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 1: Preferred Plant Size 

January 20, 2005 — December 31, 2005 

B. Kelly 

Nexant, Inc. 

San Francisco, California 

Subcontract Report 

NREL/SR-550-40162 

July 2006 
Nexant Parabolic Trough Solar 

Power Plant Systems Analysis 

Task 1: Preferred Plant Size 

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-550-40162 

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

NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any 

warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or 

usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, process, or service by 

trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States government or any agency thereof. The views and 

opinions of authors expressed herein do not necessarily state or reflect those of the United States 

government or any agency thereof. 

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy 

and its contractors, in paper, from: 

U.S. Department of Energy 

Office of Scientific and Technical Information 

P.O. Box 62 

Oak Ridge, TN 37831-0062 

phone: 865.576.8401 

fax: 865.576.5728 

email: mailto:reports@adonis.osti.gov

Available for sale to the public, in paper, from: 

U.S. Department of Commerce 

National Technical Information Service 

5285 Port Royal Road 

Springfield, VA 22161 

phone: 800.553.6847 

fax: 703.605.6900 

email: orders@ntis.fedworld.gov

online ordering: http://www.ntis.gov/ordering.htm

Printed on paper containing at least 50% wastepaper, including 20% post-consumer waste
Contents 

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

2. Rankine Cycle Models........................................................................................................................... 2 

3. Solar Multiples....................................................................................................................................... 6 

4. Collector Field Piping Models............................................................................................................... 7 

5. Annual Energy Calculations ................................................................................................................ 10 

6. Economic Analysis .............................................................................................................................. 12 

7. Commercial Turbine-Generators ......................................................................................................... 15 

8. Conceptual Cost Estimate.................................................................................................................... 17 

Heat Transport System Flow Diagram ................................................................................................. 17 

Items Included in the Estimate.............................................................................................................. 17 

Items Excluded from the Estimate........................................................................................................ 18 

Labor Rates and Indirect Costs............................................................................................................. 20 

Single Line Diagrams ........................................................................................................................... 20 

Sales Tax............................................................................................................................................... 20 

Freight................................................................................................................................................... 20 

Escalation.............................................................................................................................................. 23 

Contractor’s Fee.................................................................................................................................... 23 

Cost Estimate Summary and Details..................................................................................................... 23 

9. Observations ........................................................................................................................................ 24 

Annual Plant Availability ..................................................................................................................... 24 

Upper Limits on Plant Sizes ................................................................................................................. 25 

Appendix 1: Details of 250 MWe Plant Total Field Cost Estimate.......................................................... 26 

- - iii
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Task 1 

Preferred Plant Size 

1. Introduction 

The Rankine cycles for commercial parabolic trough solar projects range in capacity from 13.5 MWe at the 

Solar Electric Generating Station I (SEGS I) plant, to a maximum of 89 MWe at the SEGS VIII / IX plants. 

The series of SEGS projects showed a consistent reduction in the levelized energy cost due to a combination 

of improvements in collector field technology and economies of scale in both the Rankine cycle and the 

operation and maintenance costs. Nonetheless, the question of the optimum Rankine cycle capacity remains 

an open issue. The capacities of the SEGS VIII / IX plants were limited by Federal Energy Regulatory 

Commission and Public Utility Regulatory Policy Act requirements to a maximum net output of 80 MWe. 

Further improvements in the Rankine cycle efficiency, and economies of scale in both the capital and the 

operating cost, should be available at larger plant sizes. 

An analysis was conducted to determine the effect of Rankine cycle capacities greater than 80 MWe on the 

levelized energy cost. The study was conducted through the following steps: 

• Three gross cycle capacities of 88 MWe, 165 MWe, and 220 MWe were selected. 

• Three Rankine cycle models were developed using the GateCycle program. The models were based on 

single reheat turbine cycles, with main steam conditions of 1,450 lbf/in2

 and 703 °F, and reheat steam 

conditions of 239 lbf/in2

 and 703 °F. The feedwater heater system consisted of 5 closed heaters and 

1 open deaerating heater. The design condenser pressure was 2.5 in. HgA. 

• The optimization function within Excelergy was used to determine the preferred solar multiple for each 

plant. Two cases were considered for each plant: 1) a solar-only project without thermal storage, and 2) a 

solar-fossil hybrid project, with 3 hours of thermal storage and a heat transport fluid heater fired by 

natural gas. 

• For each of the 6 cases, collector field geometries, heat transport fluid pressure losses, and heat transport 

pump power requirements were calculated with a field piping optimization model. 

• Annual electric energy outputs, capital costs, and annual operating costs were calculated for each case 

using the default methods within Excelergy, from which estimates of the levelized energy costs were 

developed. The plant with the lowest energy cost was considered the optimum. 

- - 1
- - 2

The GateCycle flow diagram is shown in Figure 1. A list of the calculated cycle efficiencies, together with a 

comparison with efficiency data from existing plants, is shown in Table 1. 

Task 1

Preferred Plant Size and Capital Cost Estimate 

2. Rankine Cycle Models 

The Rankine cycle design for the 88 MWe, 165 MWe, and 220 MWe plants closely followed the designs 

developed by Fichtner for the 55 MWe AndaSol project in Spain, and by Luz for the 88 MWe SEGS VIII / 

IX projects. The cycle is a conventional, single reheat design; the live steam pressure and temperature are 

1,450 lbf/in2

 and 703 °F, respectively, and the reheat steam pressure and temperature are 269 lbf/in2 and 

703 °F, respectively. Extraction steam pressures, terminal temperature differences, and drain cooler 

approach temperatures for the 3 low pressure, and the 2 high pressure, closed feedwater heaters were derived 

from the AndaSol heat balance. The operating conditions for the 1 open deaerating feedwater heater also 

duplicated the AndaSol data. 

High pressure turbine and intermediate/low pressure turbine expansion efficiencies in GateCycle were 

calculated using the General Electric Spencer-Cotton-Cannon correlations. In addition, the low pressure 

turbine efficiency was based on an exhaust loss at the entrance to the condenser of 5 Btu/lbm, which was 

achieved by selecting an annulus area which yielded an exhaust velocity in the range of 500 to 550 ft/sec. 

For the two smaller plants, the agreements between the calculated and the published efficiencies were 

excellent.

Table 1 

Calculated and Published Rankine Cycle Efficiencies 

 Gross cycle GateCycle Published 

output, MWe calculation efficiency

 55 0.375 0.375 1

 88 0.377 0.377 2

 165 0.379 N/A 

 220 0.380 N/A 

 Notes: 

 1) Solar Millennium AndaSol heat balance, with steam chest leakage to 

condenser equal to 0.01 percent of live steam flow rate 

 2) SEGS IX heat balance, with steam chest leakage rate equal to 1.95 percent 

of live steam flow rate 
Preferred Plant 

- 3 - 

MODEL:CASE:POWER:HR:EFF:

80PTDC80PTDC 87.99 0.00 0.00

ST1

CN

FWH4

FDWPMP

ST2

FWH5

485.59 79259

466.421206.7

P T

W H

202.91 34863

664.711356.0

P T

W H

DA1 FWH0

FWH1

 3.26

 17100

144.701053.7

P T

W H

IPST

268.30

675690

407.261163.0

P T

W H

 89.65

 34037

489.451275.0

P T

W H

 75.00

606790

454.141258.8

P T

W H

FWH2

 44.11

 33106

361.141216.5

P T

W H

 16.93

 42516

219.231149.8

P T

W H

 25.00

4.95E6

1500.0369.63

P T

W H

 25.00

4.95E6

1084.2256.81

P T

W H

VRHTR

VSUHTR

STMGEN

V2

 89.65

 34037

489.451275.0

P T

W H

 89.65

770434

320.02290.41

P T

W H

 3.4741Exh loss

1460.1

770434

455.03436.39

P T

W H

135.00

622775

137.50105.76

P T

W H

1470.1

770434

374.04348.99

P T

W H

1450.5

754948

703.401294.8

P T

W H

239.29

675690

703.401373.9

P T

W H

S4

S7

S8

S11

S12

S15

S16

S26

S27

S28

S32

S33

S1

S18

S19

S22

S30

S6

S13

S14

S3

S31

S21 S39

S25

S38

88 MWe Rankine Cycle with Dry Heat Rejection 

Figure 1 GateCycle Flow Diagram 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Overall expansion efficiencies, together with the gross cycle efficiencies, are shown in Figure 2. The overall 

expansion efficiencies were calculated on a weighted average approach, as follows: 

 MW)output, IPoutput LPoutput (HP

output, (HP output, (IP)efficiency MW)(HP output, (LP)efficiency MW)(IP )efficiency MW)(LP

+ +

+ +

The gross cycle efficiency improved by about 130 parts in 10,000 as the plant capacity increased from 

50 MWe to 150 MWe. However, improvements in the cycle efficiency for plant sizes above 150 MWe 

were likely to be modest, with an asymptotic efficiency of perhaps 38.1 percent. 

0.860

0.865

0.870

0.875

0.880

0.885

0.890

50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230

Gross Turbine Output, MWe

Isentropic Expanison Efficiency

0.374

0.375

0.376

0.377

0.378

0.379

0.380

0.381

Gross Cycle Efficiency

Isentropic expansion efficiency Gross cycle efficiency

Figure 2 Turbine Expansion and Gross Cycle Efficiencies as a Function of Capacity 

To help determine the source of the efficiency improvements with increasing capacity, isentropic expansion 

efficiencies were also calculated separately for the high pressure and the intermediate/low pressure turbine 

sections. The results are illustrated in Figure 3. 

The increase in cycle efficiency was primarily a function of an increase in the high pressure turbine 

efficiency. The improvement can be traced to an increase in the length of the blades. The effect of nonuniform aerodynamic loads at the end of the blades decreased with length, and the (essentially) fixed steam 

leakage past the end of the blades represented a smaller portion of the total flow past the blade. 

- 4 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

0.850

0.855

0.860

0.865

0.870

0.875

0.880

0.885

0.890

0.895

50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230

Gross Turbine Output, MWe

Isentropic Expanison Efficiency

HP LP/IP Overall

Figure 3 Turbine Section Expansion Efficiencies as a Function of Capacity 

- 5 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

3. Solar Multiples 

The optimization function within Excelergy was used to determine the preferred solar multiple for each of 

the 6 cases. The collector field design was based on the LS-2+ collector, with 6 solar collector assemblies in 

a loop. The annual performance calculations, capital cost estimates, and operating cost estimates were based 

on the default Excelergy methods. The results of the optimization calculations are shown in Table 2. 

Table 2 

Results from Excelergy Solar Multiple Optimization Calculations 

 Optimum Collector Field 

Plant Capacity and Design Solar Multiple Area, m2

 88 MWe 

 - Solar-only 1.45 534,230 

 - Hybrid with thermal storage 1.80 662,144 

 165 MWe 

 - Solar-only 1.45 1,000,740 

 - Hybrid with thermal storage 1.80 1,241,520 

 220 MWe 

 - Solar-only 1.45 1,331,812 

 - Hybrid with thermal storage 1.80 1,651,598 

The variations in the Rankine cycle efficiency and the heat transport fluid pump power demand with plant 

capacity were not strong enough to cause the optimum solar multiple to be other than 1.45 for all of the 

solar-only plants, and 1.80 for all of the hybrid plants with thermal storage. 

- 6 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

4. Collector Field Piping Models 

An optimization model was run for each of the 6 cases to determine the parasitic power demand of the heat 

transport fluid pumps. The results of the optimizations are listed in Table 3 for the solar-only plants, and in 

Table 4 for the hybrid plants with thermal storage. 

The unit pump power demand, in kWe/m2

, increased from a value of 0.00688 for the 88 MWe solar-only 

plant, to a value of 0.00827 for the 220 MWe hybrid plant with thermal storage. The effect can be traced to 

the pressure losses in the cold header and the hot header; as the collector field became larger, the lengths of 

the primary headers increased. Similarly, the annual unit thermal losses (kWht/m2

), the annual unit pump 

energy demand (kWhe/m2

), and the unit capital cost ($/m2) all increased with field area due to the increase in 

header lengths. 

Table 3 

Collector Field Piping Model Results for Solar-Only Plants 

88 MWe 165 MWe 220 MWe

Collector area, m

2 541,786 1,015,848 1,354,464

Number of LS-2+ loops, each 192 360 480

Unit area, m

2

/MWe 6,157 6,157 6,157

Pressure losses, bar

 - HTF pump outlet piping 0.20 0.17 0.19

 - Cold header 1.96 2.78 3.22

 - Loop 8.37 8.28 8.24

 - Hot header 2.05 3.16 3.43

 - HTF inlet piping 0.18 0.19 0.19

 - Total 12.77 14.58 15.28

HTF pump power, kWe 3,729 7,653 10,538

Unit pump power, kWe / m

2 0.00688 0.00753 0.00778

Unit annual losses

 - Thermal, kWht / m

2 46.6 49.2 50.9

 - Pumping, kWhe / m

2 11.1 11.7 11.9

Piping capital costs, $

 - Collector field $12,507,459 $25,483,798 $35,789,690

 - Steam generator area $992,960 $1,931,914 $2,434,411

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

 - Total $13,500,419 $27,415,712 $38,224,102

Unit capital cost, $ / m

2 $23.09 $25.09 $26.42

- 7 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Table 4 

Collector Field Piping Model Results for Hybrid Plants with Thermal Storage 

88 MWe 165 MWe 220 MWe

Collector area, m

2 654,658 1,241,592 1,670,506

Number of LS-2+ loops, each 232 440 592

Unit area, m

2

/MWe 7,439 7,525 7,593

Pressure losses, bar

 - HTF pump outlet piping 0.21 0.17 0.20

 - Cold header 2.05 3.26 3.64

 - Loop 8.83 8.54 8.34

 - Hot header 2.27 3.26 4.01

 - HTF inlet piping 0.18 0.19 0.21

 - Total 13.54 15.42 16.41

HTF pump power, kWe 4,826 9,903 13,819

Unit pump power, kWe / m

2 0.00737 0.00798 0.00827

Unit annual losses

 - Thermal, kWht / m

2 47.5 50.5 53.0

 - Pumping, kWhe / m

2 12.1 12.5 12.5

Piping capital costs, $

 - Collector field $15,502,121 $32,392,281 $46,754,547

 - Steam generator area $1,246,061 $2,370,909 $2,942,457

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

 - Total $16,748,182 $34,763,190 $49,697,004

Unit capital cost, $ / m

2 $23.68 $26.09 $27.99

The influence of the collector field area on the electric power demand of the heat transport fluid pump is 

illustrated in Figure 4. The curve is an extremely shallow parabola; thus, the parasitic energy demand of the 

pumps did not have a strong influence on the preferred plant size. 

The pump power demand for the larger plants is in the multi-megawatt range. As such, starting the pumps 

must be coordinated with the local utility to prevent voltage and frequency upsets to the local grid. To some 

extent, these restrictions may have a minor detrimental effect on the annual plant availability, but a 

quantitative analysis has yet to be performed. 

- 8 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

3,000

5,000

7,000

9,000

11,000

13,000

15,000

500,000 700,000 900,000 1,100,000 1,300,000 1,500,000 1,700,000

Field area, m2

HTF pump power, kWe 

Figure 4 Heat Transport Fluid Pump Power Demand 

as a Function of Collector Field Area 

- 9 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

5. Annual Energy Calculations 

The annual net electric energy delivered by each of the six plant designs was calculated by the Excelergy 

computer program. The plant site was assumed to be Barstow, California, and the input parameters for the 

model were the default Excelergy values. One exception to the default parameters was the parasitic power 

demand of the heat transport fluid pumps; here, the demand was based on a polynomial curve fit of the data 

in Figure 4. 

The results of the annual energy calculations are shown in Table 5 for the solar-only plants, and in Table 6 

for the hybrid plants with thermal storage. 

Table 5 

Annual Performance of Solar-Only Plants 

88 MWe 165 MWe 220 MWe

Nominal gross plant rating, MWe 88.0 165.0 220.0

Isentropic expansion efficiency 0.866 0.874 0.876

Gross Rankine cycle efficiency 0.377 0.379 0.380

Excelergy inputs

 - SfArea, m

2 541,786 1,015,848 1,354,464

 - Edesign, MWe 88.5 166.9 223.0

 - NetCap, MWe 80.5 151.3 201.8

 - Qdesign, MWt 234.7 440.0 586.7

 - PTTmax, MWt 340.3 506.0 674.7

 - PTTmin, MWt 35.2 66.0 88.0

 - SfPar, MWe 0.144 0.270 0.360

 - ChtfPar, MWe 3.729 7.653 10.538

 - BopPar, MWe 2.183 4.053 5.375

 - CtPar, MWe 1.500 2.813 3.750

 - PbFixPar, MWe 0.443 0.835 1.115

Excelergy outputs

 - Qdni, MWh 1,491,262 2,793,491 3,717,653

 - Egr, MWhe 222,685 419,682 560,317

 - Epar, MWhe 22,201 43,079 58,114

 - Enet, MWhe 200,484 376,603 502,203

 - Net efficiency 0.134 0.135 0.135

Calculated efficiencies

 - Egr / Qdni 0.1493 0.1502 0.1507

 - Epar / Egr 0.0997 0.1026 0.1037

The gross solar-to-electric efficiency increased with plant size, as shown by the ratio Egr / Qdni. The effect 

can be traced to the increase in Rankine cycle efficiency with capacity. However, the net solar-to-electric 

- 10 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Table 6 

Annual Performance of Hybrid Plants with Thermal Storage 

88 MWe 165 MWe 220 MWe

Nominal gross plant rating, MWe 88.0 165.0 220.0

Isentropic expansion efficiency 0.866 0.874 0.876

Gross Rankine cycle efficiency 0.377 0.379 0.380

Excelergy inputs

 - SfArea, m

2 654,658 1,241,592 1,670,506

 - Edesign, MWe 88.5 166.9 223.0

 - NetCap, MWe 79.4 149.0 198.5

 - Qdesign, MWt 234.7 440.0 586.7

 - PTTmax, MWt 269.9 506.0 674.7

 - PTTmin, MWt 35.2 66.0 88.0

 - SfPar, MWe 0.174 0.330 0.444

 - ChtfPar, MWe 4.826 9.903 13.819

 - BopPar, MWe 2.183 4.053 5.375

 - CtPar, MWe 1.500 2.813 3.750

 - PbFixPar, MWe 0.443 0.835 1.115

Excelergy outputs

 - Qdni, MWh 1,848,325 3,465,609 4,610,310

 - Qgas, MWh 7,496 14,042 18,845

 - Egr, MWhe 276,760 522,265 697,064

 - Epar, MWhe 27,950 54,086 73,051

 - Enet, MWhe 248,809 468,178 624,013

 - Net solar-to-electric efficiency 0.133 0.134 0.134

Calculated efficiencies

 - Egr / Qdni 0.1497 0.1507 0.1512

 - Epar / Egr 0.1010 0.1036 0.1048

efficiency was essentially independent of the plant size. In effect, the increase in gross efficiency was offset 

by the increase in parasitic energy demand, as shown by the ratio Epar / Egr. 

For the hybrid plants, the use of natural gas was limited to the summer peak periods to ensure the revenue 

from the energy sales was sufficient to justify the expense of burning the fuel. With 3 hours of thermal 

storage and a solar multiple of 1.8, the plant can satisfy essentially all of the peak period energy demands 

without requiring the use of the fossil-fired heater. Thus, the annual thermal energy contribution from 

natural gas was less than 0.5 percent of the annual solar energy contribution for each of the three plants. 

- 11 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

6. Economic Analysis 

Levelized energy costs were calculated for each of the six plants using the year-by-year cash flow analysis 

within Excelergy. The capital cost for the plants, together with the annual operation and maintenance costs, 

were developed from the default values in Excelergy. 

The input and the output financial parameters for the solar-only plants, and for the hybrid plants with thermal 

storage, are listed in Table 7 and Table 8, respectively. 

All of the plants were assumed to be built and financed under commercial conditions, as follows: 

• The manufacturing capacities for the solar equipment were sufficiently large that all of the mirrors and the 

heat collection elements could be fabricated, shipped, and assembled within a two-year period for the 

plant engineering, procurement, and construction. 

• The debt interest rate and the required return on equity were independent of the capital cost of the plant. 

Table 7 

Input and Output Financial Parameters for Solar-Only Plants 

88 MWe 165 MWe 220 MWe

Financial parameters - Inputs

 - Capital cost, $ 1000 $267,747 $465,148 $600,039

 (Unit capital cost, $/kWe) $3,314 $3,074 $2,978

 - O & M cost, $ 1000 $4,777 $6,740 $8,118

 (Unit O&M cost, $/MWhe) $24 $18 $16

 - EPC period, years 2.0 2.0 2.0

 - Interest during construction rate 7.0 % ------> ------>

 - Debt interest rate 6.0 % ------> ------>

 - Debt term, years 20 ------> ------>

 - Minimum debt coverage ratio 140 % ------> ------>

 - Return on equity 15 % ------> ------>

 - Effective income tax rate 40 % ------> ------>

 - Investment tax credit 10 % ------> ------>

 - Depreciation period, years 5 ------> ------>

Financial parameters - Outputs

 - Optimum debt fraction 59.7 % 59.7 % 59.7 %

 - Average debt coverage ratio 152 % 152 % 152 %

 - Nominal discount rate 9.6 % 9.6 % 9.6 %

Levelized energy cost, $/kWhe $0.164 $0.146 $0.140

- 12 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Table 8 

Input and Output Financial Parameters for Hybrid Plants with Thermal Storage 

88 MWe 165 MWe 220 MWe

Financial parameters - Inputs

 - Capital cost, $ 1000 $351,427 $617,121 $800,519

 (Unit capital cost, $/kWe) $4,426 $4,145 $4,049

 - O & M cost, $ 1000 $5,355 $7,817 $9,546

 (Unit O&M cost, $/MWhe) $22 $17 $15

 - EPC period, years 2.0 2.0 2.0

 - Interest during construction rate 7.0 % ------> ------>

 - Debt interest rate 6.0 % ------> ------>

 - Debt term, years 20 ------> ------>

 - Minimum debt coverage ratio 140 % ------> ------>

 - Return on equity 15 % ------> ------>

 - Effective income tax rate 40 % ------> ------>

 - Investment tax credit 10 % ------> ------>

 - Depreciation period, years 5 ------> ------>

 - Annual fuel use, 106

 Btu 25,575 47,912 64,298

Financial parameters - Outputs

 - Optimum debt fraction 59.7 % 59.8 % 59.8 %

 - Average debt coverage ratio 152 % 151 % 151 %

 - Nominal discount rate 9.6 % 9.6 % 9.6 %

Levelized energy cost, $/kWhe $0.169 $0.153 $0.147

The levelized energy costs for the six plants are shown in Figure 5. Both the solar-only and the hybrid plants 

with thermal storage showed decreases in the levelized energy costs with increases in the plant capacity. 

However, the lowest energy costs occurred with net plant capacities in the range of 220 to 250 MWe. For 

plant capacities above 250 MWe, the energy costs were likely to remain invariant, for the following reasons: 

• The gross Rankine cycle efficiency increased with plant capacity, but appears to have an asymptotic value 

no larger than 0.381, as illustrated in Figure 2 

• The unit annual parasitic energy demand of the heat transport fluid pumps, in kWhe/m2

, increased as the 

size of the collector field increased 

• As discussed in Section 8, Conceptual Cost Estimate, various plant functions required multiple equipment 

items, even at the largest commercial size, be used. As a result, not all of the theoretical benefits of 

economies of scale could be realized. 

- 13 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

0.12

0.13

0.14

0.15

0.16

0.17

0.18

50 100 150 200 250

Net plant output, MWe

Levelized energy cost, $/kWh

Solar only Hybrid with thermal storage

Poly. (Solar only) Poly. (Hybrid with thermal storage)

Figure 5 Levelized Energy Costs as a Function of Plant Capacity 

- 14 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

7. Commercial Turbine-Generators 

Large steam turbines are fabricated from standard frame sizes, with the mechanical output matched to the 

customer’s needs by adjusting the lengths of the blades, and in some cases, the number of stages. A listing 

of commercial turbines in the size range of interest for large parabolic trough plants is shown in Table 9. 

Table 9 

Commercial Reheat Steam Turbine-Generator Capacities 

 Size Maximum steam 

Manufacturer Model Arrangement range, MWe conditions, lbf/in2 / °F/ °F

 General Electric D series Dual flow HP/IP 125-375 2,400 / 1,050 / 1,050 

 with separate LP 

 Alstom STF25 Separate HP with 210-275 2,540 / 1,004 / 1,004 

 combined IP/LP 

 Siemens SST-3000 Separate HP with 90-250 2,560 / 1,110 / 1,110 

 combined IP/LP 

 Siemens SST-5000 Dual flow HP/IP 120-500 2,560 / 1,110 / 1,110 

 with separate LP 

On a conceptual level, the unit price for the turbine, in $/kWe, should be the lowest at the upper end of the 

power level of a particular frame size. In essence, the fixed costs associated with the casing and the shaft 

could be distributed over the largest number of kilowatts. However, this situation does not seem to be borne 

out in commercial practice. Two senior cost engineers at Bechtel have yet to observe any discontinuous 

change in the cost of a turbine-generator as a function of size. The effect can, perhaps, be traced to 

commercial pricing considerations. For example, the upper end of the Alstom STF25 frame capacity is at 

about the mid-point of the General Electric D series frame capacity. For General Electric to offer a 

250 MWe turbine-generator which is competitive with the Alstom design, the price from General Electric 

may need to be lower than the theoretical value. Correspondingly, at other power levels, Alstom may need 

to adjust their prices to remain competitive with General Electric. 

In terms of Task 1, any potential step changes in the cost of the turbine-generator from moving from one 

frame size to the next is likely to have a minor influence on selection of the preferred plant size. The 

potential penalties or benefits to moving to a different frame size are muted by the ability to change to a 

different turbine vendor. Thus, discontinuities in the levelized energy cost as a function of plant size are 

more likely to be determined by plant components other than the turbine. This is discussed a little more fully 

in Section 9, Observations. Further, the unit cost for the turbine-generator is perhaps $200/kWe. If a 

- 15 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

5 percent advantage in the cost of the turbine-generator could be achieved by selecting a power output at the 

upper end of the frame size, the cost of energy from a plant with thermal storage could be reduced by 

approximately 0.25 percent. For a fully commercial industry, such as turn-key combined cycle power plants, 

such a cost advantage would be meaningful. However, for a maturing solar industry, which has yet to build a 

plant in the range of 150 to 250 MWe, the solutions to moving and storing very large quantities of Therminol 

and nitrate salt may be more expensive than anticipated. As such, the uncertainties in estimating the 

performance and the cost of large heat transport fluid and the thermal storage systems likely has as large an 

influence on the cost of energy as a step-change in the cost of the turbine. 

- 16 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

8. Conceptual Cost Estimate 

For the purposes of the study, a 250 MWe hybrid plant with 3 hours of thermal storage was selected as the 

design offering the lowest cost of energy. A conceptual capital cost estimate for the plant was developed 

from the following sources: 

• Capital cost estimate from the conceptual design of a 100 MWe central receiver power plant developed 

for the Central Receiver Utility Studies. Equipment capacities and materials were modified to reflect the 

changes in the plant size (100 MWe to 250 MWe), the working fluid (nitrate salt to Therminol), and the 

peak working fluid temperature (1,050 °F to 735 °F). 

• Capital cost estimate from the preliminary design of the 880 MWht thermal storage system at the 55 MWe 

AndaSol parabolic trough solar power plants in southern Spain 

• AspenTech Icarus equipment and labor cost data base 

• Bechtel cost estimating experience on similar power plant projects. 

Heat Transport System Flow Diagram 

With a gross plant rating of 265 MWe, a moderate Rankine cycle efficiency of 38 percent, and a limited 

temperature rise of 175 °F across the collector field, the volume flow rates of Therminol, nitrate salt, and 

steam within the plant were fairly large. As such, the flow rates and equipment capacities often required 

multiple equipment items, as outlined in Table 10. 

A schematic heat transport fluid flow diagram is shown in Figure 6. The numbers in the circles are the 

nominal pipe diameters, in inches. Although not shown in the figure, a nitrogen supply and recovery system 

is also required for the thermal storage tank ullage. 

Items Included in the Estimate 

The estimate includes the direct and indirect material and labor costs required to construct the plant, together 

with the costs for engineering, procurement, construction management, startup, and checkout. 

The estimate is arranged in the following system categories: Land; Structures and Improvements; Collector 

System; Thermal Storage System; Heat Transport Fluid System; Electric Power Generation System; and 

Master Control System. The system estimates are further divided into the following cost categories: 

C - Columns and Vessels; D - Tanks; E - Exchangers; G - Pumps and Drivers; K - Compressors and Drivers; 

T - Special Equipment; J - Instrumentation; P - Piping; M - Structural Steel; N - Insulation; P - Electrical; 

Q - Concrete Work; S - Sitework; and X - Painting. 

- 17 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

- 18 - 

Table 10 

Multiple Equipment Items 

250 MWe Plant with 3 Hours of Thermal Storage 

 Thermal Storage System 

 Storage Tanks 

 Height, ft 43 

 Diameter, ft 108 

 Cold tanks, each 3 

 Hot tanks, each 3 

 Oil-to-salt heat exchangers 

 Area, ft2 42,400 

 Number, each 24 

 Heat Transport Fluid System 

 Heat transport fluid pumps 

 Motor power, bhp 3,500 

 Number, each 6 

 HTF pump header diameter, in. 60 

 Expansion vessels 

 Diameter, ft. 14 

 Length, ft. 59 

 Number, each 8 

 Steam generator, number of shells 

 Preheater 2 

 Evaporator 4 

 Superheater 2 

 Reheater 4 

Contingencies are included for each of the principal cost estimate categories. The contingencies are 

allowances for items which have not yet been identified at this stage of the design (for example, the support 

steel for the cable trays), but which are expected to have been identified at the completion of the final design. 

The monies in each of the contingencies are expected to be spent at the completion of the project; thus, the 

funds are not intended to cover additions to the project scope or cost overruns. 

Items Excluded from the Estimate 

Items for which estimates have not been developed include the following: 1) escalation in equipment prices 

and labor costs beyond the second quarter of 2005; 2) interest expenses during final design and construction; 

3) owner’s engineering and construction management; and 4) environmental impact statements. 
Preferred P

- 19 - 

Expansion Vessels

(Typical of 8)

14 ft. dia x 59 ft. long

Heat Transport Fluid Pumps

(Typical of 6)

17,000 gpm, 715 ft. tdh, 3,500 bhp

From

Collector

Field

To

Collector

Field

Hot Salt Tank

Hot Salt

Pump

Oil-to-Salt Heat

Exchangers

Cold Salt

Pump

Cold Salt Tank

Hot Salt Tank

(Typical of 3)

108 ft. dia x 42.5 ft. high

Cold Salt Tank

(Typical of 3)

107 ft. dia x 42.5 ft. high

Hot Salt Pump

(Typical of 3)

14,000 gpm, 200 ft. tdh, 1,750 bhp

Cold Salt Pump

(Typical of 3)

14,000 gpm, 192 ft. tdh, 1,750 bhp

Oil-to-Salt Heat Exchangers

(Typical of 24)

Shell and tube, 42,400 ft2

Reheater

(Typical of 4)

Shell and tube, 29,650 ft2

Kettle Evaporator

(Typical of 4)

Shell and tube, 38,000 ft2

ReheaterReheater

Evaporator 

ReheaterReheater

Evaporator 

60

60

48

48

24 24 24

60 48

34

3434

34

42

2020

2020

2020

48

88

2

18

18

8

2

18

18

8

24

24

Figure 6 250 MWe Plant Heat Transport Fluid Flow Diagram 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

- 20 - 

Labor Rates and Indirect Costs 

Direct labor rates by craft, including payroll additives, for a generic site near a large metropolitan area in the 

Southwest United States were estimated as follows: 

• Mechanical: $38.13 / hr 

• Civil: $26.72 / hr 

• Steel worker: $38.32 / hr 

• Pipe fitter: $42.68 / hr 

• Electrician: $29.42 / hr 

• Instrument technician: $36.85 / hr 

Equipment and material installation costs for items which are distributed among the craft hours were 

estimated as a percentage of the direct wage rates. These distributable costs included equipment rentals, 

welding supplies, construction utilities, labor for material handling, and labor for site clean-up. The 

distributable costs were estimated to be 84.5 percent of the direct labor costs. Thus, the total craft labor rates 

to the project were estimated as follows: 

• Mechanical: $70.35 / hr 

• Civil: $49.30 / hr 

• Steel worker: $70.70 / hr 

• Pipe fitter: $78.84 / hr 

• Electrician: $54.28 / hr 

• Instrument technician: $67.99 / hr 

Single Line Diagrams 

In support of the electric equipment and bulk materials estimates, single line diagrams were developed for 

the heat transport fluid system and the thermal storage system. The single line diagrams are shown in 

Figures 7 and 8. 

Sales Tax 

A sales tax of 7.4 percent is applied to all equipment and bulk material purchases. The tax consists of a state 

sales tax of 5.6 percent and a local sales tax of 1.8 percent. 

Freight 

An allowance for freight, equal to 4 percent of the equipment and materials cost, is included in the estimate. 
Preferred P

- 21 - 

2500 A

From 4.16 kV Bus

4.16 kV, 3 Phase, 60 Hz

300 A

Substation Transformer

200/300 kVA, AA/FA

4.16 kV - 480 V

480 V, 3 Phase, 60 Hz, 300 A

12 kA Motor Control Center

2500 A, 250 MVA Switchgear CLF: Curr

M: ContacVFD: Var

VFD

3500

CLF

M

HTF

Circulation

Pump 1

M

VFD

3500

CLF

M

M

VFD

3500

CLF

M

M

VFD

3500

CLF

M

M

VFD

3500

CLF

M

M

VFD

3500

CLF

M

M

CLF

M

40

Nitrogen

Compressor

HTF

Circulation

Pump 2

HTF

Circulation

Pump 3

HTF

Circulation

Pump 4

HTF

Circulation

Pump 5

HTF

Circulation

Pump 6

250

Startup

Feedwater

Pump

Figure 7 Heat Transport Fluid System - Single Line Diagram 
Preferred P

- 22 - 

1500 A

From 4.16 kV Bus

4.16 kV, 3 Phase, 60 Hz

5000 A

Substation Transformer

4000/5000 kVA, OA/FA

4.16 kV - 480 V

480 V, 3 Phase, 60 Hz, 

1500 A, 150 MVA Switchgear CLF: Current L

M: ContactorVFD: Variable 

Leg

Cold Tank Immersion Heaters

155 kW, Typical of 12

VFD

1750

CLF

M

Cold Salt

Pump 'A'

M

VFD

1750

CLF

M

Cold Salt

Pump 'B'

M

VFD

1750

CLF

M

Cold Salt

Pump 'C'

M

VFD

1750

CLF

M

Hot Salt

Pump 'A'

M

VFD

1750

CLF

M

Hot Salt

Pump 'B'

M

VFD

1750

CLF

M

Hot Salt

Pump 'C'

M

Hot Tank Im

190 kW, 

CLF

M

Heat tracing load center,

complete with 45 feeders each

for 50 kVA transformers

and distribution panels

100

3000 A

Substation Transformer

2500/3000 kVA, AA/FA

4.16 kV - 480 V

CLF

M

Nitrogen

Compressor

Figure 8 Thermal Storage System - Single Line Diagram 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Escalation 

The estimate was prepared using labor, equipment, and material costs current through the first quarter of 

2004. Escalation from the first quarter of 2004 through the fourth quarter of 2005 was estimated to be 

4.5 percent, based on cost indices prepared by Bechtel Corporation for current and planned refinery and 

chemical projects. 

Contractor’s Fee 

The fee for the general contractor is assumed to be 3 percent of the total installed cost, including 

contingencies. 

Cost Estimate Summary and Details 

A summary of the overall estimate is shown in Table 11, and a breakdown of the total field costs by system 

category is shown in Table 12. 

Table 11 

Estimate Summary 

4th Quarter 2005 Overnight Construction Costs 

250 MWe Plant with 3 Hours of Thermal Storage 

Item $1,000 Contingency $1,000

Land 2,671 0% 2,671

Structures and Improvements 3,273 15% 3,763

Collector System 513,420 5% 539,091

Thermal Storage System 94,944 5% 99,691

Heat Transport Fluid System 60,173 10% 66,190

Electric Power Generation System 98,570 10% 108,428

Master Control System 2,270 15% 2,610

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

Total Field Cost 775,321 6% 822,445

Engineering, Procurement, and Home Office 12,750 15% 14,662

Construction Management and Field Procurement 5,005 15% 5,756

Startup and Checkout 2,296 15% 2,640

Contractor Fee (3 percent) 23,861 0% 23,861

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

43,911 7% 46,919

Total Overnight Construction Cost 819,232 6% 869,363

- 23 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Table 12 

Total Field Cost Estimate Summary 

4th Quarter 2005 Costs, Excluding Contingencies 

250 MWe Plant with 3 Hours of Thermal Storage 

Structures and Collector Thermal Heat Electric Power Master

Land Improvements System Storage Transport Generation Control

C - Columns and Vessels 258,110 1,392,430 147,430

D - Tanks 10,756,506 1,366,660

E - Exchangers 11,291,780 21,662,160 9,025,360

G - Pumps and Drives 12,664,020 10,406,390 2,325,010

K - Compressors and Drivers 92,300 19,360 337,950

T - Special Equipment 2,671,050 513,420,000 31,641,402 15,404,070 54,467,900 2,121,560

J - Instrumentation 841,462 456,498

L - Piping 4,170,970 2,545,650 11,639,382

M - Structural Steel 1,461,180 157,080 210,630

N - Insulation 7,876,460 3,296,310 862,674

P - Electrical 4,371,827 931,029 10,722,693

Q - Concrete Work 2,160,343 632,286 1,473,553

S - Site Work 3,262,560 2,735,771 32,731 341,972

X - Painting 27,597 7,840

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

Subtotal 2,671,050 3,262,560 513,420,000 90,349,727 56,943,835 92,921,214 2,121,560

Sales Tax 0 10,027 0 4,594,502 3,229,077 5,649,268 148,000

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

Total Field Cost 2,671,050 3,272,587 513,420,000 94,944,229 60,172,911 98,570,481 2,269,560

Details of the system estimate are shown in Appendix 1. The labor, equipment, and material costs reflect 

fourth quarter 2005 prices. 

The labor costs include both the direct and the distributable costs. 

9. Observations 

Annual Plant Availability 

Multiple equipment items in the heat transport fluid system should improve the annual plant reliability. For 

example, maintenance could be conducted on one steam generator train during the winter. Although main 

steam production would be reduced by 50 percent, the availability of thermal storage should allow the daily 

energy output to remain nearly constant. However, multiple equipment items can have a detrimental effect 

on the plant availability. Although tanks, pumps, and heat exchangers are normally quite reliable, the 

supporting equipment, such as valve actuators, instruments, and sensors, can be problematic. As such, the 

additional support equipment brings additional failure modes. 

The effect of multiple equipment items on the plant availability, although anticipated to be small, is not yet 

incorporated in the results of Section 5, Annual Energy Calculations. 

- 24 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

Upper Limits on Plant Sizes 

Therminol Heat Transport Fluid For plants with thermal storage, a capacity of 200 MWe is likely the upper 

limit for the most economic plant. The requirement for multiple equipment items in both the thermal storage 

and the heat transport fluid systems, together with Rankine cycle efficiencies approaching an asymptotic 

limit of about 38 percent, imply that larger plant sizes will not offer further reductions in the unit capital cost. 

For plants without thermal storage, the largest economic plant size is probably 250 MWe. At this capacity, 

all of the economies of scale in the heat transport fluid system have been realized, and the Rankine cycle 

efficiency has likely reached its peak value. 

Inorganic Heat Transport Fluids For this study, analyses were not conducted for designs based on inorganic 

heat transport fluids. However, the higher collector field outlet temperatures available with the inorganic 

fluids, together with the availability of direct, two-tank thermal storage systems, considerably reduces the 

volumes of fluids which must be circulated and stored. As such, the plant capacities at which equipment 

economies of scale are no longer available should be higher than the plants using Therminol. On a 

conceptual level, the upper limit on the plant capacities may be in the range of 250 to 300 MWe for plants 

with thermal storage, and perhaps 350 MWe for plants without storage. 

- 25 - 
Task 1 

Preferred Plant Size and Capital Cost Estimate 

- 26 - 

Appendix 1 

Details of 250 MWe Plant Total Field Cost Estimate 
Preferred P

- 27 - 
Preferred P

- 28 - 
Preferred P

- 29 - 
Preferred P

- 30 - 
Preferred P

- 31 - 
Preferred P

- 32 - 
Preferred P

- 33 - 
Preferred P

- 34 - 
Preferred P

- 35 - 
Preferred P

- 36 - 
Preferred P

- 37 - 
Preferred P

- 38 - 
Preferred P

- 39 - 
Preferred P

- 40 - 
Preferred P

- 41 - 
Preferred P

- 42 - 
Preferred P

- 43 - 
Preferred P

- 44 - 
Preferred P

- 45 - 
Preferred P

- 46 - 
Preferred P

- 47 - 
Preferred P

- 48 - 
Preferred P

- 49 - 
Preferred P

- 50 - 
Preferred P

- 51 - 
Preferred P

- 52 - 
Preferred P

- 53 - 
Preferred P

- 54 - 
REPORT DOCUMENTATION PAGE Form Approved 

OMB No. 0704-0188

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources, 

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this 

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents 

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a 

currently valid OMB control number. 

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

July 2006 

2. REPORT TYPE

Subcontract Report 

3. DATES COVERED (From - To)

January 20, 2005 – December 31, 2005 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Nexant Parabolic Trough Solar Power Plant Systems Analysis: 

Task 1: Preferred Plant Size 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-550-40162 

5e. TASK NUMBER

CP06.1301 

6. AUTHOR(S)

B. Kelly 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Nexant, Inc. 

101 Second St., 11th Floor 

San Francisco, CA 94105-3672 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

LDC-5-55014-01 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

NREL/SR-550-40162 

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

13. SUPPLEMENTARY NOTES

NREL Technical Monitor: H. Price 

14. ABSTRACT (Maximum 200 Words)

Subcontract report by Nexant, Inc., regarding analysis of plant size of solar parabolic trough plants. 

15. SUBJECT TERMS

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

16. SECURITY CLASSIFICATION OF: 19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified

c. THIS PAGE 

Unclassified

17. LIMITATION 

OF ABSTRACT

UL 

18. NUMBER 

OF PAGES 

19b. TELEPONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18