SEGS plants use the solar steam directly to drive the turbine at that temperature. Current available steam turbines at the 100 MWe power range use steam at 540oC with a significantly higher efficiency. (Carnot’s Law). Those turbines are also cheaper, being on standard high volume supply, while the low temperature turbine needs special custom-made manufacturing. For these plants we analyzed the option of further superheating the steam to 540oC - the optimal temperature for a commercial steam turbine. The higher cycle efficiency improves the plant cost effectiveness, since a smaller solar field is required, while only 7% additional energy is required to superheat the steam. On the other hand this approach inherently reduces the solar fraction, and fuel backing is required even at the peak solar hours. For the long run we are developing a heat storage system, to increase the solar fraction back to 70%, as required by the valid regulations. Efficient superheating of the solar steam required non-standard design. Since the solar steam is supplied at 370oC any standard boiler would throw away the flew gases to the atmosphere at about 400oC, with a large waste of energy.

Fig. 3 demonstrates the coupling of steam superheating system with the steam cycle. By a cautious thermodynamic balance we were able to release the flew gases to the atmosphere at 165oC, and thus to achieve a 90% efficiency of the boiler. Another approach replaces the boiler with a small gas turbine; its waste gases are used to superheat the steam. The coupling of the steam cycle is still required in order to maintain high a recovery of the heat in the flew gases.

Steam to condesator

Turbine L.P.

540oC125oC

ReHeater

165oC 179oC 365oC

Turbine H.P.

125oCCondensate inlet

540oC125oC

SuperHeater

165oC 371oC

Solar Field

125oC 240oCEconomizer

165oC179oC

Fig. 3: Superheating Flow sheet 5.2 Air-cooled condenser The site is located away from the sea, with only brackish water resources available in the close vicinity. Brackish water is available but is quite deep (800m) and sited within a porous rock, requiring significant power to pump it up to ground level. On the ground we must spend about 0.3$/m3 to desalinate the water in order to allow water evaporation in the cooling tower with no excess precipitation/scaling on the tubes. (Other chemical options like Ion exchange have been found to be even more expensive). Still any solid precipitation removal requires disposal of the brines back to the sea, again with substantial expense. We have therefore analyzed the option of an air-cooled condenser as a replacement for the cooling tower, saving all the process of brackish water pumping and desalination, and brine disposal. For the given location with dry and wet bulb temperatures of 31oC and 25oC respectively, commercial dry cooling could maintain a condensing temperature of 55oC. For the same power block this temperature would increase from 42oC for wet cooling to the 55oC for the dry cooling,

reducing the output power from the turbogenerator by 3-4% An hour-by-hour analysis of the condensing temperature for the average temperature at each hour, and the outcome power, results in an annual energy loss of about 22GWeh for the planed 100MWe plant. Since the solar energy is supplied during the sunny, high rate hours - the total losses in annual income reaches a value of about 1.5M$, quite similar to the water cost. For our specific case we chose dry cooling, however a small variation in the water supply or brine disposal cost, as well as revenue by power cost - may invert the picture. A combination of dry and wet cooling is also a viable option. 6. INSTALLATION AND OPERATIONAL COSTS The installation and operational cost for 370oC turbine inlet steam, air cooled condenser is shown in table2 TABLE 2: Installation and operational Costs 7. PERFORMANCE In order to analyze the performance of the plant, a model simulating the operating modes of the power plant, which including the power block and the solar field was developed. Heaters and turbine efficiencies were taken for the momentary load, and parasitic energy losses were included. The model considers transient condition and startups, for the whole year. The operating strategy

according to time dependent electricity prices (“T.O.U.” for power producers), fuel cost, and the maximum yearly limit of gas usage were defined. The model’s results are given in yearly hourly values. Comparing the results at similar

operating modes with the well proof Solel simulation code had verified the model. Solel’s simulation program was and is qualified through comparison to the on line - hourly / yearly data of the solar electric generation system (SEGS Plants) - with accuracy of +/ - 3%., For 371oC plant and 70% solar fraction the major performance parameters are presented in table 3. TABLE 3: Major Performance Parameters (371oC, 70% solar)

Note: The parasitic losses used to be 16% with while flex hoses were used for SCA thermal connections. Now with ball joints connections the losses dropped down to about 11% at nominal operating conditions. 8. POWER COST For the plant economical balance the revenue of the plant is evaluated. Since the power cost is time dependent – its yearly average value has a minor significance. Instead, the time dependent tariff (TOU) was used. A factor named "Cost Factor" was introduced to express in how much percentage this TOU tariff must increase, in order to make the plant economically balanced. The plant might operate always at the full nominal load of 100MWe. This requires fuel to compensate for the input thermal power when not available from the sun. The demand to improve the solar fraction, dictates plant operation at partial load, with lower cycle efficiency.

8.1 Assumptions and Definitions The following power cost results are based on the following assumptions: - Power sale to the National grid at "Producers" T.O.U.

tariff - Cost factor is defined as the factor over the T.O.U. tariff

required for economical balance of the plant. - Longevity - 30 years - Financing terms 6.5% for 30 years (Government

guaranties) for the entire investment. (Detailed cost variation with financial terms was evaluated)

- Cost values are given for an air-cooled condenser.

- The fuel for backing is natural gas at 3.2$/MMBtu - Some reasonable modes of operation were selected to

demonstrate cost results, since real operation mode is generated by the control system accordingly to the weather condition, and power momentarily cost.

8.2 Cost Results Table 4 presents the cost factor for a few operational modes. For each one data is given for both full and partial power operation, either for the 371oC (SEGS like), and 540oC plant. Partial power operation improves the solar fraction on the expense of a lower solar fraction and cost- effectiveness. Since the solar fractions are typically around 50% the specific fuel consumption is given as well.

TABLE 4: COST FACTOR FOR SOME OPERATIONAL MODES All investment financing at 6.5% rate for 30 years

Solar steam temperature & pressure 371oC, 100bar 371oC, 120bar

Turbine inlet temperature & pressure 371oC, 100bar 540oC, 120barTheoretical cycle efficiency 37.3% 42.6%

Effeciency @ 75% solar available 36.3% 41.2%Natural Gas Cost 3.2$/MMBtu 3.2$/MMBtu

LoadMWeh/y kg/MWh MWeh/y kg/MWh

1nominal 50.6% 411041 23.2% 0.106 42.5% 554906 8.1% 1.4% 0.109partial 57.5% 354030 34.4% 0.094 48.2% 477940 9.3% 10.2% 0.101

2nominal 46.2% 448074 19.4% 0.116 38.8% 604900 7.4% -1.5%

-8.1%

0.117partial 53.0% 381170 30.7% 0.104 44.5% 514579 8.5% 7.4% 0.109

3nominal 40.3% 438253 11.8% 0.130 33.9% 591642 6.4% 0.127partial 46.2% 372229 23.3% 0.120 38.8% 502509 7.4% 0.9% 0.120

For conventional power plant with efficiency of 40% 0.185

Cost factor for balance

specific fuel consumption

Generated energy

approx.net

∆solar fraction

(371−540)

7days/week

specific fuel consumption

Solar Fraction

mode of operation Solar Fraction

days/week; hours/year

Generated energy

(net)

Cost factor for balance

4284

4018

7days/week 8 -204380

6days/week 8 -22

Power Relative Cost vs. Solar Factor

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

30% 35% 40% 45% 50% 55% 60%

Solar Factor - %

Cos

t Fac

tor

371oC

540oC

Power Relative Cost vs. Solar Factor

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

30% 35% 40% 45% 50% 55% 60%

Solar Factor - %

Cos

t Fac

tor

371oC

540oC

Fig 4: Power cost factor vs. Solar fraction Fig 4 and 5 present the cost factor and specific fuel consumption as a factor of the solar fraction respectively, for the 371oC and 540oC plants. Fig. 6 presents the yearly average power cost in US$/kWeh

Specific Fuel Consumption

0.090

0.095

0.100

0.105

0.110

0.115

0.120

0.125

0.130

0.135

30% 35% 40% 45% 50% 55% 60%Solar Factor - %

Spe

cific

Fue

l Con

sum

ptio

n

540oC

371oCKg/

kWh

Specific Fuel Consumption

0.090

0.095

0.100

0.105

0.110

0.115

0.120

0.125

0.130

0.135

30% 35% 40% 45% 50% 55% 60%Solar Factor - %

Spe

cific

Fue

l Con

sum

ptio

n

540oC

371oCKg/

kWh

Fig 5: Specific fuel consumption vs. Solar fraction for three operational modes, at full and partial power, both for the 371oC and the 540oC plants, with the resulting solar fraction. The 540oC plant operating 4018h/y can reach a solar fraction of 50% at 6.5¢/kWeh. Even lower solar electrical power is achievable with a lower solar fraction.

Power Cost for Balance - $/kWeh

0.050

0.055

0.060

0.065

0.070

0.075

0.080

30% 35% 40% 45% 50% 55% 60%

Solar Factor - %

Pow

er C

ost $

/kW

h

- $/

kWh

371oC,4284h, 6d/w

540oC,4018h, 7d/w

540oC,4284h, 6d/w

371oC,4018h, 7d/w

371oC,4380h, 7d/w

540oC,4380h, 7d/w

Fig. 6: Power cost for balance for several operational modes The yearly average power cost as a function of the annual hours of operation is given in Fig. 7 and Fig 8 for 371oC and 540oC plants respectively. The solar fraction is given as well. Due to time delay in the natural gas pipeline arrival to the site, the power cost for the temporary option of 3%S heavy oil (Mazot), with the appropriate environmental protection, was also considered.

Electrical power cost vs Annual hours, 371oC Turbine

5

6

7

8

9

10

11

350040004500500055006000Annual hours

Cos

t cen

t

H. Mazot

N. gas

Solar Factor: 40 % 50% 60% 70% 80% 90% 100%

Fig. 7: Power cost vs. annual operational hours 371oC plant Electrical power cost vs Annual hours, 540oC Turbine

5

6

7

8

9

10

11

350040004500500055006000Annual hours

Cos

t cen

t

H. Mazot

N. gas

Solar Factor:32.4% 40.6% 48.8% 57% 65.3% 74.5% 82%

Fig. 8: Power cost vs. annual operational hours 540oC plant Since the power is supplied to the grid during daytime it overlaps the hours of high power cost. Therefore power cost of 7 to 8 ¢/kWeh is certainly acceptable. The Government is considering issuing an international tender for the erection

and operation of these 100MWe plants. In that specific case the financing cost will be higher, however this would be compensated by the premium for renewable energy, and for distribution savings. Extensive work is carried out in Rotem Industries to develop a cost effective storage system that would dramatically improve the solar fraction. Details are left for future reports. CONCLUSIONS Steam superheating significantly improves plant economy, with minor fuel addition. Dry cooling is a viable option where water is not available. A solar thermal trough plant could operate at power cost not exceeding the current prices, at the hour of supply. Some support is still required, for example as an RE premium, which the Israeli Government is willing to grant. Storage system should be included where a goal of 70% solar fraction has been set. ACKNOWLEDGMENTS - The study was supported by the Israeli Ministry of

National Infrastructure. - Data from Solel Solar Systems of Beit-Shemesh, Israel,

was extensively used for this study. REFERENCES (1) Raviv D., MST, A Paradigm Change in Replacing

Fossil Fuel with Soar Energy, Solar Energy Sde Boker Conference, Israel, 2004

(2) Elazary A., Millennium Electric, Building integrated Multi PV/t/a Solar System Roof Tiles, The 12th International Photovoltaic Science and Engineering Conference, June 2001, Korea

(3) Sagie D., Rotem Industries, The Development of a Volumetric Solar Receiver - An Overview, Israel

Atomic Energy Commission Annual Report,. IAEC 1994, IA- 1490 (4) Karni J., Kribus A., Doron P., Sagie D., The DIAPR: A

High-Pressure, High-Temperature Solar Receiver, ASME J. of Solar Energy Engineering, Vol. 19, 1997.

(5) Buck R. Heller P., DLR and Sugermen C. Ring A., Ormat, Tellez F., CIEMAT, Enrile J., SOLUCAR, Solar-Hybrid Gas Turbine Plants: Status and Perspective, EuroSun 2004

(6) Kaneff S., ANUTECH Australia, A 20 Dish Solar Thermal Array Providing 2.6MWe via an Existing Coal-fired Steam-Driven Turbogenerator System, ISES 1999 Solar World Congress, Jerusalem, Israel, 1999

(7) Mills D. Morrison G.L., Le Lievre P., Solar Heat and Power, Design of a 240 MWe Solar Thermal power Plant, EuroSun 2004

(8) Solel Solar Systems, PO Box 811, Beit-Shemesh, ISRAEL 99107, eli@solel.com