Renewable Energy Technologies: A Review of the Status and Costs of Selected Technologies (WB, 1994, 184 p.) 3. Solar-thermal Introduction Solar-thermal electric technologies (introduction...) Parabolic trough Parabolic dish Central receiver Cost of electricity generation from solar-thermal electric technologies Cost of electricity generation from parabolic trough solar-thermal technology Cost of electricity from parabolic dish solar-thermal technology Cost of electricity generation from central receiver solar-thermal technology The future of solar-thermal electric energy

Renewable Energy Technologies: A Review of the Status and Costs of Selected Technologies (WB, 1994, 184 p.)

3. Solar-thermal

Introduction

The earth continuously receives a power input of 1.73 x 1014 kW from the sun. This translates to 1.5 x 1018 kWh/year, which is about 10.000 times the world's current annual energy consumption (Dunn 1986). The conversion of this huge renewable energy resource directly to electrical energy is the topic of this chapter and that of chapter 4.

Solar-thermal power plants use the sun's rays to heat a fluid, from which heat transfer systems may be used to generate steam that in turn is used to drive a turbo-generator. Or, the fluid may be used to operate an engine directly. At the outer atmosphere, the solar energy constant (indicative of the power density) is 1.373 kW/m2. Energy is then absorbed and scattered by the earth's atmosphere. The final incident sunlight is diffuse, with a peak power density of only 1 kW/m2 at the earth's surface at noon in the tropics (International Energy Agency 1987). The insolation available for conversion to energy varies with factors such as the location of the sun in the sky (daily and seasonally), atmospheric conditions, altitude of the site, and number of daylight hours. Therefore, it is usually concentrated first by the use of mirrors. Three main technologies for concentration are in use or under development and are described in the section entitled Solar-Thermal Electric Technologies. Their current and prospective costs for electricity generation are discussed in the subsequent section.

It is worth pointing out that the methods of solar-thermal power generation are essentially the same as conventional technologies, except that the "fuel" is direct heat energy rather than stored energy in the form of fossil fuels, from which the heat energy needs to be released by combustion. This has led to criticism of the technology for its inability to store energy, unlike fossil fuels or biomass. However, storage of thermal energy is possible, and a number of systems are under development. These are discussed in more detail in the technology sections. Furthermore, as shown in the section on costs, thermal storage may help to reduce the unit cost of electricity generation from thermal-solar plants by improving the capacity utilization of the turbo generating and electrical plants. In addition, thermal storage could be unnecessary if thermal-solar plants were used in conjunction with existing hydro schemes; use of the solar plants would reduce the rate of drawdown of the reservoirs in the dry seasons.

The land requirement of solar-thermal plants is also worth consideration. Annex 4 gives land intensities of a dendro thermal plantation (based on an engineering study); an operating parabolic trough solar-thermal plant; and the collector areas of three existing central receiver test facilities. For completeness, the array area of three photovoltaic concentrator schemes is also given. These arc compared with the inundated area of several existing or planned hydro plants in Brazil. The data are also shown in Figure 3.1 below.

As can been seen, the range of sizes in the case of hydroplants is large, and the collector or array area of solar plants is at the lower end of this range; whereas that of a dendrothermal plant is at the higher end of the range. This is only a rough comparison, and a comparison of total area occupied by the plant to the kilowatt hours generated by the plant would be more accurate (see Anderson 1992). However, Figure 3.1 does provide a comparison of the areas involved; this is unlikely to be altered significantly even if the areas are changed to allow for spacing.

The land requirements for solar-thermal plants, when compared with dendrothermal plants and hydroelectric dams, therefore, are not high; furthermore, solar-thermal plant sites are likely to be desert areas with low land values. Many experts feel that thermal-solar schemes, relative to hydro and biomass, are an attractive option for these very reasons, as they can be sited away from populous agricultural areas. This is particularly important when arable land is scarce or resettlement issues are controversial.

From an environmental viewpoint, solar-thermal technologies are benign. There are no emissions to the atmosphere. There is a water requirement, since areas of high insolation are usually dry (U.S. Congress 1992; unpublished IFC data). However, that problem can be minimized by using recycling systems (such as those commonly used in thermal power plants).

Figure 3.1. Land Requirements for a Biomass Plantation, Solar-Thermal Plants, and the PV Array Areas of Existing Solar Plants Compared with the Inundated Area of Hydroplants

Solar-thermal electric technologies

The three main types of system in use for concentrating and collecting diffuse sunlight are shown in Figure 3.2.

Figure 3.2. Concentrator and Receiver Systems for Solar-Thermal Electric Technologies

Parabolic trough

Currently, the most advanced of the "concentrator" systems is the parabolic trough This is the technology used in the largest commercial grid-attached solar-thermal power plants, which together make up 90 percent of the world's solar electric capacity (U.S. DOE 1990a). These have a total net capacity of 354 MWp and are based in Southern California They were installed by Luz International Limited and operated by that company until March 1992, when operation and maintenance were taken over by new operating companies, such as the Kramer Junction Operating Company for the Kramer-based plants, after Luz suffered financial difficulties (Kearney and Price 1992; Lotker 1991). These difficulties are summarized in Annex 5. The plants are still generating electricity and continue to provide information on technical performance and costs.

Parabolic troughs track the sun along one axis, concentrating the energy onto a receiver tube located at the trough's focal line. Concentration ratios of 10 to 100 are typically achieved, with operating temperatures of about 400° C. In commercial plants, the receiver tube usually has water or oil running through it as the heat transfer medium This fluid is then piped from each of the parabolic trough assemblies to a central area, where the energy is converted to electricity (De Laquil and others 1993; U.S. DOE 1992b;

International Energy Agency 1987). Research is being carried out on direct steam generation (DSG), which is expected to cut costs further as it eliminates the need for the heat transfer fluid as well as centralized oil-heated steam generators (De Laquil and others 1993). Commercialization of DSG technology was planned for 1996 by Luz, which launched a major program to develop the technology in 1989. This is now in doubt, however, because Luz has filed for bankruptcy (see Annex 5). In commercial plants, electricity demand when solar radiation intensity is low is currently met by the use of auxiliary gas-fired boilers or heaters. Thermal storage systems do exist but are not cost effective so far; however, three new concepts that promise to be cheaper than current alternatives have been identified, although they still need significant development to reach technical readiness (De Laquil and others 1993).

The lack of economical storage and the combustion of a fossil fuel on cloudy days to maintain the output has prevented the technology from being a fully independent alternative to fossil fuel plants. The Luz plants are all 25 to 30 percent natural gas hybrids. This has not only helped to maintain their electrical output on cloudy days but has also helped to increase the capacity factor and reduce costs, resulting in a more economic scheme for the sale of power to the grid under U.S. PURPA regulations on the basis of avoided costs (Kearney and Price 1992).

Parabolic dish

A parabolic dish operates on the same principle as the parabolic trough, but it tracks the sun on two axes, concentrating the energy at the focal point of the dish because it is always pointed at the sun. The parabolic dish's concentration ratios are considerably higher than the trough's. Dish ratios are 600 to 2,000, and operating temperatures can exceed 1,500°C (De Laquil and others 1993). The power-generating equipment for use with parabolic dishes may be mounted at the focal point of the dish itself, or, as with the trough, energy may be collected from a number of separate installations and converted to electricity at a central point (International Energy Agency 1987). The former option is perhaps the most promising use of the dish technology, making it very well suited to remote or stand-alone applications.

The two most promising engines for mounting at the focal point appear to be the Brayton cycle engine and the Stirling-cycle engine (De Laquil and others 1993). These convert the heat to power as heat is continuously supplied to a gas in a closed system, which in turn drives a piston as it cycles between hot and cold spaces in the engine. Extremely high solar-toelectricity efficiencies have been achieved for this technology; the record is 29.4 percent for the Vanguard parabolic dish-Stirling engine 25 kWp module in California, which was tested jointly by the U.S. Department of Energy and the Advanco Corporation between 1984 and 1985 (De Laquil and others 1993). Several parabolic dish test facilities have been constructed and operated; of these, some are still operational, but others have been disassembled (De Laquil and others 1993). The U.S. Department of Energy, in a joint venture with Cummins Power Generation, is working on the development and commercialization of a 5 kW dish/engine system and intends to initiate another project, involving the utilities, on 25 kW dish/engine systems (U.S. DOE 1992b).

Central receiver

This is a very promising technology for large-scale grid-connected power generation, even though it is at an early stage of development compared with parabolic trough technology. In this case, flat tracking mirrors, called heliostats, concentrate the sun's energy onto a central receiver tower. Concentration ratios are 30() to 1,500, and systems can operate at temperatures of 500 to 1,500° C (De Laquil and others 1993). Energy losses from thermal-energy transport are also minimized as solar energy is being directly transferred by reflection from the heliostats to a single receiver rather than being moved through a transfer medium from several receivers to one central point, as with parabolic troughs. Solar-to-electric efficiencies for test systems are in the 8 to 13 percent range (De Laquil and others 1993). There are several test facilities in operation in both Europe and the United States. Work has been carried out on a number of different heat-transfer media, such as water/steam, molten sodium, air, and molten salt. The latter two are especially promising, as they could provide an economical energy storage system Currently, the largest demonstration of the molten salt technology has been in France on the THEMIS 2 MWp central receiver system, using Hitec molten salt, giving the plant six hours of electricity production capability without the sun. This experimental facility completed its operation in 1986, having achieved lower annual power production than expected, but having demonstrated the advantages of the new technology and highlighted problems that needed further resolution (De Laquil and others 1993; International Energy Agency 1987)

The U.S. Department of Energy, in collaboration with a consortium headed by Southern California Edison, is currently converting the successful 10 MW Solar One (water/steam) central receiver pilot-plant to Solar Two (U.S. DOE 1992b). The Solar Two project will use molten nitrate salt as the heat transfer and storage system and will be able to provide power for about four hours after sundown or during cloudy periods. The molten nitrate salt technology has been validated at Sandia National Laboratory, but the Solar Two pilot will be the first largescale field demonstration of the technology. It will highlight technical issues that appear to require further resolution, such as crystallization of the molten salt and energy losses from the salt during piping. New stretch-membrane heliostats will also be added to the existing heliostat field to increase the system's energy output. New improved heliostat design and new receiver technologies continue to be tested in the United States with a view to improving performance (see U.S. DOE 1992b and De Laquil and others 1993). The U.S. Department of Energy believes that the Solar Two project will lead to the utilities setting up as many as four 100 MW central receiver plants by 1997-98 (discussions with R.H. Annan, Director, Office of Solar Energy Conversion, U.S. DOE, Washington, D.C.).

Another project under development uses air as the heat transport medium, with heat storage in a porous ceramic material. The work is being carried out by a European industry group called the PHOEBUS Consortium (De Laquil and others 1993; Grasse 1992). The advantages of this system are great because of its suppler design, ease of operation and maintenance, and lower cost. However, current disadvantages are the heat losses from the open receiver and the low effectiveness of the storage system. Plans are under way to construct a 2.5 MW experimental facility in Spain by 1993 to validate the system before building a 30 MW central receiver/fossil fuel hybrid plant with about three hours storage capability (due to solar only) near Aqaba, Jordan, in 1995.

Cost of electricity generation from solar-thermal electric technologies

Costs of electricity production using solar-thermal electric technologies are given in Annex 6. The "calculated cost" is calculated from the quoted capital cost, quoted operating and maintenance cost, and quoted fuel cost (natural gas only) using the formula given in Annex 1, assuming a 10 percent discount rate. The cost has then been converted into 1990 dollars according to the method described in Annex 1. The "quoted cost" is the cost exactly as given in the reference.

Two points need to be emphasized. First, all costs, other than those listed in entries 9, 10, 14, 15, and 16, are predicted costs. Those noted above are based on the Luz plants operating in Southern California. The Luz SEGS {Solar Electric Generating System) power plants in California are the main source of cost data, because they are the main example of commercial grid-attached electricity production from solar-thermal technologies. Other plants do exist, but are smaller in scale and, in the main, experimental; because of the significant R&D expenditure involved, their power production costs (which are often not quoted) are not indicative of actual production costs.

Second, the graphs in this section have been plotted using the "calculated costs" (i.e., costs calculated on a common basis) rather than the quoted costs for electricity generation, in order to remove discrepancies caused by different assumptions. For example, for entry 29, the cost of electricity generation using central receiver technology assuming a 5 percent discount rate is 23 cents/kWh (1984 currency), but 34 cents/kWh (1984 currency) with a 10 percent discount rate, with all other parameters equal. On a less obvious note, for the same system, the study quotes a cost of electricity generation of 13 cents/kWh (1984 currency), assuming a 3.15 percent discount rate with "favorable tax credits." Recalculating the same using the formula in Annex 1, with the same 3.15 percent discount rate but no tax credits, gives 19.5 cents/kWh (1984 currency). When the cost could not be calculated because of insufficient data, the relevant references, together with quoted costs, were given in the table in Annex 6 but were not plotted on the graphs.

Figure 3.3 shows the calculated costs of electricity production from parabolic trough (solar/natural gas hybrid and solar only operation), parabolic dish, and central receiver solarthermal technologies. The costs are for large-scale generation of about 50 kW and upward. Discussion on the costs of electricity production by each of the individual technologies follows.

Cost of electricity generation from parabolic trough solar-thermal technology

Figure 3.4 shows the calculated costs of electricity production using parabolic trough technology (Annex 6, entries I to 16). The highlighted values are based on the Luz plants. The following may be noted from the graph:

a. The current calculated cost for electricity production (solar with 25 to 30 percent natural gas) at the SEGS plants varies between 11 to 14 US¢/kWh (1990) due to the difference in quoted capital costs.

b. The solar only values are higher, ranging from 13 to 20 US¢/kWh (1990), because of the lower capacity factor. The outlier based on data from entry 16, of 11 US¢/kWh ( 1990), stems from an usually low quoted capital cost compared with the other data and does not appear to be representative (Walton and Hall 1990).

c. As the natural gas contribution is increased to 50 percent, the cost decreases further because of the increase in the capacity factor.

d. The cost of electricity production is expected to decrease further to 10 to 14 US¢/kWh (1990) for solar only use by 2005. Thus, correspondingly, the cost of electricity production from the natural gas hybrid will also decrease. This decrease is caused by a decrease in capital costs and by a decrease in operating and maintenance costs, which constitute as much as 15 to 25 percent of the total cost of electricity production (Kearney and Price 1992; U.S. DOE 1992b). The U.S. Department of Energy is currently working on a project with the SEGS plants' owners and operators to reduce the latter, not only to make these plants more economical, but also with a view to using the lessons learned in other solar-thermal technologies, especially central receivers (U.S. DOE 1992b).

e. Economies of scale in manufacture should result in further lowering of costs. This is illustrated in the dispersion of costs in 1991 in Figure 3.4. Entries 11 to 13 in Annex 6 are for 200 MW plants; all others (entries 1 to 10, 14 to 16) are for 80 MW plants. As can be seen, this results in a 30 percent decrease in costs from the 80 MW plants. (Compare entries 8 and 10 with 11 and 13, respectively). The coatings for the 200 MW plants are based on technology proven on an experimental scale only, but one that Luz felt confident enough to offer to prospective clients in 1991 (IFC data 1991).

Figure 3.3. Calculated Cost d Electricity from Large Scale Solar-Thermal Technology

Figure 3.4. Calculated Cost of Electricity from Parabolic Trough Solar-Thermal Technology

Cost of electricity from parabolic dish solar-thermal technology

Figure 3.5 shows the expected decrease in costs over time for electricity generation from the parabolic dish system. The data points were obtained from only two sources (De Laquil and others 1993; U.S. DOE 1992c) and an all predicted costs. As shown by its predictions for 1998, the DOE expects the cost to fail faster than do De Laquil and others. The DOE's reasoning is based on an increase in production for a utility-scale market. The range quoted (5.8 to 20.3 US¢/kWh in 1990 dollars) is for a distributed system, whereas the single value (6.5 US¢/kWh in 1990 dollars) is for a modular system. This may be as a result of their projects for the development and commercialization of 5 kW and 25 kW dishes, as described in the section on parabolic dish technology.

Entries 26 to 28 in Annex 6 give more projections for costs from the U.S. DOE in terms of increasing market. The decrease in cost appears to stem both from improved technology and from increased production. According to the U.S. DOE (1992c) the cost of dishes has fallen from $1500/m2 in 1978 to $150/m2 in 1992. In comparison, Charters (1987) quotes $300/m2 in 1987, and De Laquil and others (1993) use a figure of $300 to &500/m2 in 1995-2000, with the cost decreasing to $150 to 200/m2 in 2005-10.

Figure 3.5. Calculated Cost of Electricity from Parabolic Dish Solar-Thermal Technology

Cost of electricity generation from central receiver solar-thermal technology

Figure 3.6 shows the costs of electricity production using central receiver technology (data from Annex 6). As can be seen, the predictions for the costs of electricity generation have decreased substantially in the last few years and are expected to decrease further. The outlier on the graph, 5.6 US¢/kWh (1990 dollars) in 1998, is the latest projection by the U.S. DOE, on the basis of current projects in progress. Entries 37 to 40 in Annex 6 show the expected decrease in costs with increasing market, according to the U.S. DOE. Thus, the main difference between the other predictions and that of the DOE is a faster expansion of the market, with a 200 MW plant being set up as early as 1998, compared with 2005, according to De Laquil and others ( 1993).

Figure 3.6. Calculated Cost of Electricity from Central Receiver Solar-Thermal Technology

Let us look at reasons for this expected decrease. First, capital costs of central receiver solar-thermal power plants from several sources are given in Table 3.1 and Figure 3.7. As can be seer:, the costs do not show as marked a trend as the decrease in cost of electricity. This is because recent studies have taken account of storage capability for plants. Storage adds to capital costs but improves the utilization of the turbogenerator, and, since it costs much less than the latter, it reduces generation costs.

Table 3.1. Capital Costs of Central Receiver Plants

	Quoted capital cost		Capital cost
Reference	($/kWp)	($/kWp, 1990)	Year	Notes
Palz (1978)	930 (1975)	2257	1975
International Energy Agency (1987)	2900 (1984)	3645	1986	Study In 1986 U.S. DOE Five Year Research and Development Plan Overnight construction cost. (i.e. ignoring interest during construction); based on data from Luz
Walton and Hall (1990)	2100 (1990)	2100	1990
International Energy Agency (1987)	2200 (1984)	2765	1995	Study in 1986 U.S. DOE Five Year Research and Development Plan
De Laquil and others (1993)	3000-4000 (assume 1992)	2804-3738	1995
U.S. DOE (1992c)	2961 (1990)	2961	1998
De Laquil and others (1993)	3000-2225 (assume 1992)	2079-2804	2005
De Laquil and others (1993)	2900-3500	2710-3271	2005
	(assume 1992)	2010
De Laquil and others (1993)	1800-2500	1682-2336	200
	(assume 1992)	2010

Figure 3.7. Capital Cods of Central Receiver Solar-Thermal Plants

The capability for storage has a significant effect on the capacity factor and decreases the overall cost of electricity production markedly. For example, entry 30 in Annex 6 utilizes a capacity factor of 17 percent, compared with entry 31, which has a capacity factor of 70 percent. Both are originally from U.S. Department of Energy studies, the former in 1986 and the latter in 1992. The details are compared in Table 3.2. Note the higher capital cost of the more recent estimate but the lower overall cost of electricity production because of the higher capacity factor.

The single largest cost component of the system is the heliostat field. In the United States, this exhibits an "86 percent" learning curve, with costs decreasing by 14 percent as production doubles (International Energy Agency 1987). The U.S. DOE ( 1992c) describes a tenfold decrease in costs from $1,000/m2 in 1978 to just over $100/m2 today, with costs expected to decrease to between $65/m2 and 85/m2 on mass production of the new stretched membrane heliostats currently under development. De Laquil and others ( 1993) use similar values for heliostat costs in their estimates. It appears, however, that the time scale for achieving these technological improvements and for setting up the larger scale plants is shorter in the case of the U.S. DOE's costings.

Table 3.2. Comparison of Two Estimates for a Large-Scale Central Receiver Plant

Entry from		Capital		O&M	Capacity	Calculated	Quoted cost
		Size	cost	costs	factor	cost US¢/
Annex 6	Reference	(MW)	(S/kWp)	($/yr)	(%)	kWh(1990)	US¢/kWh	Year
30a	International Energy Agency (1987)	100	2,200b	3000000b	17c	23	11.5b		1995
				(0.02 cents/ kWh)
31	U.S. DOE (1992c)	200	2,961d	625464000 d,e	70	5.6	—		1998
				(0.51 cents/ kWh)

^a From study In 1986 by U.S. DOE, Five Year Research and Development Plan..

^b Costs are in 1984 dollar'.
^c Capacity factor derived from quoted value for electricity production of 148 GWh/yr.
^d Costs are in 1990 dollars.
^e O&M costs derived from quoted value of 0.51 cents/kWh.

Figure 3.8. Load Dispatching Capability of Central Receiver Plants

The future of solar-thermal electric energy

Parabolic trough systems have so far been the most thoroughly tested of the solarthermal technologies. The Luz plants have demonstrated and continue to demonstrate the capability of the technology to deliver power reliably to the grid. The capital costs, however, are high (13 to 20 US¢/kWh in 1990 dollars for solar-only operation). Some cost reductions are considered possible from economies of scale if the approach is expanded and if Direct Steam Generation (DSG) technology is developed and tested successfully. Costs are predicted to fall to 10 to 14 US¢/kWh (1990) by 2005.

The parabolic dish appears lo be best suited for remote application, because of its modular nature. However, the technology still has not been commercialized. Costs are predicted to be in the range 7 to 14 US¢/kWh (1990) by the year 2010.

Central receiver systems (with thermal storage) have considerable promise. Cost projections are as low as 7 to 12 US¢/kWh (1990) in the next 10 years or so, and 5 to 10 US¢/kWh (1990) in the long term. However, the technology has still not been commercialized, and therefore the most important factor affecting future prospects is the time scale in which initial test facilities can be set up and operational problems can be highlighted and investigated. Some confirmation of the ability to reduce costs is the tenfold decrease just mentioned in the unit costs of heliostats over the period 1978 to 1992. Test facilities (with no storage capability) have been operated successfully, but these were never scaled up to commercial size. This may be because of the high capital cost, which stems from the inherently greater size of the plants, compared with the other solar-thermal technologies.