National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Nexant Parabolic Trough Solar 

Power Plant Systems Analysis 

Task 3: Multiple Plants at a Common 

Location 

January 20, 2005 — December 31, 2005 

B. Kelly 

Nexant, Inc. 

San Francisco, California 

Subcontract Report 

NREL/SR-550-40164 

July 2006 
Nexant Parabolic Trough Solar 

Power Plant Systems Analysis 

Task 3: Multiple Plants at a Common 

Location 

January 20, 2005 — December 31, 2005 

B. Kelly 

Nexant, Inc. 

San Francisco, California 

NREL Technical Monitor: H. Price 

Prepared under Subcontract No. LDC-5-55014-01 

Subcontract Report 

NREL/SR-550-40164 

July 2006

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
This publication was reproduced from the best available copy 

Submitted by the subcontractor and received no editorial review at NREL

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Contents 

1. Introduction............................................................................................................................................ 1 

2. Task 1 Results........................................................................................................................................ 3 

3. Plant Configurations and Collector Field Arrangements....................................................................... 4 

3.1 One 250 MWe Plant......................................................................................................................... 4 

3.2 Four 250 MWe Plants with Separated Power Blocks...................................................................... 4 

3.3 Four 250 MWe Plants with Adjacent Power Blocks ....................................................................... 4 

4. Capital Costs ........................................................................................................................................ 12 

4.1 One 250 MWe Plant....................................................................................................................... 12 

4.2 Multiple Plants at a Common Site ................................................................................................. 13 

4.3 Capital Cost of Four 250 MWe Plants with Separated Power Blocks........................................... 16 

4.4 Four 250 MWe Plants with Adjacent Power Blocks ..................................................................... 17 

5. Construction Schedule ......................................................................................................................... 20 

6. Project Financing ................................................................................................................................. 21 

7. Operation and Maintenance Costs ....................................................................................................... 22 

8. Levelized Energy Costs ....................................................................................................................... 25 

9. Summary.............................................................................................................................................. 26 

10. References.......................................................................................................................................... 27 

- - iii
Task 3 

Multiple Plants at a Common Site 

Task 3 

Multiple Plants at a Common Location 

1. Introduction 

Nine Solar Electric Generating Station (SEGS) parabolic trough solar power plants, ranging in capacity from 

13.5 MWe to 89 MWe, are located in the southern California desert. Each of the plants is located adjacent 

to at least one other plant: SEGS I and II at Daggett; SEGS III through VII at Kramer Junction; and SEGS 

VIII and IX at Harper Lake. The plants are co-located to take advantage of common site permits, 

evaporation ponds, access to utility transmission lines, and sharing of the operation and maintenance staff. 

However, each of the projects was privately financed and constructed separately from the adjoining projects. 

In principle, additional benefits could have accrued if the individual plants were owned, financed, installed, 

and operated under one organization. An analysis was conducted to determine the economic benefits to 

locating multiple plants at a common site with a common owner. The potential economic advantages 

included the following: 

• Capturing the discounts available from the purchase of larger numbers of mirrors, heat collection 

elements, drives, structural steel elements, and sensors 

• Capturing the discounts available from the multiple purchase of the large Rankine cycle components, 

including the turbine-generator, condenser, steam generator, and main transformer 

• Using the final design engineering, the equipment specifications, and the procurement packages from the 

first plant on the subsequent plants 

• Reducing the permit schedule and expense by applying for, and submitting the environmental impact 

statement for, all of the plants with the first 

• Sharing the operation and maintenance staff and facilities 

• Securing a learning curve benefit on the construction labor schedule and hours by retaining one 

constructor for the series of plants 

• Reducing interest during construction expenses due to a reduction in the construction schedule 

• Simultaneously financing multiple plants to reduce the debt origination and lenders’ fees. 

Task 3 is the final task in an overall study, which includes the following tasks: 1) Preferred Plant Size and 

Capital Cost Estimate; 2) Dry Heat Rejection; and 3) Multiple Plants at a Common Location. 

The results from Task 1 are briefly discussed in Section 2 below. 

- - 1
Task 3 

Multiple Plants at a Common Site 

The analyses for Task 3 were conducted as follows: 

1) Using the preferred plant identified in Task 1 (Ref. 1), conceptual plant arrangements were developed for 

the following multiple plant options: a) four collector fields, each delivering thermal energy to a 

Rankine cycle located at the center of each collector field; and b) four collector fields, each delivering 

thermal energy to a central site where the four Rankine cycles are co-located. 

 The plant arrangements were based on the equipment designs developed during Task 1, and on additional 

field piping calculations to determine the relative capital costs and parasitic energy demands for the two 

multiple plant options. 

2) Using the capital cost estimate from Task 1 as the baseline, differential capital costs for the two multiple 

plant options were estimated for each of the elements above. The estimates were based on Bechtel 

experience with the construction of multiple plants at a common site, historical cost information from the 

Federal Power Commission, and the experience of Solar Millennium and RW Beck with the design, 

financing, and construction of multiple plants at a common site. 

- - 2
Task 3 

Multiple Plants at a Common Site 

2. Task 1 Results 

As described in the Task 1 report, Preferred Plant Size, the optimum size for a parabolic trough project with 

thermal storage was determined to be in the range of 200 to 250 MWe. For the purposes of Task 1, a 

detailed capital cost estimate was developed for a nominal 250 MWe plant with 3 hours of thermal storage. 

The basic characteristics of the plant were as follows: 

Table 1 

Nominal 250 MWe Plant Characteristics 

 Gross plant rating, MWe 265 

 Net plant capacity, MWe 232 

 Thermal storage capacity, hours 3 

 Collector area, m2 1,960,097 

 Annual plant output, MWhe 740,980 

 Capital cost 1, $ 1000 878,600 

 Operation and maintenance cost, $ 1000 11,780 

 Levelized cost of energy 2, $/kWhe 0.137 

 Notes: 

 1) Overnight construction cost 

 2) 2008 dollars; first year of plant operation 

- - 3
Task 3 

Multiple Plants at a Common Site 

- - 4

3. Plant Configurations and Collector Field Arrangements 

3.1 One 250 MWe Plant 

Using the field piping arrangement of the SEGS VIII / IX plants as a reference, a potential collector field 

arrangement for a single 250 MWe plant was developed, as illustrated in Figure 1. The power block was 

located at the center of the collector field, with the heat transport fluid distribution headers arranged in an ‘H’ 

pattern. Four East-West headers supplied cold fluid to, and collected hot fluid from, 8 collector field 

segments. Each segment consisted of 87 loops, each of which contains 6 solar collector assemblies. 

The header pipe diameters were selected using an optimization program developed in an earlier study for 

NREL (Ref. 2). The largest pipe sizes required were the 54 in. cold and hot headers running North and 

South to and from the power block. One of the four cold headers is labeled as (A) in Figure 1; there was also 

a similar arrangement of hot return headers (not shown). The East-West headers, labeled as (B) in the figure, 

were 36 inches in diameter at the center of the field, decreasing to 6 inches in diameter at the edge of the 

field. 

At the design point, the pressure loss through the collector field was 17.4 bar, and the heat transport fluid 

pump power requirement was 17,400 kWe. 

3.2 Four 250 MWe Plants with Separated Power Blocks 

Potential arrangements for four 250 MWe with separated power blocks are shown in Figures 2A (East-West 

configuration) and 2B (North-South). Each of the four plants essentially replicated the 250 MWe plant 

above. Thus, the header sizes and the collector field pressure loss are also the same. However, the heat 

transport fluid pump power requirement was four times as high, at 69,700 kWe. 

The North-South arrangement may offer some modest economic advantages over the East-West layout; i.e., 

the perimeter fence should be shorter, and travel times between collector fields may be slightly less. 

However, for the purposes of the study, the differences were believed to small enough that both 

configurations offered the same performance and economics. 

3.3 Four 250 MWe Plants with Adjacent Power Blocks 

An East-West arrangement for four 250 MWe plants with adjacent power blocks is illustrated in Figure 3A, 

and a North-South arrangement is shown in Figure 3B. The heat transport fluid header lengths and pressure 

losses for the North-South layout were much lower than the East-West arrangement, and the former was 

selected for the analysis. 
- 5 - 

2630 m

A

B

Power Block

Collector field segment

87 loops of 6 collectors each (typica

Figure 1 250 MWe Plant Arrangement 

Partial Field Piping Shown 

 Legend:  A) 54 in. cold header to semi-field (typical of 2)  B) 36 in. cold header to quadrant (typical of 4) 
A

B

A

B

A

B

A

B

Power Blo

Power Block Power BloPower Block

Figure 2A 4 x 250 MWe Plant East-West Arrangement 

Separate Power Blocks 

Partial Field Piping Shown 

- 6 - 

 Legend:  A) 54 in. cold header to semi-field (typical of 2)  B) 36 in. cold header to quadrant (typical of 4) 
Task 3 

Multiple Plants at a Common Site 

- 7 - 

 B) 36 in. cold header to quadrant (typical of 4) 

 Legend: 

 A) 54 in. cold header to semi-field (typical of 2) 

Power Block

Power Block

Power Block

Power Block

A

B

B

A

2630 m

300 m Collector field segment

87 loops of 6 collectors each (typical of 32)

Figure 2B 4 x 250 MWe Plant North-South Arrangement 

Separate Power Blocks 

Partial Field Piping Shown 
- 8 - 

A

Power BlockPower Block

Power BlockPower Block

87 lo

BC

Figure 3A 4 x 250 MWe East-West Plant Arrangement 

Partial Field Piping Shown 

Adjacent Power Blocks 

 A) 72 in. cold header to 16 segments; 3 required per semi-field  C) 60 in. cold header to 4 segments  B) 72 in. cold header to 8 segments  Legend: 
Task 3 

Multiple Plants at a Common Site 

2630 m

300 m

D

C

Power Block

Power Block

Power Block

Power Block

Collector field segment

87 loops of 6 collectors each (typical of 32)

A

A

B

B

C

D

E

E

E

E

Figure 3B 4 x 250 MWe North-South Plant Arrangement 

Adjacent Power Blocks 

Partial Field Piping Shown 

 Legend: 

 A) 60 in. cold header to 16 segments; 3 required per semi-field 

 B) 72 in. cold header to 12 segments; 2 required per semi-field 

 C) 72 in. cold header to 8 segments 

 D) 60 in. cold header to 4 segments 

 E) 36 in. cold header to 2 segments 

- 9 - 
Task 3 

Multiple Plants at a Common Site 

Locating the four Rankine cycles at one location offered the following benefits: 

• Plant Availability The default plant availability within Excelergy is 94.0 percent, based on the 

following: a 10-day scheduled outage every year; an extended 5-week scheduled outage every 10 years 

(3.5 days per year); and an unscheduled forced outage rate of 2.3 percent (8.4 days per year). For the 

adjacent plant option, the 4 steam generators can, during the winter months, supply steam to 1, 2, 3, or all 

of the Rankine cycles. As such, each Rankine cycle can, in series, be removed from service during the 

winter months for scheduled maintenance without reducing the plant electric output. In principle, it 

should be possible to eliminate both the 10 day scheduled outage and the 3.5 day extended scheduled 

outage from the availability calculations. The flexibility in Rankine cycle operation should also allow a 

reduction in the unscheduled forced outage rate of perhaps 10 percent. With these changes, the plant 

availability increased by 3.7 percentage points to a new value of 97.9 percent.

• Annual Solar-to-Electric Efficiency The Rankine cycle efficiency, as a function of load, is modeled in 

Excelergy as follows: 

 Nth = .Qtpb / Qdesign 

 Nel = T2EPLF0 + T2EPLF1 * Nth + T2EPLF2 * Nth

2

 + T2EPLF3 * Nth

3

 + T2EPLF4 * Nth

4

 The default values for the coefficients are -0.0377, 1.0062, 0.0763, -0.0448, and 0.0000. 

 For the adjacent plant option, it should be possible to isolate one or more Rankine cycles during the 

winter months. The Rankine cycles which remain in operation then operate at higher loads and at higher 

thermal-to-electric efficiencies. In the limit, the improved efficiencies can be modeled in Excelergy by 

selecting coefficients of 0, 1, 0, 0, and 0 for the equation above. Running Excelergy with the latter 

coefficients increased the net plant output by about 0.36 percent. The modest improvement can be traced 

to a comparison of Nel for the two sets of coefficients. For loads above 40 percent, the two efficiency 

values were almost identical; only when the load fell below 25 percent was there a marked advantage to 

isolating a Rankine cycle. Since the annual winter energy delivered with the Rankine cycle operating at 

loads below 25 percent was rather limited, the annual improvement in energy output was also modest.

• Operation and Maintenance Costs A modest improvement in the efficiency of the operation and 

maintenance staff should accrue if all of the thermal storage and the Rankine cycle equipment are in one 

location. An analysis of the potential savings is described in Section 7, Operation and Maintenance 

Costs. 

Compared to the separated power block option, the adjacent plant option required additional field piping 

headers to distribute the heat transport fluid to the collector loops. The incremental piping, and the 

associated design point pressure losses, are presented in Table 2. In principle, the primary North-South 

headers to and from the power blocks could use a 102 inch diameter line for both the cold fluid and the hot 

fluid. However, the required wall thicknesses would be about 1.5 inches for the cold line, and 1.1 inches for 

the hot. For pipe sizes of 42 inches and above, the heaviest commercial wall thickness is 1.00 inch. For the 

purposes of the study, three 60 inch diameter lines for the cold fluid, and two 84 inch diameter lines for the 

hot fluid, were selected to retain the use of commercial pipe sizes and wall thicknesses. 

- 10 - 
Task 3 

Multiple Plants at a Common Site 

Table 2 

Incremental Field Piping for 

Four 250 MWe Plants with Adjacent Power Blocks 

 Total Pressure 

Header Diameter, in. length 1, m loss, bar

 A) To/From 16 segments 2

 Cold: 3 required 3 60 4,500 0.73 

 Hot: 2 required 3 84 3,000 0.20 

 B) To/From 12 segments 

 Cold 72 3,000 0.43 

 Hot 72 3,000 0.48 

 C) To/From 8 segments 

 Cold 4 54 1,500 0.74 

 Hot 4 54 1,500 0.74 

 D) To/From 4 segments 

 Cold 4 54 1,500 0.21 

 Hot 4 54 1,500 0.22 

 ------ 

 Total 3.45 

 Notes: 

 1) Includes an allowance for an expansion loop every 70 m 

 2) Segments are shown in Figure 3 

 3) Multiple lines required to limit wall thickness to maximum commercial value of 1.00 in. 

 4) Incremental pressure loss relative to separated power block option 

The design point power requirement for the heat transport fluid pumps was 80,200 kWe, which was about 

15 percent higher than the separated power block option. 

- 11 - 
Task 3 

Multiple Plants at a Common Site 

4. Capital Costs 

4.1 One 250 MWe Plant 

The estimate developed in Task 1 for the 250 MWe project was an overnight construction cost. The estimate 

included all of the costs associated with land, vendor equipment, bulk materials, field labor, field 

supervision, engineering, procurement, construction management, startup, checkout, and contractor fees. 

To assemble a complete capital cost, several expenses associated with conducting the project must be added 

to the overnight cost. The additional expenses included project development costs, working capital, interest 

during construction, and debt origination fees (Ref. 3, 4, 5, 6, and 7). The major components of the 

overnight construction cost, together with the development of the project related expenses for the 250 MWe 

project, are summarized in Table 3. 

Table 3 

250 MWe Plant Capital Cost Estimate 

2005 $1,000 

Overnight construction cost

Total installed material and labor 831,423

Engineering, procurement, and home office 14,662

Construction management and field procurement 5,756

Startup and checkout 2,640

Contractor fee 24,110

----------

Total overnight construction cost 878,590

Project related expenses

Development costs (5.0 percent) 43,929

Development fees (2.0 percent) 17,572

Owner's general and administrative (2.5 percent) 21,965

Constructor mobilization (1.0 percent) 8,786

Initial spare parts (0.6 percent) 5,272

Owner's contingency (1.5 percent) 13,179

Initial working capital (2.5 percent) 21,965

Interest during construction (2/3 year; 8 percent) 46,858

Lender initiation fee (1.5 percent) 13,179

Lender closing fee (0.5 percent) 4,393

Funded debt reserves (6 month debt service) 12,081

----------

Total project related expenses 209,178

Total capital cost 1,087,768

The project related expenses added approximately 24 percent to the overnight construction costs. 

- 12 - 
Task 3 

Multiple Plants at a Common Site 

4.2 Multiple Plants at a Common Site 

The Federal Power Commission, now the Department of Energy, maintains a database of performance and 

cost information on power plants constructed in the United States. Data on 175 conventional gas fired, 

combustion turbine, and combined cycle plants, were reviewed for the study. The plants, constructed 

between 1950 and 1980, included both single and multiple units at a total of 55 sites in the South and the 

Southwest. 

Of the 55 sites, at least 46 had more than on unit at the same site. After adjusting the costs to a common 

price level, the unit costs, in $/kWe, for subsequent units were compared with the unit costs for the initial 

units. The results for 80 plants, in which the subsequent unit was the same capacity as the initial unit, are 

summarized in Table 4. As shown, the average unit cost for the subsequent units was about 13 percent less 

than the cost of the initial unit. 

The statistics indicate there is a meaningful cost savings to locating multiple plants at a common site. The 

factors which might contribute to the reduction of costs include the following: 

• Procurement of multiple quantities, capturing the discounts available from the purchase of two or more 

identical components, such as the turbine-generator, condenser, steam generator, and main transformer. 

Unfortunately, traditional procurement processes of bidding or negotiating a lump sum price for 

equipment make it impossible to accurately measure the effect of volume purchasing. Nonetheless, an 

examination of purchase orders for large components indicates that 5 to 10 percent of the order is tied to 

delivery of certified vendor prints. As such, it would be reasonable to assume that some fraction of this 

cost could be avoided in the purchase of multiple quantities. 

• Reusing the final design engineering, the equipment specifications, and the procurement packages from 

the first plant on each of the subsequent plants. 

Two important qualifications should be placed on the estimated savings of 13 percent for subsequent units. 

First, details of the capital costs for each plant in the DOE database are not maintained. As such, it is not 

possible to determine what, if any, pre-investments in the subsequent plant were included with the initial 

plant. Such pre-investments might include the land for the second plant, soils analyses, geologic studies, site 

preparation, fences, raw water supplies, operator control room, warehouse facilities, evaporation pond, and 

grid connections. An intuitive estimate from a Bechtel cost engineer suggests that one-third of the savings in 

the subsequent plants are due to the pre-investment in the first plant. 

Second, the projects listed in Table 3 go back several years. As such, the plants are likely owned and 

financed by the local utility. This arrangement is somewhat different than today, in which many projects are 

owned and financed privately, and in which the only source of revenue is energy sales to the local utility. In 

general, the financial resources of a utility are greater than a private source. Further, a utility may be willing 

- 13 - 
Task 3 

Multiple Plants at a Common Site 

Table 4 

Historical Cost Data on Multiple Plants 

Capacity, Unit cost, Commercial Adjusted to 1970

Station - Unit State Utility MWe $/kWe Operation price, $/kWe Change

Agua Fria 1 AZ SRP 106 108 57 166

Agua Fria 2 AZ SRP 106 88 57 135 -19%

Bertron 1 TX HLP 165 89 56 146

Bertron 2 TX HLP 165 80 58 119 -19%

Bertron 3 TX HLP 220 80 59 116

Bertron 4 TX HLP 220 65 60 93 -20%

Braunig 1 TX SAPS 225 89 66 111

Braunig 2 TX SAPS 255 63 68 71 -36%

Clark 1 TX HLP 42 61 47 138

Clark 2 TX HLP 42 61 47 138 0%

Clark 3 TX HLP 86 63 50 143

Clark 4 TX HLP 86 71 51 147 3%

Coughlin 1 LA CLE 9 138 48 312

Coughlin 2 LA CLE 9 112 48 254 -19%

Greens Bayou 1 TX HLP 73 77 49 174

Greens Bayou 2 TX HLP 73 63 49 143 -18%

Greens Bayou 3 TX HLP 111 68 53 130

Greens Bayou 4 TX HLP 111 68 53 130 0%

Hill 1 TX CPL 75 96 54 177

Hill 2 TX CPL 75 79 56 130 -27%

Jones 1 TX SPS 244 102 71 96

Jones 2 TX SPS 244 111 74 82 -14%

Kyrene CT 1 AZ SRP 53 103 71 97

Kyrene CT-2 AZ SRP 53 103 72 92 -5%

Kyrene CT 3 & 4 AZ SRP 2x60 93 73 79

Laredo 1 TX CPL 35 114 51 236

Laredo 2 TX CPL 39 114 55 198 -16%

Lee 1 TX SWEP 34 91 50 206

Lee 2 TX SWEP 34 91 50 206

Lee 3 TX SWEP 34 91 52 182 -12%

Leon Creek 1 TX SAPS 31 103 50 233

Leon Creek 2 TX SAPS 32 144 52 288 23%

Lieberman 1 LA SWEP 26 128 47 290

Lieberman 2 LA SWEP 26 89 49 202 -30%

Nichols 1 TX SWPS 106 133 60 190

Nichols 2 TX SWPS 106 117 63 160 -16%

Nine Mile Point 4 LA LPL 748 76 71 71

Nine Mile Point 5 LA LPL 763 63 73 53 -25%

North Texas 1 TX BEP 20 106 58 157

North Texas 2 TX BEP 20 106 58 157 0%

Ocatillo 1 AZ APS 115 122 60 174

Ocatillo 2 AZ APS 115 96 61 136 -22%

- 14 - 
Task 3 

Multiple Plants at a Common Site 

Table 4 (Continued) 

Historical Cost Data on Multiple Plants 

Capacity, Unit cost, Commercial Adjusted to 1970

Station - Unit State Utility MWe $/kWe Operation price, $/kWe Change

Paint Creek 1 TX WTU 36 114 53 217

Paint Creek 2 TX WTU 36 94 54 174 -20%

Patterson 1 LA NOPS 40 125 48 283

Patterson 2 LA NOPS 40 102 48 231 -18%

Plant x 2 TX SWPS 103 98 53 187

Plant x 3 TX SWPS 106 105 55 183 -2%

Reeves 1 NM PSNM 50 150 59 217

Reeves 2 NM PSNM 51 125 60 179 -18%

Riverside 1 LA GSU 40 108 49 245

Riverside 2 LA GSU 46 108 50 245 0%

Riverside 1 OK PSO 463 116 74 86

Riverside 2 OK PSO 463 114 76 70 -19%

Sabine 1 TX GSU 230 111 62 153

Sabine 2 TX GSU 230 91 62 126 -18%

Saguaro 1 AZ APS 99 125 54 231

Saguaro 2 AZ APS 99 99 55 172 -25%

Saguaro CT1 AZ APS 53 98 72 87

Saguaro CT2 AZ APS 53 106 73 90 3%

Seminole 3 OK OGE 522 98 75 64

Seminole 4 OK OGE 522 98 75 64 0%

Southwestern 1 OK PSO 80 106 52 212

Southwestern 2 OK PSO 80 80 54 148 -30%

Sweatt 1 MS MPC 46 125 51 259

Sweatt 2 MS MPC 46 103 53 196 -24%

Tuttle 2 TX SAPS 100 87 56 143

Tuttle 3 TX SAPS 105 98 61 138 -3%

Watson 1 MS MPC 81 145 57 223

Watson 2 MS MPC 79 120 60 171 -23%

Webster 1 TX HLP 110 87 54 161

Webster 2 TX HLP 110 71 54 131 -18%

Wharton 3 TX HLP 102 53 74 39

Wharton 4 TX HLP 102 53 74 39 0%

Wharton CC3 TX HLP 317 189 74 140

Wharton CC4 TX HLP 329 173 75 113 -19%

Wharton CT2-4 TX HLP 3x51 129 71 121

Wharton CT5-7 TX HLP 3x51 129 72 115 -5%

Wilkes 2 TX SWEP 360 61 70 61

Wilkes 3 TX SWEP 342 61 71 57 -6%

Average -13%

- 15 - 
Task 3 

Multiple Plants at a Common Site 

to commit future funds if the utility believes both the first and the subsequent projects will eventually be 

incorporated in the utility’s rate base. As a result, a utility may be more willing than a private source to 

commit to the necessary resources in the first project which will yield cost reductions on the subsequent 

plants. These resources could include the pre-investments noted above, and may also involve vendor 

purchase orders for two turbine-generators, two cooling towers, and so on. 

For the purposes of the study, a net reduction in the capital cost for the second plant was estimated to be twothirds of the 13 percent savings cited above, or 9 percent. A savings of 9 percent was also consistent with the 

cost projections developed for the two 50 MWe AndaSol projects, in which the second plant was estimated 

to be 10 percent less expensive than the first. The savings were derived from the following: vendor 

purchase orders which included an option for the purchase of identical components on the second project; 

construction of a switchyard with sufficient capacity for up to 5 projects; incorporating an intentional lag 

between the two construction schedules which allowed the craft labor to finish the activities on the first 

project, and then move to the second; and reusing the engineering and procurement documents from the first 

project on the second. 

4.3 Capital Cost of Four 250 MWe Plants with Separated Power Blocks 

As shown in Table 1, the overnight construction cost for a 250 MWe plant was estimated to be 

$878.6 million. Of this total, $831.4 million was the total field cost for installed material and labor, and 

$47.2 million were the indirect costs for engineering, procurement, construction management, startup, 

checkout, and contractor fee. 

For the purposes of the study, the total field cost for installed material and labor on the second plant was 

estimated to be 9 percent less than the first, or $756.6 million. However, no further reductions in the total 

field cost were credited for the third and the fourth projects, based on the following: 

• No data were identified for three or more identical plants at a common site to substantiate further cost 

reductions. 

• Most, if not all, of the potential cost reductions due to pre-investment or multiple purchase orders were 

likely have been achieved with the second project. 

• The third and fourth plants in a series will start construction at least 2, and perhaps as much as 4 years, 

after the first. As such, the benefits to be achieved in 2 to 4 years from an investment today may be more 

than offset by potential changes in regulatory requirements, transmission line access, interest charges on 

committed funds, and changes in equipment designs and pricing. The last item is of particular relevance 

for solar facilities, as design improvements and cost reductions are likely to take place in the trough 

structure, the heat collection elements, the mirrors, and the heat transport fluid. For example, committing 

a future project to an indirect thermal storage system when the industry may, in the long run, be switching 

to an inorganic heat transport fluid could be counterproductive. 

- 16 - 
Task 3 

Multiple Plants at a Common Site 

The indirect costs for the second, third, and fourth plants were estimated to be 8 percent less than of the costs 

for the first, based on the following: 

• Much of the engineering and procurement documentation from the first plant could be used on the 

subsequent projects, reducing the costs by 25 percent. 

• The remaining indirect costs for construction management, field procurement, startup, checkout, and 

contractor fee involved primarily field labor, with a minimum of documentation. As such, discounts on 

the second and subsequent plants were believed to be, at most, minor. 

The anticipated progression in the overall plant expenditure is shown in Table 5. 

As with the direct and the indirect costs, some of the project related expenses were also expected to decrease 

for the second, third, and fourth plants. For example, the project development costs could decrease by as 

much as 75 percent if the land, the power purchase agreement, and the land use permits for the first plant 

were applicable to the subsequent plants. Similarly, mobilization costs could decline by 50 percent if the 

same constructor was used for all of the projects. However, discounts on the lenders fees were not 

anticipated for the subsequent projects, as discussed below in Section 6. 

For the single 250 MWe plant, the project related expenses added approximately 24 percent to the overnight 

construction costs. For the four 250 MWe plants, the average of the related expenses decreased to 20 percent 

of the overnight costs. 

4.4 Four 250 MWe Plants with Adjacent Power Blocks 

With adjacent power blocks, the additional collector field piping listed in Table 2 was required. Based on the 

unit costs in the piping optimization model, the total field cost for the incremental piping was estimated to be 

$75 million. To this was added an incremental cost of $7 million for the additional heat transport fluid pump 

capacity of 10,600 kWe. The economic effect of the additional piping and the heat transport pump capacity 

was fairly significant, representing an increase in the collector field piping cost of about 35 percent, and an 

increase in the unit plant cost of $88/kWe. 

As shown in Figure 3, the incremental field piping was sufficiently segregated that only those headers 

associated with each 250 MWe collector field needed to be installed with each collector field. Thus, the 

incremental costs were distributed over the four plants. The anticipated progression in the overall plant 

expenditure is shown in Table 6. 

As with the four plant option above, the average of the related expenses decreased to 20 percent of the 

overnight costs. 

- 17 - 
Task 3 

Multiple Plants at a Common Site 

Table 5 

Progression of Overnight Construction Costs 

4 x 250 MWe Plants with Separated Power Blocks; 2005 $1,000 

Overnight construction cost Plant 1 Plant 2 Plant 3 Plant 4

Total installed material and labor 831,423 756,595 756,595 756,595

Engineering, procurement, and home office 14,662 13,562 13,562 13,562

Construction management and field procurement 5,756 5,324 5,324 5,324

Startup and checkout 2,640 2,442 2,442 2,442

Contractor fee 24,110 21,950 21,950 21,950

---------- ---------- ---------- ----------

Total overnight construction cost 878,590 799,872 799,872 799,872

Project related expenses

Development costs (5.0 / 1.25 / 1.25 / 1.25 percent) 43,929 9,998 9,998 9,998

Development fees (2.0 percent) 17,572 15,997 15,997 15,997

Owner's general and administrative (2.5 / 2.0 / 2.0 / 2.0 percent) 21,965 15,997 15,997 15,997

Constructor mobilization (1.0 / 0.5 / 0.5 / 0.5 percent) 8,786 3,999 3,999 3,999

Initial spare parts (0.6 percent) 5,272 4,799 4,799 4,799

Owner's contingency (1.5 percent) 13,179 11,998 11,998 11,998

Initial working capital (2.5 percent) 21,965 19,997 19,997 19,997

Interest during construction (2/3 year; 8 percent) 46,858 42,660 42,660 42,660

Lender initiation fee (1.5 percent) 13,179 11,998 11,998 11,998

Lender closing fee (0.5 percent) 4,393 3,999 3,999 3,999

Funded debt reserves (6 month debt service) 12,081 10,998 10,998 10,998

---------- ---------- ---------- ----------

Total project related expenses 209,178 152,442 152,442 152,442

Total capital cost 1,087,768 952,315 952,315 952,315

- 18 - 
Task 3 

Multiple Plants at a Common Site 

Table 6 

Progression of Overnight Construction Costs 

4 x 250 MWe Plants with Adjacent Power Blocks; 2005 $1,000 

Overnight construction cost Plant 1 Plant 2 Plant 3 Plant 4

Total installed material and labor 875,812 800,984 800,984 800,984

Engineering, procurement, and home office 14,662 13,562 13,562 13,562

Construction management and field procurement 5,756 5,324 5,324 5,324

Startup and checkout 2,640 2,442 2,442 2,442

Contractor fee 25,362 23,202 23,202 23,202

---------- ---------- ---------- ----------

Total overnight construction cost 924,232 845,515 845,515 845,515

Project related expenses

Development costs (5.0 / 1.25 / 1.25 / 1.25 percent) 46,212 10,569 10,569 10,569

Development fees (2.0 percent) 18,485 16,910 16,910 16,910

Owner's general and administrative (2.5 / 2.0 / 2.0 / 2.0 percent) 23,106 16,910 16,910 16,910

Constructor mobilization (1.0 / 0.5 / 0.5 / 0.5 percent) 9,242 4,228 4,228 4,228

Initial spare parts (0.6 percent) 5,545 5,073 5,073 5,073

Owner's contingency (1.5 percent) 13,863 12,683 12,683 12,683

Initial working capital (2.5 percent) 23,106 21,138 21,138 21,138

Interest during construction (2/3 year; 8 percent) 49,292 45,094 45,094 45,094

Lender initiation fee (1.5 percent) 13,863 12,683 12,683 12,683

Lender closing fee (0.5 percent) 4,621 4,228 4,228 4,228

Funded debt reserves (6 month debt service) 12,708 11,626 11,626 11,626

---------- ---------- ---------- ----------

Total project related expenses 220,044 161,141 161,141 161,141

Total capital cost 1,144,276 1,006,656 1,006,656 1,006,656

- 19 - 
Task 3 

Multiple Plants at a Common Site 

5. Construction Schedule 

In principle, a learning curve benefit on the construction labor schedule and craft hours can be achieved if 

one constructor is used on a series of two or more plants. In practice, not all of the theoretical benefits are 

often realized. If the subsequent unit is constructed at the same time as, or shortly after, the first, some of the 

learning curve benefits are offset by efficiency losses arising out of the execution of a larger project. The 

efficiency losses include the need for additional coordination and supervision, and an increased requirement 

for skilled labor. The timing of the project in relation to other work in the area is important. If there are 

other projects under construction at the same time, the increase in demand for craft labor will raise the 

prevailing wage rates, and eliminate some of the potential savings. Similarly, if the additional unit is 

completed some period of time after the initial project, there are likely no learning curve benefits, as perhaps 

a different constructor, and certainly a different labor pool, would be used. 

For the purposes of the study, the construction schedule on the second, third, and fourth plants should be 

somewhat shorter than the first plant. However, the shorter schedules were not believed to provide a 

measurable reduction in the construction cost. 

- 20 - 
Task 3 

Multiple Plants at a Common Site 

6. Project Financing 

In principle, simultaneously financing multiple plants should allow a reduction in the debt origination and 

closing costs. Some of the savings can be derived by distributing the bank costs over a larger debt quantity, 

and by avoiding the due diligence activities on replicated plants. However, in practice, each plant is likely to 

be financed separately, and a reduction in fees probably will not occur. The reasons are as follows: 

• It is anticipated that a different group of banks will provide the debt financing for each project. Each bank 

defines its limit to exposure in any particular area, including solar projects, and the limits are likely to be 

low enough that an individual bank will not be in a position to provide funds to more than one or two 

projects. 

• Parabolic trough technology is not yet fully mature, and the number of banks interested in financing a 

developing industry is limited. As such, it is not necessary for the interested banks to discount their fees 

to attract those in search of solar project financing. 

For the purposes of the study, the baseline bank fee structure used in the New Mexico Concentrating Solar 

Plant Feasibility Study (Ref. 6) was adopted for each of the four plants in the series. 

- 21 - 
Task 3 

Multiple Plants at a Common Site 

7. Operation and Maintenance Costs 

Operation and maintenance cost estimates were developed using a spreadsheet model prepared by NREL, 

with minor modification developed by Nexant for the larger plant sizes in Task 3. The NREL model was 

based on detailed assessments of the operating expenses at the SEGS III through VII plants at Kramer 

Junction. The NREL costs were extrapolated to the larger plant sizes based on the following approach: 

• Administration costs were largely independent of the capacity of the plant, and were weakly dependent on 

the number of plants at a site. 

• Solar field operating and maintenance costs were essentially proportional to the size of the collector field. 

• Rankine cycle operating costs were essentially proportional to the number of the number of cycles, and 

varied with the power rating based on exponents ranging from 0.5 to 0.7. 

For the study, operation and maintenance estimates were developed for 4 cases, as follows: 

 1) SEGS III through VII, as a point of reference 

 2) The baseline 250 MWe plant 

 3) A 940 MWe (net) plant, with four separated 250 MWe power blocks 

 4) A 940 MWe (net) plant, with four adjacent 250 MWe power blocks. 

The results are summarized in Table 7. 

As might be expected, Case 1 had the highest unit costs, in both $/kWe-year and $/m2

-year. The results can 

be traced to the operating complexities associated with 5 Rankine cycles, and the corresponding high staffing 

requirement of 0.78 personnel per MWe. 

The operating costs for Case 2 were about one-third lower than Case 1. Most of the benefit was derived 

from the smaller staff needed to operate and maintain one, as opposed to five, Rankine cycles. A review of 

the remaining data showed most of the balance in the operating costs were essentially proportional to the 

collector field area. 

The unit operating costs for Case 3 were about 20 percent lower than for Case 2. Although Case 3 had four 

Rankine cycles, as opposed to one for Case 2, the ability to distribute the Administration and the Power Plant 

Maintenance costs over 940 MWe, rather than 235 MWe, was the principal source of the savings. 

- 22 - 
Task 3 

Multiple Plants at a Common Site 

Table 7 

Operation and Maintenance Cost Estimates 

Case 1234

Capacity at site, MWe 150 235 940 940

Capacity per plant, MWe 30 235 235 235

Plants at site 5144

Total solar field size, m2 1,094,000 1,962,000 7,849,000 7,849,000

Staff

 Administration 18 12 16 16

 Solar Field Maintenance 19 32 120 108

 Solar Field Operations 12 22 86 77

 Power Plant Operations 48 11 39 32

 Power Plant Maintenance 20 14 26 23

------ ------ ------ ------

 Total 117 90 287 257

 Staff / MWe 0.78 0.38 0.31 0.27

Annual Costs, $ 1,000

 Administration 1,430 1,030 1,350 1,350

 Solar Field Maintenance 1,470 2,400 8,900 8,060

 Solar Field Operations 790 1,420 5,690 5,120

 Power Plant Operations 3,590 850 2,920 2,390

 Power Plant Maintenance 1,570 1,130 2,050 1,820

 Service Contracts 280 330 580 550

 Water Treatment 170 310 1,230 1,210

 Power Block Spare Parts 1,040 720 2,870 2,870

 Solar Field Spare Parts 1,410 2,540 10,140 10,140

 Miscellaneous 550 750 1,970 1,870

 Capital Equipment 220 300 600 570

--------- --------- --------- ---------

 Total 12,520 11,780 38,300 35,950

Unit Costs

 $ / kWe-yr 83 50 41 38

 $ / m2

-yr 11,400 6,000 4,900 4,600

- 23 - 
Task 3 

Multiple Plants at a Common Site 

The unit operating costs for Case 4 were about 6 percent lower than for Case 3. The savings were derived in 

the following areas: 

1) The labor efficiency for the solar field maintenance staff, excluding the manager and the foreman, and 

the solar field operations staff were both estimated to improve by 10 percent. The improvements were 

derived by sharing warehouse and maintenance facilities, and by using a smaller contingency in the 

number of maintenance workers required to handle the peak, as opposed to the average, work load in the 

collector fields. 

2) The power plants operations staff was reduced by 8 percent by sharing the senior operators, the control 

room operators, and the plant equipment operators among the plants, and by locating the control 

operations for the four plants in one location. The number of staff for operations manager, assistant 

operations manager, and chemical technician remained unchanged. 

3) The power plants maintenance staff was reduced by 8 percent by sharing the mechanics, the HTF 

mechanics, and the mechanics helpers among the plants, and by locating the warehouse and the 

maintenance facilities in one location. The number of staff for maintenance manager, plant maintenance 

foreman, electricians, instrumentation and control technicians, HTF mechanics helpers, machinist/ 

welder, warehouse clerk, and vehicle mechanic remained unchanged. 

4) The annual expenses for plant service contracts, capital equipment for solar field maintenance, and 

miscellaneous expenses were each estimated to decrease by 5 percent due to the improvements in labor 

productivities noted above. The water treatment costs were also estimated to decrease by 5 percent due 

the higher annual thermal-to-electric conversion efficiencies for the Rankine cycles. However, as 

discussed in Section 3.3, the increase in the plant availability of 3.7 percent raised the annual output by a 

like amount, which resulted in a net reduction in the water treatment cost of about 1 percent. 

- 24 - 
Task 3 

Multiple Plants at a Common Site 

8. Levelized Energy Costs 

Levelized energy costs were calculated to determine the economic benefits to multiples plants at a common 

site. The calculations were based on the following: 

• For a Barstow location, the 4 x 250 MWe plant with the separated power blocks had a net annual electric 

energy production of 2,963,900 MWhe. The plant arrangement with adjacent power blocks incurred a 

penalty of about 15 percent in the annual energy required for the heat transport fluid pumps, which 

increased the overall parasitic energy demand by 4 percent. However, the improvements in the plant 

availability and the winter thermal-to-electric conversion efficiencies resulted in net energy production 

increase of about 4.5 percent, to a new value of 3,098,500 MWhe. 

• From the Excelergy analyses in Task 1, a nominal fixed charge rate of 10.25 percent was calculated, based 

the default financial parameters, and on an optimum debt fraction and equity fraction of 0.60 and 0.40, 

respectively. 

• For the purposes of Task 3, levelized energy costs were calculated based on the following simplified 

approach: 

energy Annual kWhe ,production

rate)(Capi charge (Fixed cost) tal maintenanc and (Operation cost) e $/kWhe cost,energy Levelized + =

The results of the calculations are presented in Table 8. 

Table 8 

Levelized Energy Costs 

4 x 250 MWe plant 4 x 250 MWe plant

1 x 250 MWe Separated power blocks Adjacent power blocks

Equivalent annual capital cost, $1,000 111,496 404,333 413,900

Annual operation and maintenance cost, $1,000 11,780 38,300 35,950

Annual energy production, MWhe 740,980 2,963,920 3,098,532

Levelized energy cost, $/kWhe 0.166 0.149 0.145

Savings due to multiple plants, percent Base -10.2% -12.7%

Replicating the 250 MWe plant, and keeping the power block at the center of each respective collector field, 

yielded a nominal 10 percent reduction in the levelized energy cost. Locating the power blocks at a common 

location offered an additional 2.5 percent reduction in the energy cost. 

- 25 - 
Task 3 

Multiple Plants at a Common Site 

9. Summary 

In principle, installing multiple plants at a common site should offer a reduction in the levelized energy cost 

of 10 to 12 percent. In this study, the savings were allocated approximately as follows: 

• 55 percent to the purchase of greater quantities of equipment and bulk materials 

• 1 percent to the reuse of the final design and procurement documents 

• 25 percent to the reuse of one organization for project development, and one organization for project 

construction 

• 20 percent to the sharing of the operation and maintenance staff among the plants. 

It should be noted the potential for savings is not automatic. If the full benefits are to be realized, one 

organization must assume the responsibility for maintaining the same equipment vendors and the same 

contractors throughout the projects. Further, the equipment designs must be sufficiently mature that the 

benefits to replicating the design are at least as great as switching to an improved approach. 

- 26 - 
Task 3 

Multiple Plants at a Common Site 

10. References 

1) “Task 1 - Preferred Plant Size”, Technical Support for Parabolic Trough Solar Technology, Nexant, Inc., 

NREL Subcontract Number LDC-5-55014-01, October 2005 

2) “Parabolic Trough Solar System Piping Model - Interim Report”, USA Trough Initiative, Kearney & 

Associates, NREL Contract No. AAA-2-32432-01, July 10, 2002 

3) Telephone conversation with Larry Stoddard, Black & Veatch Energy, December 8, 2005 

4) Telephone conversation with Brandon Owens, Cambridge Energy Research, December 8, 2005 

5) Telephone conversation with Rainer Aringhoff, Solar Millennium LLC, December 9, 2005 

6) Stoddard, L., (Black & Veatch, Overland Park, Kansas), “New Mexico Concentrating Solar Plant 

Feasibility Study, Draft Final Report”, prepared for New Mexico Energy, Minerals and Natural 

Resources Department, February 9, 2005 

7) Telephone conversation with Mike Henderson, RW Beck, December 12, 2005 

- 27 - 
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1. REPORT DATE (DD-MM-YYYY)

July 2006 

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Subcontract Report 

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January 20, 2005 – December 31, 2005 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

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4. TITLE AND SUBTITLE

Nexant Parabolic Trough Solar Power Plant Systems Analysis: 

Task 3: Multiple Plants at a Common Location 

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NREL/SR-550-40164 

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CP06.1301 

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B. Kelly 

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Nexant, Inc. 

101 Second St., 11th Floor 

San Francisco, CA 94105-3672 

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LDC-5-55014-01 

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Subcontract report by Nexant, Inc., regarding a system analysis of multiple solar parabolic trough plants at a common 

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concentrating solar power; solar parabolic trough; solar; solar thermal electricity 

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