October 2003 • NREL/SR-550-34440 

Sargent & Lundy LLC Consulting Group 

Chicago, Illinois 

Assessment of Parabolic 

Trough and Power Tower Solar 

Technology Cost and 

Performance Forecasts 

National Renewable Energy Laboratory 

1617 Cole Boulevard 

Golden, Colorado 80401-3393 

NREL is a U.S. Department of Energy Laboratory 

Operated by Midwest Research Institute • Battelle • Bechtel 

Contract No. DE-AC36-99-GO10337 
October 2003 • NREL/SR-550-34440 

Assessment of Parabolic 

Trough and Power Tower Solar 

Technology Cost and 

Performance Forecasts 

Sargent & Lundy LLC Consulting Group 

Chicago, Illinois 

NREL Technical Monitor: H. Price 

Prepared under Subcontract No. LAA-2-32458-01 

National Renewable Energy Laboratory 

1617 Cole Boulevard 

Golden, Colorado 80401-3393 

NREL is a U.S. Department of Energy Laboratory 

Operated by Midwest Research Institute • Battelle • Bechtel 

Contract No. DE-AC36-99-GO10337 
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ASSESSMENT OF 

PARABOLIC TROUGH AND POWER TOWER SOLAR TECHNOLOGY 

COST AND PERFORMANCE FORECASTS 

CONTENTS 

Section Page

 EXECUTIVE SUMMARY.....................................................................................................................ES-1 

1. INTRODUCTION......................................................................................................................................1-1 

1.1 Background and Objective.......................................................................................................................1-1 

1.2 Scope of Work..........................................................................................................................................1-2 

1.3 Methodology ............................................................................................................................................1-3 

1.3.1 Data Collection.................................................................................................................................1-3 

1.3.2 Review of SunLab Cost Model ........................................................................................................1-3 

1.3.3 Technical Improvements..................................................................................................................1-4 

1.3.4 Economy of Scale.............................................................................................................................1-4 

1.3.5 Volume Production (Volume and Learning Curve) .........................................................................1-4

1.3.6 Operation and Maintenance Costs....................................................................................................1-5 

1.3.7 Financial Modeling Analysis Methodology.....................................................................................1-5 

2. CONCENTRATING SOLAR POWER TECHNOLOGIES..................................................................2-1 

2.1 Trough Technology..................................................................................................................................2-1 

2.1.1 System Description ..........................................................................................................................2-1 

2.1.2 Current Experience...........................................................................................................................2-2 

2.2 Tower .......................................................................................................................................................2-3 

2.2.1 System Description ..........................................................................................................................2-3 
 

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CONTENTS (CONT.) 

Section Page

2.2.2 Current Experience...........................................................................................................................2-4 

2.3 Integration with Fossil Power Plants........................................................................................................2-5 

2.3.1 Hybrid ..............................................................................................................................................2-5 

2.3.2 Integrated Solar Combined Cycle System (ISCCS).........................................................................2-5 

2.4 Advanced Technology and Application Options .....................................................................................2-6 

2.4.1 Advanced Tower Technology ..........................................................................................................2-7 

2.4.2 Current International Development Directions ................................................................................2-7 

2.4.3 Long-Term CSP Advanced Applications Options ...........................................................................2-9

3. POWER GENERATION MARKET AND DEPLOYMENT FORECAST..........................................3-1 

3.1 Power Generation Market ........................................................................................................................3-1 

3.2 Deployment Forecast ...............................................................................................................................3-2 

3.3 Trough......................................................................................................................................................3-4 

3.4 Tower .......................................................................................................................................................3-6 

4. EVALUATION OF POTENTIAL FOR COST REDUCTIONS — TROUGH ...................................4-1 

4.1 Development Plan for Cost Reduction.....................................................................................................4-1 

4.2 Efficiency .................................................................................................................................................4-4 

4.2.1 Solar Field Optical Efficiency..........................................................................................................4-6 

4.2.2 Receiver Thermal Losses .................................................................................................................4-7 

4.2.3 Piping Thermal Losses.....................................................................................................................4-7 

4.2.4 Storage Thermal Efficiency .............................................................................................................4-8 

4.2.5 Turbine Cycle Annual Efficiency.....................................................................................................4-8 

4.2.6 Electric Parasitic Load .....................................................................................................................4-9 

4.2.7 Power Plant Availability ..................................................................................................................4-9 

4.3 Evaluation of Major Cost Components..................................................................................................4-10 

4.3.1 Solar Field Support Structure.........................................................................................................4-11 
 

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CONTENTS (CONT.) 

Section Page

4.3.2 Solar Field Heat Collection Elements (HCE).................................................................................4-12 

4.3.3 Solar Field Mirrors.........................................................................................................................4-14 

4.3.4 Power Block...................................................................................................................................4-16 

4.3.5 Thermal Storage .............................................................................................................................4-18 

4.3.6 Total Investment Costs...................................................................................................................4-19 

4.4 Levelized Energy Costs..........................................................................................................................4-25 

4.5 Technology Step Changes and Comparison...........................................................................................4-28 

4.6 Risk Assessment for Trough Technology ..............................................................................................4-37 

4.6.1 Deployment ....................................................................................................................................4-38 

4.6.2 Net Annual Solar-to-Electric Efficiency ........................................................................................4-39 

4.6.3 Mid Term (2010)............................................................................................................................4-40 

4.6.4 Total Investment Cost ....................................................................................................................4-41 

4.6.5 Operation and Maintenance (O&M) Costs ....................................................................................4-43 

4.7 Cost Sensitivities....................................................................................................................................4-45 

4.7.1 Depreciable Life.............................................................................................................................4-46 

4.7.2 Investment Tax Credits ..................................................................................................................4-46 

4.7.3 Corporate Tax Rate ........................................................................................................................4-47 

4.7.4 Inflation..........................................................................................................................................4-47 

4.7.5 Cost of Capital................................................................................................................................4-47 

4.7.6 Construction Duration....................................................................................................................4-48 

4.7.7 Capital Cost....................................................................................................................................4-48 

4.7.8 Annual O&M Cost .........................................................................................................................4-49 

4.7.9 Ownership ......................................................................................................................................4-49 

5. EVALUATION OF POTENTIAL FOR COST REDUCTIONS — TOWER......................................5-1 

5.1 Industry Plan for Cost Reduction.............................................................................................................5-1 

5.2 Tower Efficiency......................................................................................................................................5-4 
 

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CONTENTS (CONT.) 

Section Page

5.2.1 Annual Collector Efficiency.............................................................................................................5-6 

5.2.2 Annual Receiver Efficiency .............................................................................................................5-7 

5.2.3 Annual Gross Cycle Efficiency........................................................................................................5-8 

5.2.4 Annual Parasitic Efficiency..............................................................................................................5-8 

5.2.5 Annual Thermal Storage Efficiency.................................................................................................5-8 

5.2.6 Annual Piping Efficiency.................................................................................................................5-8 

5.2.7 Annual Plant Availability.................................................................................................................5-8 

5.3 Evaluation of Major Cost Components....................................................................................................5-8 

5.3.1 Collectors .......................................................................................................................................5-10 

5.3.2 Electrical Power Block...................................................................................................................5-15 

5.3.3 Receiver..........................................................................................................................................5-18 

5.3.4 Thermal Storage .............................................................................................................................5-21 

5.3.5 Steam Generator.............................................................................................................................5-23 

5.3.6 Balance of Plant .............................................................................................................................5-23 

5.3.7 Technology Improvements.............................................................................................................5-25 

5.4 Operations and Maintenance..................................................................................................................5-25 

5.5 Levelized Energy Cost ...........................................................................................................................5-26 

5.6 Power Tower Technology Step Changes and Comparison....................................................................5-32 

5.7 Cost Reduction Step Changes and Breakdown Comparison..................................................................5-40 

5.8 Risk Assessment for Tower Technology ...............................................................................................5-49 

5.8.1 Deployment ....................................................................................................................................5-50 

5.8.2 Net Annual Solar-to-Electric Efficiency ........................................................................................5-52 

5.8.3 Total Investment Cost ....................................................................................................................5-57 

5.8.4 Operation and Maintenance (O&M) Costs ....................................................................................5-59 

5.9 Cost Sensitivities....................................................................................................................................5-61 

5.9.1 Depreciable Life.............................................................................................................................5-62 

5.9.2 Investment Tax Credits ..................................................................................................................5-62 
 

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CONTENTS (CONT.) 

Section Page

5.9.3 Corporate Tax Rate ........................................................................................................................5-63 

5.9.4 Inflation..........................................................................................................................................5-63 

5.9.5 Cost of Capital................................................................................................................................5-64 

5.9.6 Construction Duration....................................................................................................................5-64 

5.9.7 Capital Cost....................................................................................................................................5-65 

5.9.8 Annual O&M Cost .........................................................................................................................5-65 

5.9.9 Ownership ......................................................................................................................................5-65 
 

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APPENDIXES 

A. List of Documents 

B. Methodology 

C. Levelized Cost for Ranking Alternatives and Example Calculations 

D. Evaluation Of Technology Improvements And Capital Cost Projections For Parabolic Trough Solar Plants 

E. Evaluation of Technology Improvements and Capital Cost Projections – Tower 

F. Evaluation of O&M Costs — Trough 

G. Evaluation of O&M Costs — Tower 

H. Mirror Reflectivity (SunLab Input) 

I. Sargent & Lundy Response to the NRC Issues and Observations 
 

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ACRONYMS AND ABBREVIATIONS 

Term Definition or Clarification 

°C / °F Degrees Celsius/degrees Fahrenheit 

ADL AD Little 

ATS Advanced Thermal Systems 

CHP Combined heat and power 

CRADA Cooperative Research and Development Agreement 

CSP Concentrating Solar Power 

DOE Department of Energy 

DSCR Debt service coverage ratio 

DSG Direct steam generation 

EERE Office of Energy Efficiency and Renewable Energy (a part of the DOE) 

EPSG Electric power generating system 

EU European Union 

GEF Global Environmental Facility 

GWe Gigawatts-electrical 

HCE Heat collection elements 

HRSG Heat recovery steam generator 

HTF Heat transfer fluid 

HTGR High-temperature gas-cooled reactor 

IEA International Energy Agency 

IGC Intergranular corrosion 

ILR Intermediate load range 

IPP Independent power producer 

IRD Industrial Research & Development 

IRR Internal rate of return 

ISCCS Integrated Solar Combined Cycle System (s) 

km Kilometers 

kPa Kilopascals 
 

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ACRONYMS AND ABBREVIATIONS 

Term Definition or Clarification 

kW Kilowatts 

kWt Kilowatts-thermal 

LCOE Levelized costs of energy 

LEC Levelized energy cost 

MACRS Modified Accelerated Cost Recovery System 

MW Megawatts 

MWe Megawatts-electrical 

MWt Megawatts-thermal 

NRC National Research Council 

NREL National Renewable Energy Laboratory 

O&M Operation and maintenance 

PR Progress ratio 

PTC Energy Production Tax Credit 

PV Photovoltaic 

R&D Research and development 

Sargent & 

Lundy or S&L 

Sargent & Lundy LLC

SCA Solar collector assembly 

SEGS Solar Electric Generating Station 

SNL Sandia National Laboratories 

SunLab SunLab comprises researchers from Sandia National Laboratories and the 

National Renewable Energy Laboratory working together on Concentrating 

Solar Power technology for the Department of Energy 

TES Thermal energy storage 

 
 

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ACKNOWLEDGEMENTS 

Sargent & Lundy would like to thank the following individuals and organizations for their important 

contributions to this study: 

R. D. (Dale) Rogers Boeing 

Robert Litwin Boeing 

Pat DeLaquil Clean Energy Commercialization 

Frank Wilkins Department of Energy 

Gilbert Cohen Duke Solar 

David Kearney Kearney & Associates 

Mark Mehos National Renewable Energy Laboratory 

Fredrick Morse Morse Associates, Inc. 

Henry Price National Renewable Energy Laboratory (SunLab) 

William Gould Nexant 

Scott Jones Sandia National Laboratories (SunLab) 

 
 

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EXECUTIVE SUMMARY 

PURPOSE AND SCOPE 

A review of DOE’s Renewable Energy Programs by the National Research Council in 2000 (Renewable Power 

Pathways: A Review of the U.S. Department of Energy’s Renewable Energy Programs, NRC-2000) 

recommended that DOE “should limit or halt its R&D on power-tower and power-trough technologies because 

further refinements to these concepts will not further their deployment.” Subsequent DOE funding requests for 

Concentrating Solar Power (CSP) technology development have been sharply reduced (FY02, FY03) or zero 

(FY04). In 2002, DOE’s Office of Energy Efficiency and Renewable Energy (DOE/EERE) conducted a 

Strategic Program Review that, among other things, identified a need for further technical analysis of CSP 

R&D. In response, DOE/EERE initiated a review process whereby an independent engineering firm would 

conduct a detailed analysis of CSP, which would in turn be reviewed by a second independent NRC panel. 

Sargent & Lundy LLC (S&L) was selected by DOE/EERE to conduct this independent “due-diligence-like” 

analysis of parabolic trough and power tower solar technology cost and performance. The work by S&L was 

done in close collaboration with the National Research Council (NRC) Committee, which was contracted by 

DOE/EERE to provide this second level of independent review. 

As detailed below, S&L’s analysis of the cost-reduction potential of CSP technology over the next 10–20 years 

included the following: 

• Examination of the current trough and tower baseline technologies that are examples of the next 

plants to be built, including a detailed assessment of the cost and performance basis for these 

plants. 

• Analysis of the industry projections for technology improvement and plant scale-up out to 2020, 

including a detailed assessment of the cost and performance projections for future trough and 

tower plants based on factors such as technology R&D progress, economies of scale, economies 

of learning resulting from increased deployment, and experience-related O&M cost reductions 

resulting from deployments. 

• Assessment of the level of cost reductions and performance improvements that, based on S&L 

experience, are most likely to be achieved, and a financial analysis of the cost of electricity from 

such future solar trough and tower plants. 
 

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SARGENT & LUNDY CONCLUSIONS 

Based on this review, it is S&L’s opinion that CSP technology is a proven technology for energy production, 

there is a potential market for CSP technology, and that significant cost reductions are achievable assuming 

reasonable deployment of CSP technologies occurs. S&L independently projected capital and O&M costs, from 

which the levelized energy costs were derived, based on a conservative approach whereby the technology 

improvements are limited to current demonstrated or tested improvements and with a relatively low rate of 

deployment (this does not mean that there is no technology development, only that the technologies have been 

demonstrated or tested at some scale so that no breakthroughs are required; further scale-up and engineering are 

required with associated risks). 

The projections for electrical power consumption in the United States and worldwide vary depending on the 

study, but there will be a significant increase in installed capacity due to increased demand through 2020. 

Trough and tower solar power plants can compete with technologies that provide bulk power to the electric 

utility transmission and distribution systems if market entry barriers are overcome: 

• Market expansion of trough and tower technology will require incentives to reach market 

acceptance (competitiveness). Both tower and trough technology currently produce electricity 

that is more expensive than conventional fossil-fueled technology. Analysis of incentives 

required to reach market acceptance is not within the scope of the report. 

• Significant cost reductions will be required to reach market acceptance (competitiveness). S&L 

focused on the potential of cost reductions with the assumption that incentives will occur to 

support deployment through market expansion. 

For the more technically aggressive low-cost case, S&L found the National Laboratories’ “SunLab” 

methodology and analysis to be credible. The projections by SunLab, developed in conjunction with industry, 

are considered by S&L to represent a “best-case analysis” in which the technology is optimized and a high 

deployment rate is achieved. The two sets of estimates, by SunLab and S&L, provide a band within which the 

costs can be expected to fall. The figure and table below highlight these results, with initial electricity costs in 

the range of 10 to 12.6 ¢/kWh and eventually achieving costs in the range of 3.5 to 6.2 ¢/kWh. The specific 

values will depend on total capacity of various technologies deployed and the extent of R&D program success. 

In the technically aggressive cases for troughs / towers, the S&L analysis found that cost reductions were due to 

volume production (26%/28%), plant scale-up (20%/48%), and technological advance (54%/24%). 
 

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Figure ES-1 — Levelized Energy Cost Summary 

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

2004

Near Term

2006 2010

Mid Term

2015 2020

Long Term

cents per kWh

S&L-Trough

S&L - Tower

Sunlab - Tower

Sunlab -Trough

6.2 cents/kWh

4.3 cents/kWh

5.5 cents/kWh

3.5 cents/kWh

Sargent & Lundy allocated cost reduction as follows: 

S&L High-Cost 

Bound 

Cumulative 

Deployment 

2002–2020 

SunLab Low-Cost 

Bound 

Cumulative 

Deployment 

2002–2020 

Troughs 6.2 cents/kWh 2.8 GWe 4.3 cents/kWh 4.9 GWe 

Towers 5.5 cents/kWh 2.6 GWe 3.5 cents/kWh 8.7 GWe 

Trough technology is further advanced than tower technology. Trough technology has 354 MW of commercial 

generation in operation in the southwestern United States. Tower technology has been successfully 

demonstrated with a conceptual and pilot plants (Solar One and Solar Two). Trough technology is a fully mature 

technology, and there is low technical and financial risk in developing near-term plants. The long-term 

projection has a higher risk due to technology advances needed in thermal storage. The tower technology needs 

to proceed from demonstration to commercial development. There is a higher technical and financial risk in 

developing a first-of-its-kind commercial plant. The advantage of tower technology is that if commercial 
 

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development is successful (e.g., if expected cost and performance targets are achieved), then the levelized 

energy cost (LEC) for long-term deployment will be less than for trough technology. 

TROUGH TECHNOLOGY 

Trough Technology Summary 

The cost, performance, and risk of parabolic trough technology are fairly well established by the experience of 

the existing operating parabolic trough plants. Based on the data available to S&L, the analysis bounds the 

future potential cost of parabolic trough power. 

• Assuming the technology improvements are limited to current demonstrated or tested 

improvements and a deployment of 2.8 GWe of installed capacity by the year 2020 and 

successful development of a thermal storage system, trough costs should be able to drop to 

approximately 6.2¢/kWh 

• Assuming the projected technical improvements are achieved by an active R&D program 

combined with incentives and deployment of 4.9 GWe, the trough costs projected by Sunlab of 

about 4¢/kWh could be acheived. 

Trough Technology S&L Base Case 

The base case for the S&L trough technology cost estimates is as follows: 

 Trough 

Year 2020 

Capacity, MWe 400 

Capacity Factor, % 56.2% 

Capital Cost, $/kW $3,220 

Annual O&M Cost, $k $14,129 

Levelized Energy Cost (LEC), $/kWh $0.0621 

Economic Life 30 yrs 

General Inflation 2.5 % 

Equity Rate of Return 14% 

Cost of Construction 7% 

Construction Duration 1 yr. 

Investment Tax Credit 10% 

Taxes 40.2% 

Depreciable Life 5 yrs. 
 

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 Trough 

Internal Rate of Return (IRR) 14% 

Debt Service Coverage Ratio (DSCR) 1.35 

Ownership IPP 

Differences and Rational for the S&L Trough Technology Projection 

The DOE Concentrating Solar Power Program has developed detailed baseline cost and performance data for 

the parabolic trough technology. In addition, detailed technology R&D plans specify how these technologies are 

expected to change over time. DOE also has established assumed plant deployment forecasts over time. The 

S&L due-diligence-like approach used in this study reviewed the technology cost, performance, technology 

R&D, and deployment assumptions and identified the areas where the assumptions have not been fully 

demonstrated. The S&L review was based on discussions with SunLab, interaction with the CSP industry, input 

from other experts, and S&L in-house technical expertise. 

Relatively detailed cost and performance data are available from existing operating parabolic trough power 

plants. As a result, near-term estimates are relatively close between the SunLab case and the S&L case. In the 

longer-term (2020), the S&L projection differs from the SunLab trough cases in several key areas. A more 

conservative estimate of improvements in annual solar-to-electric efficiency is used, a less aggressive estimate 

in collector cost reductions due to lower expected deployments, and a somewhat higher O&M cost. 

The projected levelized energy cost of electricity in 2020 estimated by S&L is 45% higher than the SunLab 

case. The main differences and rational for the S&L projections are the following: 

• The annual solar-to-electric efficiency in the S&L case is lower than the SunLab case for the 

following reasons (SunLab 17.2%, S&L 15.5%) 

 Receiver performance based on demonstrated UVAC technology. Absorption of 94.4% 

(SunLab 96%), envelop transmittance of 96.5% (SunLab of 97%), and emittance of 10% at 

400C (SunLab 7%). 

 Mirror reflectivity efficiency was not increased beyond the demonstrated value of 93.5% 

(SunLab 95%). Increase would require advanced glass or other reflective membranes. 

 Mirror cleanliness efficiency was not increased beyond the demonstrated value of 95% 

(SunLab 96%). Increase would require new materials and significant enhancements in 

cleaning equipment and methods. 

• The capital cost in the S&L case is 45% higher than the SunLab case for the following reasons. 

(SunLab $2,221/kWe, S&L $3,220/kWe) 
 

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 The lower S&L solar-to-electric efficiency requires a larger solar field to compensate. The 

S&L case assume an 11% increase in solar field. 

 The S&L case assumes a lower deployment 2.8 GWe by 2020 verses the SunLab 

deployment assumption of 4.8 GWe. As a result, less production-based learning was 

assumed. 

 Cost estimates for steam turbines and balance-of-plant costs were estimated by S&L using 

the EPRI SOAPP model, compared to S&L’s internal cost database, and adjusted for labor 

and productivity rates in the southwestern states. The S&L estimates for steam turbines 

were less than SunLab. The S&L estimates for balance-of-plant costs were comparable to 

SunLab. 

 S&L estimated that the engineering, management, and development to be 15% of the 

capital cost as compared to SunLab estimate of 7.8%. 

• Sargent & Lundy’s estimate of the O&M costs is higher than SunLab for the following reasons: 

 S&L scaled-up the cost of field and vehicle maintenance to account for the increase in field 

size 

 Raw water cost used by S&L is based on actual cost reports at SEGS of $0.00122 per 

gallon ($0.32 per m3

). SunLab estimated the cost to be $0.021 per m3, which is about 15 

times less than the S&L estimate. 

Trough Technology Cost Sensitivity 

Variations in the inputs for levelized energy costs were calculated to illustrate the sensitivity to variations. 

 LEC Variation 

Sargent & Lundy Base Case for 2020 $0.0621/kWh 

Financial Incentives 

Impact of Eliminating 5-year MACRS $0.0698 12.5% 

Impact of Eliminating 10% Investment Tax Credit 

(ITC) 

$0.067 7.8% 

Replacing ITC with Production Tax Credit of 

1.8¢/kWh 

$0.049 -26.9% 

Project Cost 

Increasing Cost of Equity by 1% $0.0668 7.7% 

Increasing Construction Period to 2 Years $0.0655 5.5% 

Increase in Capital Cost by 10% $0.0675 8.8% 

Increase in Annual O&M Cost by 20% $0.0635 2.3% 
 

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 LEC Variation 

Ownership 

Utility Ownership $0.0597 -3.9% 

Municipal Utility Ownership $0.0458 -26.1% 

Technology & Deployment 

Increased Deployment from 2.8 GWe to 4.9 GWe $0.0593 -4.7% 

Advanced Technology Case $0.0534 -16.3% 

Trough Technology Risk Analysis 

The major risk for parabolic trough solar plants to reach market acceptance (competitiveness) is the incentives 

that will allow the plant to be competitive with current non-renewable cost of generating power. Assuming 

incentives are provided the risk for achieving cost reduction over the next 10 – 20 years is low to average. 

The capital cost estimate for the initial deployment was developed by SunLab based on actual costs for the 

SEGS plants, detailed cost models developed by industry, and spare part data for the SEGS plant. S&L reviewed 

published cost data and updated the information to include the latest cost estimate for receivers from Solel, 

mirrors from FlagSol, collector structure costs from EuroTrough and Duke Solar, electrical power generation 

system and balance-of-plant costs from the EPRI SOAPP program and S&L’s internal database, and increased 

contingencies. The S&L estimate is 15% higher than the SunLab estimate, which is within an acceptable range. 

Cost reductions are achieved from technology improvements, economy of scale, and volume production. The 

risk of achieving the technology improvements projected by S&L is low based on field-demonstrated 

technology at the SEGS plants and ongoing research by Duke Solar, Solel, FlagSol, and others. The one 

technology risk element left in the S&L case was the switch to molten-salt heat transfer fluid (HTF), which is 

key to driving down future costs. This switch adds some additional risk to the technology. A parametric case is 

included that assumes no thermal storage to see the impact of this technology. 

Economy of scale is a well-established method of estimating the cost of components of a new size or quantity 

from the known cost for a different size or capacity. The risk of achieving the cost improvements projected by 

S&L from economy of scale is low based on (a) using well-established scaling factor ratios from industry data 

(e.g. balance-of-plant, receivers, and electric power system) or (b) if no data are available, then using scaling 
 

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factors slightly more conservative than the industry average. The risk of achieving the cost improvements from 

volume production projected by S&L is low based on the cost reduction experience from the SEGS plants. 

Key Trough Technology Conclusions 

A number of key technology advances will cause near-term trough plants to be a significant improvement over 

the SEGS units. These include: 

• Development of the new Solel UVAC receiver, improving collector field thermal performance 

by 20%. 

• Development of a near-term thermal storage option for troughs by Nexant and SunLab. The 

design is likely to be demonstrated at the first trough plant to be built in Spain. 

• Replacement of flex hoses with ball joint assemblies in the collector field, significantly reducing 

HTF pumping parasitics and increasing the potential size of future parabolic trough solar fields. 

The development of longer-term, more advanced thermal storage technologies is critical. This path offers the 

largest cost reduction potential, as follows. 

• Integral with advanced thermal storage is the implementation of a higher temperature heat 

transfer fluid in the 450°–500°C range. (SunLab and international R&D groups have significant 

efforts underway.) 

• However, increasing trough-operating temperature to 500°C appears to have minimal impact on 

the eventual LEC compared to 450°C. This is contrary to earlier conclusions, necessitating a 

more detailed assessment in the near future. 

Significant cost reductions appear reachable in all three key trough components—structure, receiver, and 

reflectors—though brought about by different cost reduction mechanisms. 

• Concentrator cost reduction will depend largely on size scale-up, production volume, and 

increased competition. (Significant industrial efforts are currently in progress by Duke Solar & 

EuroTrough.) 

• Alternative reflector (mirror) options and production volume are projected to drop costs 

significantly. 

• Achieving an operating temperature of 450°C with current receiver technology appears feasible. 

However, the development of a higher performing and more reliable receiver is very important 

to achieve SunLab long-term cost and performance goals (labs and industry are addressing this). 

O&M procedures are expected to continue downward with scale-up, increasing field experience, and technology 

improvements in reliability. 
 

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TOWER TECHNOLOGY 

Tower Technology Summary 

Because no commercial power tower plants have been built, there is more uncertainty in the cost, performance, 

and technical risk of this technology. Based on the data available to S&L, the analysis bounds the future 

potential cost of power tower plants. 

• Assuming the technology improvements are limited to current demonstrated or tested 

improvements and a deployment of 2.6 GWe of installed capacity by the year 2020, tower costs 

should be able to drop to approximately 5.5¢/kWh 

• Assuming the projected technical improvements are achieved by an active R&D program 

combined with incentives and deployment of 8.7 GWe, the tower costs projected by Sunlab of 

about 3.5¢/kWh could be achieved. 

Tower Technology S&L Base Case 

The base case for the Sargent & Lundy tower technology cost estimates is as follows: 

 Tower 

Year 2020 

Capacity, MWe 200 

Capacity Factor, % 72.9% 

Capital Cost, $/kW $3,622 

Annual O&M Cost, $k $9,132 

Levelized Energy Cost (LEC), $/kWh $0.0547 

Economic Life 30 yrs 

General Inflation 2.5 % 

Equity Rate of Return 14% 

Cost of Construction 7% 

Construction Duration 1 yr. 

Investment Tax Credit 10% 

Taxes 40.2% 

Depreciable Life 5 yrs. 

Internal Rate of Return (IRR) 14% 

Debt Service Coverage Ratio (DSCR) 1.35 

Ownership IPP 
 

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Differences and Rational for the S&L Tower Technology Projection 

The DOE Concentrating Solar Power Program has developed detailed baseline cost and performance data for 

the power tower technology. In addition, detailed technology R&D plans specify how these technologies are 

expected to change over time. DOE also has established assumed plant deployment forecasts over time. The 

S&L due-diligence-like approach used in this study reviewed the technology cost, performance, technology 

R&D, and deployment assumptions and identified the areas where the assumptions have not been fully 

demonstrated. The S&L review was based on discussions with SunLab, interaction with the CSP industry, input 

from other experts, and S&L in-house technical expertise. 

The projected levelized energy costs of electricity in 2020 estimated by S&L are 65% higher than the 

projections by SunLab. The main differences and rational for the S&L projections are the following: 

• Sargent & Lundy did not assume deployment of the advanced high temperature turbine and 

heliostats in 2020, whereas the SunLab assumed deployment in 2018. 

• Sargent & Lundy cost estimate for heliostats, which are about 45% of the total cost, are about 

10% higher. The S&L estimate is based on our evaluation of cost estimates prepared by 

SunLab, AD Little, Advanced Thermal Systems, Solar Kinetics, and Winsmith. 

 S&L used a contingency of 10% as compared to SunLab of 5%. 

 S&L estimated deployment at about 25% of the SunLab estimate to take into consideration 

a realistic duration between the first and second deployment and between increases in plant 

size. 

 S&L manufacturing costs are higher as a result of our evaluation 

• Sargent & Lundy estimated the costs for steam turbines and balance of plant costs using the 

EPRI SOAPP model, compared to S&L’s internal cost database and adjusted for labor and 

productivity rates in the southwestern states. The S&L estimate for steam turbines were less 

than SunLab. The S&L estimates for balance-of-plant costs were higher than SunLab. 

• The S&L receiver capital costs are based on a cost estimate provided by Boeing. Boeing was 

the supplier of the Solar Two receiver and is providing the receiver for Solar Tres. 

• Sargent & Lundy estimated that the engineering, management, and development to be 15% of 

the capital cost as compared to SunLab estimate of 7.8%. 

• SunLab included a risk pool contingency of 10% for Solar Tres, and S&L concurs with this 

value. In addition, S&L included a risk pool contingency of 5% for Solar 50. 

• S&L included a contingency of 12% for direct costs and 15% for cost reduction, in comparison 

to SunLab’s contingency of 7.8% 
 

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• The efficiency projections by S&L were based on a review of the SunLab Reference Case, 

demonstrated efficiencies, design modifications based on lessons learned from Solar Two, and 

turbine generator computer model. The main differences are the following: 

 Mirror reflectivity efficiency was not increased beyond the demonstrated value of 95%. 

Increase would require advanced glass or other reflective membranes. 

 Mirror cleanliness efficiency was not increased beyond the demonstrated value of 95%. 

Increase would require new materials and significant enhancements in cleaning equipment 

and methods. 

 Near-term efficiencies were based on the ABB-Brown Boveri heat balance for SEGS IX. 

The efficiency for other size units was verified by using the General Electric STGPer 

software program. 

 Efficiency has a direct impact on the size of the collector field. The increase in collector 

field area and corresponding increase in capital cost was calculated based on the lower 

efficiency estimated by S&L. 

• S&L estimate of the O&M costs is higher than SunLab for the following reasons: 

 S&L scaled-up the cost of field and vehicle maintenance to account for the increase in field 

size. 

 S&L assumed that the average burdened rate would not decrease between Solar 100 and 

Solar 220. 

 Raw water cost used by S&L is based on actual cost reports at SEGS of $0.00122 per 

gallon ($0.32 per m3

). SunLab estimated the cost to be $0.021 per m3), which is about 15 

times less than the S&L estimate. 

 S&L included a 10% contingency. 

Tower Technology Cost Sensitivity 

Variations in the inputs for levelized energy costs were calculated to illustrate the sensitivity to variations. 

 LEC Variation 

S&L Base Case for 2020 $0.0547/kWh 

Financial Incentives 

Impact of Eliminating 5-year MACRS $0.0614 12.3% 

Impact of Eliminating 10% Investment Tax Credit 

(ITC) 

$0.0590 7.8% 

Replacing ITC with Production Tax Credit of 

1.8¢/kWh 

$0.0410 -30.5% 
 

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 LEC Variation 

Project Cost 

Increasing Cost of Equity by 1% $0.0588 7.6% 

Increasing Construction Period to 2 Years $0.0577 5.4% 

Increase in Capital Cost by 10% $0.0595 8.7% 

Increase in Annual O&M Cost by 20% $0.0561 2.6% 

Ownership 

Utility Ownership $0.0526 -3.8% 

Municipal Utility Ownership $0.0406 -25.7% 

Technology & Deployment 

Increased Deployment from 2.6 GWe to 8.7 GWe $0.0524 -4.2% 

Advanced Technology Case with Advanced 

Heliostat and High Temperature TurbineGenerator (from 16.5% to 17.4%) 

 $0.0487 -11.0% 

Worst Case Efficiency (from 16.5% to 14.6%) $0.0590 7.9% 

Tower Technology Risk Analysis 

The major risk for tower solar plants to reach market acceptance (competitiveness) is the incentives that will 

allow the plant to be competitive with current non-renewable cost of generating power. Assuming incentives are 

provided, the risk for achieving cost reduction over the next 10–20 years is low to average. 

The capital cost estimate for the initial deployment was developed by SunLab based on actual costs for Solar 

Two, the Central Receiver Utility Studies, the AD Little heliostat detailed cost estimate, detailed heliostat design 

from ATS, and industry data. S&L reviewed published cost data and updated the information to include the 

latest cost estimate for receivers from Boeing, electrical power generation system and balance-of-plant costs 

from the EPRI SOAPP program and S&L’s internal database, and increased contingencies. The S&L estimate is 

15% higher than the SunLab estimate, which is within an acceptable range. 

Cost reductions are achieved from technology improvements, economy of scale, and volume production. The 

risk of achieving the technology improvements projected by S&L is low based on demonstrated technology, 

design enhancements from lessons learned during Solar Two, improved advances in control technology since 

Solar Two, and ongoing research by Boeing. Economy of scale is a well-established method of estimating the 
 

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cost of components of a new size or quantity from the known cost for a different size or capacity. The risk of 

achieving the cost improvements projected by S&L from economy of scale is low based on (a) using wellestablished scaling factor ratios from industry data (e.g. balance of plant, receivers, and electric power system) 

or (b) if no data are available, then using scaling factors slightly more conservative than the industry average. 

The risk of achieving the cost improvements from volume production projected by S&L is low based on using a 

progress ratio of 0.97, which is at the upper end of published data. Various studies on learning curves from 

actual data suggest a progress ratio of 0.82 for development of photovoltaics and 0.95 for development of wind 

power. 

Key Tower Technology Conclusions 

Solar plant and power plant scale-up provide the largest cost reduction opportunity for power tower 

technologies. 

• Scale-up of the tower solar plant requires a total redesign and re-optimization of the field, 

tower, and receiver. This greatly reduces capital and O&M costs, but has only a small effect on 

efficiency. R&D support in the design, development, and testing of larger receivers, larger 

heliostats, and larger heliostat fields will reduce scale-up risk. 

• Scale-up of the steam turbine increases efficiency, and reduces capital and O&M costs. 

Probability of success here is very high, as no development is required until high-efficiency 

supercritical steam turbines become available (2020). 

Key technical advances include increasing receiver solar flux levels, development of new heliostat designs with 

significantly lower costs, and the use of new highly efficient steam turbines. 

• Increased receiver flux levels have been demonstrated at the prototype scale and require 

improved heliostat field flux monitoring/management systems and design optimization for use 

at large plants. 

• Revolutionary heliostat designs with significantly lower cost have been proposed that use 

flexible, durable thin mirrors with a lower-weight ‘stretched-membrane’ design that can be 

manufactured in high volumes. Other novel designs like inflatable/rolling heliostats are also 

possible. 

• High-efficiency supercritical steam turbines are now being demonstrated that operate at 

temperatures compatible with current tower technology or at temperatures that require 

increasing the operating temperature of the tower technology to 600°–650°C. 

The major volume manufacturing benefit evaluated for tower technology was related to heliostats. 

• Heliostat cost reduction will occur when they are produced at high volume. Sargent & Lundy’s 

evaluation of the current heliostat design and cost indicated that cost should decrease 3% with 
 

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each doubling of cumulative capacity. This would reduce the cost of a field of 148 m2 heliostats 

from $148/m2

 to $94/m2. 

DISCUSSION OF NRC COMMENTS ON THE S&L DRAFT REPORT 

The draft report of the S&L “due-diligence-like” analysis of parabolic trough and power tower solar technology 

cost and performance was reviewed the National Research Council Committee. The results of the NRC review 

were published in “Critique of the Sargent & Lundy Assessment of Cost and Performance Forecasts for 

Concentrating Solar Power.” The NRC Committee recommended several methodological approaches for S&L 

to follow, identified areas for further investigation by S&L, and critically reviewed the S&L findings. 

Much of the NRC critique of the S&L analysis centered around assumed rates of deployment and incentive 

issues. Deployment and incentive issues were outside the scope of work for S&L. As noted by the NRC: “The 

committee notes that CSP technology is not unique in the requirement for incentivizing the early market phases 

of emerging energy technologies” (NRC, page 11). “The committee notes the extensive reports and study 

literature on these issues cited by S&L, including DOE/EERE’s own August 2002 Report to Congress on the 

Feasibility of 1,000 Megawatts of Solar Power in the Southwest by 2006...” (NRC, page 11). DOE noted in 

their presentations to the NRC and S&L that because such studies were available, DOE’s primary concern, and 

the reason for this study, was to determine the potential technical feasibility of CSP. Nevertheless, there are 

several deployment issues worth considering. First, the “chicken-and-egg” (NRC, page 15) problem of driving 

down costs by deploying technologies, but facing high initial costs that impede deployment, is true of all energy 

technologies, not just CSP. Second, as noted by the NRC and S&L, incentives are a key determinant of the rate 

at which CSP, or any new energy technology, penetrates the market. Evaluating this lies well outside the 

technical analysis requested of S&L. Third, the level of deployment identified by S&L is modest, at about 

2.8 GW by 2020. The NRC also noted that “The SunLab deployment scenarios evaluated by S&L represent a 

range from a modest rate of adding one 100 MWe plant per year (the first becoming operational in 2004) to an 

aggressive approach that would result in almost 5,000 MWe of new capacity by 2020” (NRC, page 5). To place 

this in context, the wind industry added 1,700 MW of new capacity in the U.S. in 2001 alone. 

The main NRC findings that support the S&L study are the following: 

1. The NRC committee believed that a plausible estimate of levelized energy cost would lie somewhere 

between S&L’s and Sunlab’s projections in 2020. 
 

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• “Based on the level of uncertainty that is inherently present in projecting these deployment rates 

and technology advances, a more plausible estimate would lie somewhere between the two 

projections (S&L’s and SunLab’s) in 2020. However, if deployment does not proceed at the 

assumed rate, the projected LEC could be much higher than either of these estimates.” (NRC 

page 6) 

2. The NRC committee agreed with S&L on a number of its technical findings. 

• “Since 1999, significant progress has been made in understanding the potential impacts of 

thermal storage technologies, thin film glass mirrors, improved heat collection units, improved 

trough support structures, and other technical opportunities to improve CSP technology.” (NRC 

Page 4) 

• “The committee agrees with S&L’s identification of key technology components for increasing 

the performance of trough systems to lower costs.” (NRC, page 6) 

• The committee has a high confidence in the estimate for power block cost reductions that will 

result in increasing plant sizes. (NRC, pages 7 and 8) 

• “The committee believes that S&L did a reasonable job of assessing the improvements in 

annual tower efficiency of power plant progression....” (NRC, page 7) 

• “It is anticipated that industry R&D will deliver the technical advances appropriate for 

receivers.” (NRC, page 9) 

• “S&L appears to have done a reasonable job of assessing the design and capital cost potential 

for systems based on a near-term (or demonstrated) technologies.” (NRC, page 8) 

• The NRC committee agreed with S&L’s methods and review of the O&M costs. (NRC, page 5 

and 9) 

3. The NRC committee agreed with S&L that policy-based incentives are needed for initial introduction of 

technologies and that both R&D and deployment of technology are necessary. 

4. The committee agreed that S&L’s selection of the base case economic parameters are reasonable, but did 

not ‘sufficiently examine the effect of uncertainties (NRC, page 5). S&L concurs with the NRC and has 

included expanded sensitivity analysis in the final report. 

5. The NRC committee found that S&L was not biased and provided a creditable process within the constraints 

of time and the information available. Furthermore, the NRC committee stated that S&L did reasonable job 

assimilating information within time and resource constraints. 

• “...that S&L took any potential conflict of interest very seriously and made a concerted effort to 

address and avoid it. No obvious example of bias was apparent in S&L’s interpretation of the 

available data nor was there any deliverate omission of pertinent facts. If anything, the S&L 
 

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analysis was more conservative than SunLab’s estimates in assessing areas like time to develop 

new materials or power conversion technologies.” (NRC, page 18) 

• “...that S&L attempted to maintain a credible process by filling in the gaps in its knowledge 

base with the advice of world-recognized experts.” (NRC, page 18) 

The main NRC committee recommendations to S&L are the following: 

1. The NRC committee asked for a risk assessment. The S&L final report has been modified to include a risk 

assessment section per NRC recommendations. 

2. The NRC committee asked for additional sensitivity analysis. The S&L final report has been modified to 

include an expanded sensitivity analysis per NRC recommendations. 

3. The NRC committee asked for clarification of the differences and rational for the S&L cost estimate. The 

S&L final report has been modified to include a comparison summary of the differences in the executive 

summary. 

4. The NRC committee would have preferred a bottoms-up cost analysis. This study was never intended to 

provide a bottoms-up cost assessment. Unfortunately time and budgets did not allow for this type of cost 

analysis. Instead, a typical financial review was conducted to assess the validity of the existing data. 

A considerable portion of the NRC’s critique was focused on the S&L scope of work, not results of our review 

as documented in the report. Sargent & Lundy had a defined scope of work for this project, which was clearly 

identified in our contract. Most of the areas identified by the NRC as a critique to the S&L Report are in fact 

critiques of the defined work scope. The most significant areas identified by the NRC, which were not in our 

scope of work, are the following: 

• The type or value of incentives needed to reach market acceptance. Our report clearly identifies 

that this was not part of the work scope and is one of the most significant market entry barriers 

to overcome. 

• The S&L projection of deployment is ‘not creditable’. The scope of work did not include a 

market analysis, which would be required to provide a deployment projection. One of the key 

drivers for deployment is overcoming market entry barriers, in particular incentives. As 

previously mentioned, incentives are needed, but the political climate and assessment of 

whether or when incentives would become available require significant review not considered 

within our scope. 

• Power generation market. The S&L draft report issued September 2002 included a discussion of 

power generation markets, including geography, access to established power grids, 
 

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environmental restrictions or incentives, and taxes. Subsequently, due to a tight schedule and 

because such work had already been done elsewhere, the DOE directed that the scope of work 

not include an evaluation of the power generation market and associated issues. 

• The S&L report did not include a bottoms-up cost estimate. Our scope of work was an 

independent review of the cost estimates developed by SunLab for trough and tower 

technology. It is typical for due diligence or due diligence-like reviews to perform an 

independent assessment of cost estimates and documentation provided for our review and to 

point out areas where the estimates may be inaccurate. Typically, this type of review does not 

include an independent bottoms-up cost estimate. Instead, S&L drew heavily from industry 

experience, vendor quotes, and other sources rather than recreate all this analysis on its own. 

Sargent & Lundy agrees that the recommended expanded scope proposed by the NRC provides additional value 

to the DOE. However, we believe the methodology used by S&L stands on its own as a credible assessment of 

the status and potential of parabolic trough and power tower technologies. Sargent & Lundy’s response to the 

more significant findings in the NRC critique is included in Appendix I. 
 

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1. INTRODUCTION 

1.1 BACKGROUND AND OBJECTIVE 

Several years ago, the National Research Council (NRC) issued a report (Hubbard 2000) recommending that the 

Department of Energy (DOE) should “limit or halt its research and development on power-tower and powertrough technologies because further refinements would not lead to deployment.” Unfortunately, the report 

provided no analysis or description of the various advanced technology options, their costs, or their associated 

technical risks that the NRC considered in arriving at these conclusions. 

To examine the possible factors contributing to the NRC recommendations, the DOE had the Concentrating 

Solar Power (CSP) Program (which provides funding for trough and tower research and development) peer 

reviewed in the fall of 2001. This review concluded that “the CSP Program can play an important role in 

catalyzing further CSP technology advances, which will further improve CSP economics and market 

penetration” (Tester 2001). 

In order to resolve the differing conclusions between the NRC report and the Peer Review, and in accordance 

with its own strategic program review recommendations, the Office of Energy Efficiency and Renewable 

Energy (EERE), a part of the DOE, contracted Sargent & Lundy (S&L) to conduct a “due diligence-like” 

analysis of both trough and tower technologies and to have the results of the “due diligence” analysis reviewed 

by a new panel assembled by the NRC. 

The objective of this evaluation was to assess the cost-reduction potential of CSP technology over the next 10 to 

20 years. The analysis proceeded along the following steps: 

1. Examination of the current trough and tower baseline technologies that are examples of the 

next plants to be built, including a detailed assessment of the cost and performance basis for 

these plants. 

2. Analysis of the industry projections for technology improvement and plant scale-up out to 

2020, including a detailed assessment of the cost and performance projections for future 

trough and tower plants based on factors such as technology research and development (R&D) 

progress, economies of scale, economies of learning resulting from increased deployment, and 

experience-related operation and maintenance (O&M) cost reductions resulting from 

deployments. 

3. Assessment of the level of cost reductions and performance improvements that, based on S&L 

experience, are most likely to be achieved, and a financial analysis of the cost of electricity 

from such future solar trough and tower plants. 
 

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Sargent & Lundy, with technical support from its expert consultants, reviewed available information and data to 

make our independent assessment. The detailed review was performed by S&L, with only technical input from 

our consultants, so that we maintain as much independence as possible from the industry and from our expert 

consultants. 

Sargent & Lundy is not an active participant in the solar market. However, our experience includes design of the 

power block and civil/structural portions for the Solar Electric Generating Station (SEGS) VIII and IX in 1988–

1989. Any future involvement in CSP plants would entail a similar scope (design of the power block and 

civil/structural portions). S&L’s core competence is as an architect-engineer and designer for the power block. 

Although we may be a participant in the project, our independence is maintained since any work would be a 

small portion of our overall business. 

1.2 SCOPE OF WORK 

Sargent & Lundy received and organized data from the DOE, National Renewable Energy Laboratory (NREL), 

Sandia National Laboratories (SNL), and members of the CSP industry. These data included technology 

assessments and supporting studies for troughs and towers. 

The first meeting with the NRC panel to discuss the work approach and agree on the focus of the work scope 

occurred on August 12, 2002. Before the meeting, S&L, with approval from NREL, proceeded with the review 

based on our contractual work scope. Among the technical experts within the industry from whom we received 

guidance, including support on a subcontract basis, were Dave Kearney for Trough Technology and Pat 

DeLaquil for Tower Technology. 

The work scope was modified during the first NRC meeting to focus on cost reductions and technology 

improvements. S&L’s scope of work included “estimate the expected competitiveness of these technologies 

(CSP) in peaking, cycling, and baseload applications for operation as grid-connected generators, comparing CSP 

technologies with other technologies commercially used for such service today (e.g. combined-cycle natural gas 

fired power plants).” S&L had completed considerable work in this area before the August 12, 2002 meeting. 

The DOE stated that it was not the intent, nor should it be the intent, to include this in the work scope. The 

analysis of competing technologies will be addressed separately by the DOE. S&L’s evaluation or assessment 

focused on cost reduction, improvements in technology and financial analysis of levelized energy cost (LEC). 

Our evaluation review was based on our examination of relevant data, technical assistance from our 

subcontractors, our experience in the power industry and due diligence process, and industry input. The 
 

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evaluation review is an independent evaluation of the reasonableness and feasibility that cost reductions and 

technology improvements can be achieved based on available information and our experience. The evaluation 

review does not include detailed engineering or detailed bottom-up cost estimates. 

Sargent & Lundy issued the final draft report ‘Assessment of Parabolic Trough and Power Tower Solar 

Technology Cost and Performance Forecasts’ in October 2002. The National Research Council (NRC) 

Committee for the Review of a Technology Assessment of Solar Power Energy Systems reviewed the report. 

The results of the NRC review were published in ‘Critique of the Sargent & Lundy Assessment of Cost and 

Performance Forecasts for Concentrating Solar Power’ dated October 12, 2002. S&L was authorized by NREL 

to update the report to expand the executive summary to provide more information as suggested by the NRC and 

perform additional sensitivity analysis. S&L response to the NRC issues and observations are included in 

Appendix I. 

1.3 METHODOLOGY 

A summary of the methodology for performing this evaluation is provided in this section. A detailed discussion 

of the methodology and example is included in Appendix B. 

1.3.1 Data Collection 

Sargent & Lundy received relevant documents from NREL and SNL for our independent review. During the 

review process, additional documents were gathered from industry sources, the Internet, and our internal S&L 

library. The list of documents is included in Appendix A. 

1.3.2 Review of SunLab Cost Model 

Sargent & Lundy reviewed the SunLab cost model and determined that the SunLab cost model approach and 

methodology is reasonable. The SunLab cost model was developed based on industry cost data and engineering 

evaluation. S&L evaluated the assumptions in the SunLab cost model: efficiency improvements, capital cost for 

the near-term deployment, and cost reductions through the year 2020. The review of cost reductions included 

technology improvements, increase in the size of the plant (scale-up), and production volume. 

The cost model was compared to S&L’s internal cost database, as appropriate (e.g., turbine, equipment, and 

commodities such as steel prices). 
 

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Differences between the SunLab and S&L cost estimates were a result of different assumptions. For example, 

S&L increased the duration between the deployment of the next generation plant from 1 year to 2 years to 

account for lessons learned and an adequate time for steady-state operation. The differences in assumptions are 

identified in the main body of the report. 

1.3.3 Technical Improvements 

Projected technical improvements that reduce costs by improving plant efficiency or by reducing initial capital 

costs were evaluated with respect to probability of the improvement and the estimated magnitude of cost 

reduction. The projected technical improvements investigated were those identified in the SunLab models, and 

the probability and magnitude of cost reductions are based on data from DOE, NREL, SNL, and members of the 

CSP industry, including technology assessments and supporting studies for troughs and towers. 

1.3.4 Economy of Scale 

Economy of scale was used, as appropriate; to estimate or evaluate cost estimates for components. Scaling 

factors were used to estimate the cost of a new size or capacity from the known cost for a different size or 

capacity. 

1.3.5 Volume Production (Volume and Learning Curve) 

Experience curves define how unit costs decrease with cumulative production. The specific characteristics of the 

experience curve are that the cost declines by a constant percentage with each doubling of the total number of 

units produced (Neij 1997). 

Many of the previous studies that assessed the cost reduction potential for tower and trough technologies based 

their findings on experience curves (World Bank 1999). As pointed out in the Teagan report (2001), “the review 

documents do not make a strong case that the cost of technologies (particularly the solar field) can be reduced to 

a point that they approach economic viability....” His primary example was the collector field: “the ‘learning 

curve’ arguments put forth lack sufficient backup to be credible given the fact that the materials of construction 

are already commodities and the fabrication techniques, for the most part standard.” He also stated that he 

believed cost reductions are likely “via a combination of ‘learning curve’ and technology refinement.” In 

response, S&L performed a thorough review of the cost reduction potential for heliostats. Heliostat cost 

reduction potential is more difficult to estimate since it is not based on actual costs of significant volume, 

whereas trough costs and the cost reductions are known based on actual SEGS construction data and recent costs 
 

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for replacement during operations and maintenance. Our detailed evaluation of cost reduction potential is 

provided in Appendix E.5. 

Sargent & Lundy reviewed the engineering assumptions, industry data, and studies that constitute the basis of 

the SunLab Cost Model for the major cost drivers. The review was not based on just applying an experience 

curve, but an engineering review. We reviewed the assumptions and made adjustments as deemed appropriate 

based on our experience. We calculated the progress ratio and compared it to actual experience curves from 

other industries. The calculated progress ratio value was then used to determine estimated costs for a range of 

deployments. 

1.3.6 Operation and Maintenance Costs 

Sargent & Lundy reviewed the SunLab cost model against interviews and actual data provided to us during a 

site visit to Kramer Junction and our knowledge and internal database of O&M costs for electric power plants. 

We reviewed the SunLab assumptions and made adjustments as appropriate based on our experience and 

information provided by Kramer Junction. 

1.3.7 Financial Modeling Analysis Methodology 

The financial model used for developing generating costs is a spreadsheet pro forma financial model of the type 

used in competitive industry to support power project planning and financing. S&L regularly reviews such 

models as part of our due diligence practice, working with lenders and investors in project financing. In some 

cases we also support project developers by writing and maintaining such models for them. 

The main analysis engine is a standard income statement that includes calculations of energy production, 

revenues, operation and maintenance expenses, fuel expenses, depreciation, insurance, property taxes, interest, 

investment tax credit, and income tax. The investment tax credit for solar technologies is represented. Once 

after-tax income was determined in the income statement, depreciation was added back and payback of debt 

principal was subtracted to obtain cash available for dividends. The dividend stream and equity investment into 

the project was combined to compute the equity internal rate of return for the project. All evaluations were done 

on a lifetime $/MWh evaluated cost basis, covering 30 years of service. 
 

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2. CONCENTRATING SOLAR POWER TECHNOLOGIES 

2.1 TROUGH TECHNOLOGY 

2.1.1 System Description 

The collector field in the trough technology 

consists of a large field of single-axis tracking 

parabolic trough solar collectors, as shown on the 

illustration to the right. The solar field is modular 

and is composed of many parallel rows of solar 

collectors aligned on a north-south horizontal 

axis. Each solar collector has a linear parabolicshaped reflector that focuses the sun’s direct beam 

radiation on a linear receiver located at the focus 

of the parabola. The collectors track the sun from 

east to west during the day to ensure that the sun 

is continuously focused on the linear receiver. A heat transfer fluid (HTF) is heated as it circulates through the 

receiver and returns to a series of heat exchangers in the power block where the fluid is used to generate highpressure superheated steam. The superheated steam is then fed to a conventional reheat steam turbine/generator 

to produce electricity. The spent steam from the turbine is condensed in a standard condenser and returned to the 

heat exchangers via condensate and feedwater pumps to be transformed back into steam. After passing through 

the HTF side of the solar heat exchangers, the cooled HTF is recirculated through the solar field. Figure 2-1 is a 

process flow diagram for the trough technology. 
 

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Figure 2-1 — Process Flow Diagram for Trough Technology 

2.1.2 Current Experience 

Parabolic trough technology is currently the most proven of the solar thermal electric technologies. The success 

of this technology is primarily indicated by the operation of nine large commercial-scale solar power plants, the 

first of which has been operating in the California Mojave Desert since 1984 (SEGS I). These plants, which 

continue to operate daily, range in size from 14 to 80 megawatts (MW) and represent a total of 354 MW of 

installed electric generating capacity. SEGS gross production for 1985 to 2001 was 8,305,477 MWh. 
 

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2.2 TOWER 

2.2.1 System Description 

Solar power towers generate electric power 

from sunlight by focusing concentrated 

solar radiation on a tower-mounted heat 

exchanger (receiver). The system uses 

hundreds to thousands of sun-tracking 

mirrors called heliostats to reflect the 

incident sunlight onto the receiver (see 

illustration to the right). These plants are 

best suited for utility-scale applications in 

the 30- to 400-MWe ranges. In a molten-salt solar power tower, liquid salt at 290°C (554°F) is pumped from a 

“cold” storage tank through the receiver where it is heated to 565°C (1,049°F) and then on to a “hot” tank for 

storage. When power is needed from the plant, hot salt is pumped to a steam generating system that produces 

superheated steam for a conventional Rankine-cycle turbine/generator system. From the steam generator, the 

salt is returned to the cold tank where it is stored and eventually reheated in the receiver. Figure 2-2 is a molten 

salt power tower system schematic diagram. 
 

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Figure 2-2 — Molten-Salt Power Tower System Schematic 

(Solar Two, baseline configuration) 

2.2.2 Current Experience 

To date, the largest power towers ever built are the 10-MWe Solar One and Solar Two plants in southern 

California. Although power towers are commercially less mature than parabolic trough systems, a number of 

component and experimental systems have been field tested around the world in the last 15 years, demonstrating 

the engineering feasibility and economic potential of the technology. 

The Solar One Pilot plant was an important step in the development of power tower technology and operated 

from 1982 to 1988. After the initial startup (test and evaluation) phase, Solar One operated reliably. 

The goals of the redesigned demonstration plant, called Solar Two, were to validate nitrate salt technology, to 

reduce the technical and economic risk of power towers, and to stimulate the commercialization of power tower 

technology. Solar Two succeeded in meeting these objectives and has led to the formation of a 

commercialization consortia to build the first commercial power tower plant, Solar Tres, in Spain. Solar Two 

produced 10 MW of electricity with enough thermal storage to continue to operate the turbine at full capacity for 

3 hours after the sun has set, proving the ability to dispatch to meet peak utility loads. Solar Two also 

demonstrated continuous operation for nearly a week, frequently at part-load output. 
 

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2.3 INTEGRATION WITH FOSSIL POWER PLANTS 

2.3.1 Hybrid 

Many solar-fossil hybrid options are possible with natural gas combined-cycle and coal-fired or oil-fired 

Rankine plants, and may accelerate near-term deployment of projects due to improved economics and reduced 

overall project risk. One opportunity for hybrid integration is with a power tower hybridized with a combinedcycle plant. In this power boost hybrid plant, a solar-only plant has, in effect, been “piggybacked” on top of a 

base-loaded fossil-fueled plant. Power is produced in the gas turbine (fossil only) and from the steam turbine 

(fossil and solar). Steam from the solar steam generator is blended with fossil steam from the heat recovery 

steam generator (HRSG) before entering a steam turbine. 

In the power boost hybrid plant, additional electricity is produced by over sizing the steam turbine, contained 

within a coal-fired Rankine plant or the bottoming portion of a combined-cycle plant, so that it can operate on 

both full fossil and solar energy when solar is available. Studies of this concept have typically oversized the 

steam turbine from 25% to 50% beyond what the turbine can produce in the fossil-only mode. Oversizing 

beyond this range is not recommended because the thermal-to-electric conversion efficiency will degrade at the 

partial loads associated with operating in the fuel-only mode. 

When hybridizing a solar power tower with a base-load fossil-fired plant, solar contributes about 25% of the 

peak power output from the plant and between 10% and 25% of the annual electricity. (The higher annual solar 

fraction can be achieved with 13 hours of thermal storage and the lower solar fraction with just a few hours of 

storage.) 

2.3.2 Integrated Solar Combined Cycle System (ISCCS) 

The Integrated Solar Combined Cycle System (ISCCS) was initially proposed as a way of integrating a 

parabolic trough solar plant with modern combined-cycle power plants. The approach reduces the effective cost 

of the conventional power plant equipment, leveraging O&M and project development costs over a much larger 

plant and potentially increasing the solar-to-electric conversion efficiency. The initial concept was simply to 

increase the size of the steam turbine, use solar energy to generate steam, and use the waste heat from the gas 

turbine to preheat and superheat the steam. The general concept called for doubling the size of the steam turbine 

in the bottoming cycle. The ISCCS plant would operate at the combined-cycle output during non-solar periods, 

and then output would increase by up to one third when solar energy was available (referred to as the solar 

increment). However if the combined-cycle plant is operated in a baseload operating profile, the annual solar 
 

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fraction (percent of electric generation from solar) will only be about 10%. In addition, detailed design 

integration issues must be considered to make sure the solar integration does not have a significant impact on the 

combined-cycle fossil operation. A number of recent studies have looked at the best approaches for this 

integration. ISCCS plants are being considered for all four of the Global Environmental Facility (GEF) grant 

projects (India, Egypt, Morocco, and Mexico). Figure 2-3 shows a process flow schematic of a parabolic trough 

ISCCS plant concept. 

Figure 2-3 — Scheme of an ISCCS power plant with a dual-pressure-reheat steam cycle and 

the usage of solar energy to replace latent heat of evaporation in the high pressure part 

Source: Price et al. (2002) 

2.4 ADVANCED TECHNOLOGY AND APPLICATION OPTIONS 

By charter, this report addresses trough and tower technologies and focuses on Rankine cycle power generation 

at temperatures in the range of 350°–550°C, as currently being pursued by U.S. industry and the CSP program. 

For completeness, we have also included here some high-level information on other options, namely variants of 

trough and tower technology that are being pursued by international competitors, as well as other options for 

future applications of large-scale CSP technology. This information was supplied by SunLab and has not been 

verified by S&L. 
 

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2.4.1 Advanced Tower Technology 

One idea under consideration for future power tower technology is an advanced receiver that is capable of 

efficiently heating air to gas-turbine temperatures (>1,400°C/2,552°F) and pressures (>1,500 kPa) in 

conjunction with a high-temperature phase-change thermal storage system. If this can be achieved, large solaronly plants with a combined-cycle power block efficiency of 60% or more might be achieved. In addition, as 

receiver temperatures exceed 800°C (1,832°F), thermo-chemical approaches to hydrogen generation could be 

exploited using solar power towers. Another interesting option is the thermo-chemical production of syngas by 

reforming methane. Since existing natural gas pipelines can accept about 10% hydrogen content, this concept 

could be used before the development of a hydrogen infrastructure. A CSP plant located in the desert could 

effectively convert 10% of the downstream gas appliances (water heaters, stoves, industrial equipment, etc.) into 

“solar-powered” appliances without needing to have any solar facilities on site. Significant research would 

certainly be required to develop these concepts, and they have not been reviewed by S&L as part of this study. 

2.4.2 Current International Development Directions 

Internationally, trough or tower technology development, along with related project development, is being 

aggressively pursued in Germany, Spain, Italy, Israel, and South Africa. While international trough technology 

is fundamentally the same as that in the United States, there are some differences. European partners (with 

significant funding from the European Union (EU), national and state programs) have developed and 

extensively tested a prototype of a competing trough structure (EuroTrough) that will begin full-scale prototype 

testing at the Kramer Junction solar plant in California in the spring of 2003. Germany and Spain are pursuing 

steam as a high-temperature working fluid in addition to near-term development based on the same heat transfer 

oil as used here in the United States. Trough receiver development includes advances by Solel in Israel (which 

would be implemented by U.S. industry as well); development by the EU (through Germany and Spain) of a 

completely new heat collection elements (HCE), including an advanced selective surface capable of operation at 

the temperatures of their steam working fluid (up to 550°C); and a new effort by Schott Rohrglas to develop an 

entire HCE product. A German/Spanish consortium is in the final stages of planning for two commercial 

50-MW trough plants in Spain. Italy has a major new program ($100M) focused on troughs with a molten salt 

working fluid, to allow both higher temperatures and better integration with storage. Both activities plan to use 

the Solar Two-proven molten salt technology for storage. 

South Africa has extensively assessed both trough and tower technology and recently selected U.S. tower 

technology (with extensive in-country content and manufacturing) for a 100-MW proposed project. However, in 
 

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Europe and Israel, tower technology has evolved quite differently. The Europeans (specifically, the Germans 

and Spanish) have focused on systems using air as the working fluid. The near-term application pulls air at 

atmospheric pressure through a porous metal or ceramic mesh (the so-called volumetric receiver concept) 

illuminated by the heliostat field, generating temperatures of about 700°C, ultimately for use in steam generation 

at 550°C for Rankine cycles (identical to current U.S. molten-salt system Rankine temperatures). The Europeans 

have investigated rock and ceramic packed-bed storage options that, while not nearly as efficient as two-tank 

molten salt systems, have continued to drop in cost through the development process, although they have not yet 

achieved the costs of molten salt systems. A Spanish/German consortium plans to use this technology in the 

10-MW PS10 project, which was expected to begin construction in Southern Spain in late 2002 or early 2003. 

Because 700°C is a relatively conservative temperature limit for this technology (there are no temperature limits 

on air, and ceramic receivers of this design can go to much higher temperatures), temperature increases to 

accommodate advanced steam turbines operating above 600°C are relatively straightforward. 

To expand options further, the Germans are also aggressively investigating pressurized volumetric receiver 

concepts using quartz windows, reflective secondary concentrators, and ceramic mesh absorbers capable of 

operating at several atmospheres and temperatures of 900°–1,200°C. The quartz windows limit the size of each 

receiver, so they are packed into hexagonal arrays (the secondary concentrators have a hexagonal entrance 

aperture) to achieve higher power levels. Individual receiver elements have been successfully demonstrated over 

the past 10 years, and they are currently testing the first multi-module array (Sugarman et al. 2002). If 

successful, this technology will ultimately open options for coupling to higher-efficiency Brayton cycles or 

combined cycles. There are, of course, many technical challenges to this receiver concept (in the secondary 

reflectors, the windows, and the ceramic mesh durability), and commercial implementation is still quite a few 

years away, at best. Nonetheless, DOE/SunLab follows the European development closely and considers this 

technology credible. For a variety of reasons (see advanced applications below), DOE/SunLab has conducted 

preliminary development in this area in the past, with those investigations ultimately being terminated due to 

budget restrictions, not a lack of technology promise. 

The Israelis have carried this concept one step further, proposing to put a large hyperbolic secondary reflector on 

top of a tower to “beam down” the concentrated solar energy to ground level (Yogev et al. 1998). This would 

theoretically allow more options for the high-temperature receiver and coupling of the high-temperature air 

working fluid to a Brayton cycle or other application. They have successfully demonstrated (without the beamdown mirror) pressurized air volumetric receiver operation at temperatures above 1,200°C (Kribus 2001). They 
 

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are currently testing a 700-kW beam-down experiment on the tower at the Weizmann Institute of Technology 

solar power tower test facility. The higher precision required for the heliostat field, as well as thermal and wind 

loads on the tower-mounted secondary mirror, have limited success to date. This technology likely has years of 

development ahead, if indeed it will ever be feasible. 

2.4.3 Long-Term CSP Advanced Applications Options 

Over the last dozen years or so, budget restrictions in the U.S. CSP program have limited the focus to near-term 

electric power generation options. Since power generation is the simplest interface for CSP technologies and 

since low-cost, reliable concentrators will be needed for any advanced applications, this continues to be the most 

productive approach with limited budgets. However, there are a number of potential, long-term applications that 

take advantage of the high-temperature capabilities of tower technology. These include not only the higher 

temperature (and thus more efficient) Rankine and Brayton electric power cycles discussed above, but also a 

range of solar chemistry applications that could potentially make CSP a major source of energy in the fuels and 

chemicals sector. 

For example, the DOE has successfully demonstrated the thermo-catalytic reforming of natural gas and other 

organics with steam or carbon dioxide (at temperatures of 800°–900°C). The Israelis, Swiss, Germans, and 

Australians continue to develop this technology today. In this approach, a tower uses reactors similar to the 

closed volumetric receivers described above, except that a rhodium or another catalyst is dispersed on the 

surface of the ceramic mesh, directly absorbing the solar energy to produce syngas, hydrogen, and carbon 

monoxide (Moller et al. 2002). In an open-loop system, the syngas can be further hydrogen enriched via a watergas shift reaction for several possible applications, including hydrogen production for other uses, including 

direct combustion, or further conversion to methanol for liquid fuel use. In a closed-loop system, the syngas can 

be stored (effectively chemically storing solar energy for longer periods than thermal storage) or transported 

over distances up to a hundred kilometers for process heat or power generation via the reverse reaction 

(methanation), in which the syngas is converted back to methane for reuse in the solar reactor. 

With their high-temperature capabilities, towers (and CSP dish technology) can also be used to drive a number 

of thermochemical, hydrogen production cycles that operate at 800°C and higher. For example, towers could 

“fuel” the following thermochemical cycles: the sulfur-iodine cycle currently being investigated by the nuclear 

industry for powering by a nuclear high-temperature gas-cooled reactor (HTGR); the Zn/ZnO cycle under 

intensive study in Switzerland and Israel (Wieckert et al. 2002); U.S. activity in methane decomposition (Dahl et 
 

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al. 2002); and other high-temperature, solar thermal decomposition reactions. While CSP can theoretically 

generate the temperatures required for hydrogen production by direct water splitting, theory is a long way from 

practice in both receiver design and separation technology. Nonetheless, high-temperature electrolysis (where a 

portion of the electrical energy needed for electrolysis is offset by high-temperature thermal energy) is 

considered feasible in the long term and has been investigated at a variety of institutions. 

Finally, technology advancements in the last 20 years have been dramatic (e.g., computers, communications, 

and biotechnology) and have been characterized by unforeseen developments in other areas of research. It is not 

unreasonable to expect that, over the course of the next 20 years, we will see advancements not now anticipated 

in areas such as materials research that could have a significant impact on CSP technology. 
 

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3. POWER GENERATION MARKET AND DEPLOYMENT FORECAST 

The projections for electrical power consumption in the United States and worldwide vary depending on the 

study, but there will be a significant increase in installed capacity due to increased demand through 2020. 

Trough and tower solar power plants will compete with technologies that provide bulk power to the electric 

utility transmission and distribution systems. The following market entry barriers are the most significant to 

overcome: 

• Market expansion of trough and tower technology will require incentives to reach market 

acceptance (competitive). Incentives include environmental (CO2 emission credits), favorable 

tax credits, favorable peak energy tariff, premium consumer pricing, loan guarantees, low 

interest loans, and grants. Both tower and trough technology currently produce electricity that is 

more expensive than conventional fossil-fueled technology. Analysis of incentives required to 

reach market acceptance is not within the scope of the report. 

• Significant cost reductions will be required to reach market acceptance (competitive). Cost 

reductions occur from technical improvements, increase in plant size (scaling), and volume 

production (learning curves). This report focuses on the potential of cost reductions with the 

assumption that incentives will occur that will support deployment through market expansion. 

3.1 POWER GENERATION MARKET 

There are several recent studies that discuss the market for CSP technology (Teagan 2001; World Bank 1999; 

EERE 2002). A number of international and national project developments for commercial or commercial-entry 

trough or tower power plants typically in the capacity range of 15 MWe to 100 MWe are being pursued by the 

industry. These entry opportunities largely arise from activities of the Global Environment Facility,*

 selected 

nations and U.S. programs on Renewable Portfolio Standards, or other incentives to encourage renewable 

energy systems. 

A summary of the current market is as follows: 

• Global Environmental Facility. The Global Environmental Facility (GEF) has identified CSP 

technology as one of their renewable energy options, and has approved four $50M grants for 

CSP solar power plants in India, Egypt, Morocco, and Mexico. 

• United States. The parabolic trough industry (specifically Duke Solar Energy) is aggressively 

pursuing individual IPP projects opportunities in Nevada, California, Arizona, and Oregon as 

 

*

 The Global Environment Facility (GEF) helps developing countries fund projects and programs that protect the global 

environment. Established in 1991, GEF is the designated financial mechanism for international agreements on biodiversity, 

climate change, and persistent organic pollutants. GEF also supports projects that combat desertification and protect 

international waters and the ozone layer. GEF funding comes via the World Bank and UNDP. 
 

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large as 80-MWe steam Rankine cycle projects to as small as 1-MWe organic Rankine cycle 

systems. From a more general perspective, Congress asked DOE with the fiscal year 2002 

funding authorization to “develop and scope out an initiative to fulfill the goal of having 

1,000 MW of new parabolic trough, power tower, and dish/engine solar capacity supplying the 

southwestern United States by 2006” (EERE 2002). DOE, the CSP industry, and SunLab have 

collaborated on the development of a report to Congress on the implementation of a plan to 

achieve this goal. In early 2002, the Western Governors’ Association expressed its high interest 

in the implementation of 1,000 MW of CSP in the Southwest in a letter directed to Congress. 

• South Africa. ESKOM, the national utility in South Africa, has been comparing troughs and 

towers to select a single technology for their first CSP plant in South Africa. In September 

2002, their board approved the recommendation to proceed with the central receiver technology 

only. Their plan is to gather the cost inputs in sufficient detail to take a proposal to their Board 

of Directors by the end of this year proposing a 100-MW central receiver station with molten 

salt thermal storage to be sited somewhere in the northwest part of the country, probably in the 

vicinity of the city of Upingt. 

• Spain. In August 2002, the Spanish Government approved a modification of Royal Decree 

2818 providing substantial incentives for the erection of IPP solar thermal power plants fueled 

exclusively by solar radiation, i.e., no hybrid operation. This modification of Royal Decree 2818 

grants a premium of €0.12 above the market price for electricity generated from solar thermal 

energy in facilities with a maximum unit power of 50 MW. Four projects have been proposed 

by industry, as follows: 10-MWe tower project based on European technology; 15-MWe tower 

project based on U.S. technology; 10-MWe trough prototype based on U.S. technology; two 

50-MWe trough projects based on European technology. Work is now proceeding on the 

commercial financing and development of these projects. 

• Israel. The Israel Ministry of National Infrastructures, which is also responsible for the energy 

sector, decided in November 2001 to propose CSP as a strategic ingredient into the Israel 

electricity market over the next several years, with a minimal power unit of 100 MWe. There is 

an option to increase the CSP contribution up to 500 MWe at a later stage, after the successful 

operation of the first unit. The plant is to operate in hybrid mode, 4,400 hr/yr, 50% of which is 

solar and the rest natural gas. A final decision on the plan is expected in late 2002. 

Industry participation is also an indicator of market potential. There are a number of companies actively 

participating in research and development, marketing, and engineering in support of tower and trough 

technology. Nexant, Boeing, and Duke Solar are the key participants in the United States. Internationally, the 

key participants are Solel, Flabeg, Solar Millennium, and Fichtner. 

3.2 DEPLOYMENT FORECAST 

Cost reductions occur from technical improvements, increase in plant size (scaling), and volume production 

(learning curves). All three are dependent on deployment (development) of CSP technology. Deployment 

requires movement through various phases: pilot testing, commercial validation, commercial niche market, 
 

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market expansion, and market acceptance (Morse 2000). Deployment provides a means for continued research 

in technology improvements, cost reductions due to increased production, and economy of scale from 

constructing larger plants. The cost reduction analysis provided in this report is based on the assumption that 

trough and tower plants will be constructed. S&L’s review is based on a deployment range between 

2.4 gigawatts-electrical (GWe) and 9.5 GWe of installed tower and trough solar power plants. The major cost 

reduction is from the increased size of the plant and increased electrical production. The cost reduction 

associated with increased volume production between 2.6 GWe and 9.5 GWe (from year 2004 to 2020) is about 

10%. 

Estimates of tower and trough solar power plants deployment have been identified in several reports (Morse 

2000). Comparison of these estimates and the SunLab and S&L estimates are shown in Figure 3-1. 

Figure 3-1 — Summary of CSP Worldwide Deployment Forecast 

0.354

45

30

13.6

9.6

2.4

0

5

10

15

20

25

30

35

40

45

50

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Cummulative Installed Generation (GWe)

Enermodal

Pilkington

Sunlab

S&L Range

The commercialization path for trough and tower technologies was presented in the Morse report (2000) as 

occurring in five phases: pilot testing, commercial validation, commercial niche market (entry), market 
 

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expansion, and market acceptance. The program to move CSP technologies through commercial niche market 

and market expansion to market acceptance is shown in Figure 3-2: 

Figure 3-2 — CSP Path to Market Acceptance 

 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022

Trough Solar Power 

Plants 

Commercial Niche 

Market 

 

 Market 

Expansion 

 

 Market 

Acceptance 

 

Tower Solar Power 

Plants 

Commercial 

Validation 

 

 Commercial Niche 

Market 

 

 Market 

Expansion 

 

 Market 

Acceptance 

3.3 TROUGH 

Sargent & Lundy’s review and assessment of the SunLab deployment projections for trough solar power plants 

is included in Appendix D.2. While the trough technology was commercialized for a brief period, no trough 

plants have been built in nearly a decade. Trough solar plants are a proven technology, and 354 MW of trough 

technology generation at the SEGS plants have and are still being operated commercially. 

The following Table 3-1 shows a case of two scenarios set forth by SunLab that are representative of how 

systems would be deployed commercially if a market existed. The first assumes one plant built per year. The 

second assumes a doubling of cumulative installed capacity with each new technology case introduced. This 

second case is an aggressive development scenario; however, if the projects were financially competitive, this 

represents a plausible development scenario. The second case is the type of scale-up that Luz envisioned and 

actually achieved with the SEGS plants to some degree, building multiple plants in the same year. 
 

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Table 3-1 — Trough Deployment Scenarios 

Year 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

Technology 

Cases X X X X X 

Case 1 Deployment Scenario: One Plant per Year Deployment 

2004 

Technology 

100 

MW 1 1 1 300 650 

2007 

Technology 

100 

MW 1 1 1 300 950 

2010 

Technology 

150 

MW 1 1 1 1 1 750 1,700 

2015 

Technology 

200 

MW 1 1 1 1 1 1,000 2,700 

2020 

Technology 

400 

MW 1 400 3,100 

Total 2,750 

 

Case 2 Deployment Scenario: Cumulative Capacity Doubled with Each New Technology Case 

2004 

Technology 

100 

MW 1 1 1 300 650 

2007 

Technology 

100 

MW 1 2 2 1 600 1,250 

2010 

Technology 

150 

MW 1 1 2 2 2 1,200 2,450 

2015 

Technology 

200 

MW 1 2 2 3 3 1 2,400 4,850 

2020 

Technology 

400 

MW 1 400 5,250 

Total 4,900 

The actual strategy employed by the plant suppliers can be significantly diverse, with more emphasis on nearterm cost reduction with a minimum of risk. The suppliers may opt to provide multiple plants in the 50-MWe to 

100-MWe size range with no thermal storage but with a supplemental steam generator, replicating the proven 

technology of the existing SEGS plants. The suppliers can rely more on initial production volume to reduce 

costs as opposed to efficiency and technology improvements and scale-up factors. Minimizing or eliminating 

thermal storage, with its current elevated cost, appreciably reduces the total direct cost of the plant as discussed 
 

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later in this section of the report. The suppliers’ strategy will vary depending on the extent of trough plant 

deployment. 

3.4 TOWER 

Sargent & Lundy’s review and assessment of the SunLab deployment projections for tower solar power plants is 

included in Appendix E.2. The first step will be deployment of the first commercial power tower facility in 

Spain (Solar Tres). The Solar Tres design and cost estimate are based on the successful demonstration projects 

Solar One and Solar Two. “Commercial” is defined as when a power plant is providing electrical power to 

customers. The next commercial plant will be Solar 50, which is a significant increase in plant size. The net 

electrical output increases 36.5 MWe (factor of 3.7) and the thermal capacity increases by 260 MWt (factor of 

3.2). Solar 50 is the first commercial plant of sufficient size to allow a number of larger plants to be developed. 

The next commercial steps include Solar 100 and Solar 200. Solar 200, which consists of a net electrical 

capacity of 200 MWe and thermal capacity of 1,400 MWt (12.7 hours operation at peak output), is about the 

optimum size monolithic single receiver plant based on physical limitations of technology (specifically, the 

distance from the heliostat to the receiver). Larger plants are feasible with multiple power towers deployed. The 

final deployment is Solar 220, which considers an advanced heliostat design and advanced electrical turbinegenerator. 

Table 3-2 shows two scenarios: projection by SunLab and projection by S&L. 

Table 3-2 — Power Tower Deployment Projections, SunLab and S&L 

MWe\ Year 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

SunLab – 

8.7 GWe 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 2 3 300 314 

Solar 100 100 1 2 3 4 4 4 4 2 2 1 2,700 3,014 

Solar 200 200 1 1 1 3 3 4 4 5 4,400 7,414 

Solar 220 220 1 5 1,320 8,734 

 13.5 0 50 100 250 200 300 400 600 600 600 800 800 900 1,020 1,000 1,100 8,734 
 

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MWe\ Year 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

S&L – 2.6 

GWe 

 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 1 1 1 200 214 

Solar 100 100 1 1 1 1 400 614 

Solar 200 200 1 1 1 600 1,214 

Solar 220 220 0 0 

 13.5 0 0 0 0 50 0 50 50 150 0 100 100 300 0 200 200 1,214 
 

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4. EVALUATION OF POTENTIAL FOR COST REDUCTIONS — TROUGH 

4.1 DEVELOPMENT PLAN FOR COST REDUCTION 

The SunLab trough model DueDiligence11–Excelergy11-14-01.xls (SunLab 2001) depicts the industry plan for 

long-term cost reduction. The industry plan keys on thermal storage to obtain a high capacity factor, which 

reduces the O&M costs ($/MWh) by obtaining a higher annual MWh generation. In combination with thermal 

storage, increased annual net efficiency, and reduced equipment cost via technology advancements, competition 

and deployment are primary elements in reducing the long-term capital costs of the trough plant. 

The parabolic trough industry has developed a proprietary plan to lower costs, emphasizing the near-term, which 

cannot be shared in detail since it would compromise their ability to compete in the domestic and international 

market. However, the SunLab model provides a cost estimate that closely follows the industry expectations for 

research and development advances in component and subsystem improvements. Whereas the SunLab plan for 

plant implementation assumes, for comparative purposes, the use of thermal storage starting in 2004, the U.S. 

trough industry is pursuing a commercialization plan that favors implementation of SEGS-type plants in the 

near-term. With this plan, industry has set cost goals that target a solar field cost less than $200/m2

 and an 

installed plant cost in the 2,000–2,400 $/kW range by 2006. The industry considers this plan a low-risk 

approach, with plants similar to the existing SEGS type plants able to produce electricity in a hybrid model. By 

incorporating this hybrid option, the only increase to the solar-only portion of the project is the relatively small 

capital cost of a boiler cost of fuel and fuel costs during hybrid operation. Near-term development of this plan is 

shown below in Table 4-1. 

Table 4-1 — Near-Term Development for Trough Industry 

Case* Baseline Trough Industry Near Term

Project SEGS VI 

Hybrid

Trough 50 

Hybrid (US)

Trough 50 

TES (Spain)

Trough 40 

ISCCS (GEF)

In Service 1989 2004 2004 2004

Net Power (MWe) 30 50 50 40 

Capacity Factor (%) 22/34% ** 29/40% ** 47% 28% 

Solar Field (km2) 0.188 0.312 0.496 0.184 

Heat Transfer Fluid VP-1 VP-1 VP-1 VP-1 
 

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Case* Baseline Trough Industry Near Term

Project SEGS VI 

Hybrid

Trough 50 

Hybrid (US)

Trough 50 

TES (Spain)

Trough 40 

ISCCS (GEF)

In Service 1989 2004 2004 2004

SF Operating Temperature (°C) 391 391 391 391 

Thermal Storage (hrs) 0 0 9 0 

Thermal Energy Storage NA NA Indirect 

2-Tank 

NA 

Thermal Storage Fluid NA NA Solar Salt NA 

Land Area (km2) 0.635 1.052 1.675 0.623 

Comment Hybrid 

backup 

Hybrid 

backup 

Indirect 

2-Tank TES 

None 

* All cases assume Kramer Junction 1999 radiation 8.054 kW/m2/day. 

** Solar Only / Hybrid Operation 

Cost reductions in parabolic trough plants are discussed from a reference point of the nine operating SEGS 

plants in the California Mojave Desert. Future cost reductions derive from technical improvements, scale-up in 

individual plant megawatt capacity, increased deployment rates, competitive pressures, use of thermal storage, 

and advancements in O&M methods. Cost drivers have been identified from SunLab activities and from 

industry input. Duke Solar Energy is a key industrial participant in trough technology and is actively engaged in 

developing trough power plant opportunities as well as an advanced collector design. 

The development and operation of the SEGS plants by Luz International, totaling 354 MWe net installed 

capacity, provide the baseline for future performance and cost projections. Projected cost reductions are tied to 

the future development path shown in Table 4-2. 
 

 4-3 

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Table 4-2 — Trough Technology Summary for SunLab Technology Cases 

 SunLab Technology Cases

Case Baseline Near Term Mid Term Long Term

Project SEGS VI 

Hybrid Trough 100 Trough 100 Trough 400

In Service 1989 2004 2010 2020

Net Power (MWe) 30 100 150 400 

Capacity Factor (%) 22 

(solar only) 

54% 56% 57% 

Solar Field (km2) 0.188 1.120 1.477 3.910 

Heat Transfer Fluid VP-1 VP-1 Hitec XL Advanced 

Solar Field Operating 

Temperature (o

C) 

391 391 500 500 

Thermal Storage (hrs) 0 12 12 12 

Thermal Energy Storage NA Indirect 2-

Tank 

Direct 

Thermocline 

Direct 

Thermocline 

Thermal Storage Fluid NA Solar Salt Hitec XL Advanced 

Land Area (km2) 0.635 3.780 4.98 13.189 

However, the actual strategy employed by the plant suppliers can be significantly diverse, with more emphasis 

on near-term cost reduction with a minimum of risk. As discussed above, for the near-term, the suppliers may 

opt to provide multiple plants in the 50-MWe to 100-MWe size range with no thermal storage but with a 

supplemental steam generator, replicating the proven technology of the existing SEGS plants. In a series of 

evolutionary design improvements, the following major advancements formed the basis of the SunLab 

estimates: 

• Collector 

 A comprehensive series of wind tunnel tests on parabolic trough collector models was 

carried out in 2001–2002, establishing design pressure force coefficients for various wind 

approach angles and collector orientations, with and without a wind fence. 

 Using these coefficients, finite element methods stress analyses were used to optimize the 

collector structure for wind survival conditions, minimizing collector weight and defining 

design parameters for mirror strength, pylons, and foundations. With more tightly known 

design parameters, the collector weight, and thus costs, can be lowered. 
 

 4-4 

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 High efficiency and durable receivers are assumed to be developed, with selective surfaces 

(consisting of special selective coatings on the metal tube receivers) to maximize the 

absorption of incident solar radiation and minimize radiation losses from the receiver. High 

efficiencies result in smaller solar fields for a given thermal energy delivery and in longer 

lifetimes to reduce operation and maintenance costs. 

 Advanced receivers are assumed utilizing selective surfaces that can operate efficiently at 

temperatures of 500°C or higher, paving the way for major advancements in thermal 

storage and power block operation for trough plants. 

 Alternative mirror design development using thin-glass with non-metallic structural 

elements or using thin silverized films is assumed. Both approaches reduce weight and 

offer less expensive reflector options. 

• Heat transfer fluid (HTF) 

 Alternate HTFs, such as inorganic molten salts and ionic fluids, are being investigated that 

will permit operation at higher temperatures (at or above 500°C), leading to lower thermal 

storage costs and higher power block efficiencies. 

• Thermal Storage System 

 The Solar Two two-tank molten salt storage system is designed for commercial operation 

in a trough plant for the case of the conventional synthetic oil HTF. Termed an indirect 

storage system, this also requires an oil-to-salt heat exchanger in the system. 

 This same two-tank molten salt storage system is designed for direct operation with a 

molten salt HTF. 

 A single-tank direct molten salt thermocline system is designed to reduce thermal storage 

costs. 

• Electric Power Block 

 The efficiency of a SEGS-type plant is improved by refining the integration of the solar 

field with the power block. 

 Turbine efficiencies are improved through use of the higher temperature heat transfer fluids 

in the solar field. 

4.2 EFFICIENCY 

The efficiency of the existing SEGS parabolic trough plants has been well documented and provides the basis 

for evaluating the potential performance improvements of future parabolic trough plants. SEGS VI, a 14-yearold 30-MWe plant currently in operation in California, is used as a reference plant to evaluate future efficiency 

improvements. SEGS VI was selected because it was the last plant built using all second-generation Luz 

collector (LS-2) technology. The later third-generation Luz collector (LS-3) used at the larger 80-MWe SEGS 

plants had alignment problems and never operated at the same level of performance achieved at SEGS VI. 
 

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The technological advances and research, upon which the SunLab efficiency improvement estimates are based, 

include the following: 

• The development of the new Solel UVAC receiver. The UVAC has improved thermal and optic 

properties. Field tests of the new receiver at SEGS VI shows a 20% increase in thermal 

performance compared to original receiver tubes. 

• The development of ball joint assembly replacements for flexhoses. A demonstration of new 

ball joint assemblies has been shown to reduce the hydraulic pressure drop in the solar field by 

approximately 50%. This results in lower solar field heat transfer fluid pumping electric 

parasitics. 

• Improvements in mirror washing techniques have resulted in increased solar field average 

mirror reflectance. 

• Investigation of higher temperature heat transfer fluids. 

• Research of direct thermal energy storage. 

• Research of higher temperature receiver selective coatings. 

Table 4-3 shows a breakdown of the elements that contribute to the annual efficiency. The table shows both the 

SunLab goal efficiencies and the S&L estimates based on a less aggressive technology development scenario. A 

more detailed breakdown of all the SunLab cases is shown in Appendix D. The SEGS VI data are based on 

actual plant data from 1999. 

Table 4-3 — Trough Annual Efficiency Summary 

 SunLab Forecast Sargent & Lundy

Case Baseline

Near 

Term

Mid 

Term

Long 

Term

Near 

Term

Mid 

Term

Long 

Term

Project SEGS 

VI 

Trough 

100 

Trough 

150 

Trough 

400 

Trough 

100 

Trough 

150 

Trough 

400 

Year In Service 1989 2004 2010 2020 2004 2010 2020

Solar Field Optical Efficiency 0.533 0.567 0.598 0.602 0.567 0.570 0.570 

Receiver Thermal Losses 0.729 0.860 0.852 0.853 0.843 0.810 0.810 

Piping Thermal Losses 0.961 0.965 0.967 0.968 0.965 0.967 0.968 

Storage Thermal Losses NA 0.991 0.996 0.996 0.991 0.996 0.996 

EPGS Efficiency 0.350 0.370 0.400 0.400 0.370 0.400 0.400 

Electric Parasitic Load 0.827 0.884 0.922 0.928 0.884 0.922 0.928 
 

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 SunLab Forecast Sargent & Lundy

Case Baseline

Near 

Term

Mid 

Term

Long 

Term

Near 

Term

Mid 

Term

Long 

Term

Project SEGS 

VI 

Trough 

100 

Trough 

150 

Trough 

400 

Trough 

100 

Trough 

150 

Trough 

400 

Year In Service 1989 2004 2010 2020 2004 2010 2020

Power Plant Availability 0.980 0.94 0.94 0.94 0.94 0.94 0.94 

Annual Solar-to-Electric 

Efficiency

10.6% 14.3% 17.0% 17.2% 14.0% 15.4% 15.5%

4.2.1 Solar Field Optical Efficiency 

The solar field optical efficiency includes incident angle effects, solar field availability, collector tracking error 

and twist, the geometric accuracy of the mirrors to focus light on the receiver, mirror reflectivity, cleanliness of 

the mirrors, shadowing of the receiver, transmittance of the receiver glass envelope, cleanliness of the glass 

envelope, absorption of solar energy by the receiver, end losses, and row-to-row shadowing. The SunLab 

projected improvements in optical efficiency are due primarily to improvements in the receiver optical 

properties, including the following: 

• Receiver Solar Absorptance. Significant improvements in selective coatings have occurred 

since the last SEGS plant was built. The solar absorptance of the cermet tubes used at SEGS VI 

was approximately 91.5%. According to test data, the Solel UVAC receiver tubes have a solar 

weighted absorptance of 94.4% and further optimization of the selective coating is expected to 

yield solar absorptances of 96% or higher. 

• Receiver Glass Envelope Transmittance. Anti reflective coatings for glass have been 

improved in the last 10 years to improve durability. The new receiver tubes have anti-reflective 

coatings that deliver solar transmittances of 96.5% compared with earlier coating that only 

allowed 92.5%. 

• New Front Surface Reflectors. New front surface reflectors with solar-weighted reflectivity of 

95% are assumed for the SunLab long-term case compared to 93.5% for current thick glass 

mirrors. 

The S&L evaluation is based on a less aggressive technology development approach, basing the maximum 

optical efficiency on the tested receiver tubes weighted absorptance of 94.4% and receiver coatings solar 

transmittances of 96.5%. 
 

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4.2.2 Receiver Thermal Losses 

Receiver thermal losses are primarily driven by the thermal emittance of the receiver’s selective coating 

(radiation losses) and by the vacuum in the receiver (convection losses). As long as vacuum is maintained, 

convection losses are negligible. Radiation losses, on the other hand, are a function of the receiver’s absolute 

surface temperature to the fourth power. The thermal emittance measures the ability of the surface to radiate 

energy away from the receiver. The lower the thermal emittance, the lower the radiation losses from the surface. 

• Receiver Thermal Emittance. SEGS VI had a combination of black chrome and the original 

generation of Luz Cermet receiver tubes. The average thermal emittance of these tubes is 

approximately greater than 20% at 350°C. The UVAC receiver first installed at SEGS VI had a 

thermal emittance of 14% at 400°C. According to tests performed for Solel, the secondgeneration UVAC receiver had a thermal emittance of about 9% at 400°C. SunLab currently has 

a research and development effort exploring high temperature coating designs with low thermal 

emittance and high solar absorptance. 

• Receiver Reliability. As long as vacuum is maintained, convective thermal losses are minimal 

from the receiver. When receivers lose vacuum, the thermal losses from the receiver are 

approximately doubled. Breakage of the glass envelope results in significantly higher thermal 

losses. Loss of vacuum and breakage of the receiver glass envelope have been significant issues 

at the existing SEGS plants. 

4.2.3 Piping Thermal Losses 

Piping thermal losses corresponds to thermal losses from the solar field header piping and heat transfer fluid 

(HTF) system piping. Piping heat losses are a function of the piping surface area and the temperature of the fluid 

in the pipe above ambient temperature. Nexant has developed a parabolic trough solar field piping model for 

sizing the layout of piping headers. This model has been used to determine the heat losses for the various cases. 

The piping model has been baselined against the thermal performance of the SEGS VI solar field. 

• The near-term case operates at temperatures similar to SEGS VI (391°C), thus the heat losses 

are considered to be similar. 

• Piping losses in future cases are similar due to a combination of offsetting factors. The mid-term 

case is based on operating at a higher temperature of 450°C and maintaining the field at a 

minimum of 150°C during non-operational periods to prevent the molten-salt HTF from 

freezing. This higher temperature results in increased thermal losses per unit area of piping. 

However, the new salt fluid has a higher density that requires lower flow rates and smaller 

heater piping. These result in the thermal losses from the solar field being reduced. The longterm case is based on operating at higher temperatures (500°C) and lower flow rates. 
 

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4.2.4 Storage Thermal Efficiency 

Thermal storage efficiency accounts for thermal losses from the thermal storage system. Storage thermal losses 

are a function of the surface area of the storage tanks and the temperature of the fluid above ambient. Large high 

temperature thermal storage systems have been demonstrated at the SEGS I trough plant and Solar Two power 

tower. In these systems, thermal losses have been shown to be minimal; thus the storage thermal efficiency 

approaches 100%. Nexant has developed a thermal storage design model, which was used to determine the heat 

losses. This model is based on the Solar Two thermal storage design and operational experience. 

• Storage thermal losses for the near-term trough plants are slightly larger for trough plants than 

for tower plants. Due to the smaller temperature difference between the hot and cold storage 

tanks in the trough plant, the thermal storage system must be larger to hold the same amount of 

thermal energy. Thus, there is more surface area for the trough plant. However, the hot tank 

temperature at the trough plant will be lower than the tower plants and the thermal losses per 

unit area of tank will be lower. Overall, storage losses are slightly larger at the trough plant; 

however, the storage thermal efficiency is still greater than 99%. 

• Mid-term and long-term thermal storage systems operate at higher temperatures; however, the 

temperature difference between hot and cold is greater. As a result, a smaller volume is required 

to store energy. Also, single tank thermocline storage systems are anticipated. These further 

reduce the required tank volume by replacing a large fraction of the storage fluid with low cost 

filler, sand and gravel, that typically has a higher volumetric heat capacity than the fluid it is 

replacing. Therefore, even though future thermal storage systems operate at higher fluid 

temperatures, the surface area of the thermal storage system is reduced compared to the nearterm storage case and results in improved storage thermal efficiency. 

4.2.5 Turbine Cycle Annual Efficiency 

The turbine cycle annual efficiency accounts for the design point turbine cycle efficiency, start-up losses, partload operation, and losses due to minimum turbine load requirements (especially important for plants without 

thermal storage). 

• The near-term case has the same turbine cycle design point efficiency as SEGS VI (37.7%); 

however, because of thermal storage, the annual turbine cycle efficiency is better than the case 

without thermal storage. The near-term plant with thermal storage has a higher capacity factor 

than SEGS VI (47% versus 34%). Thus, the number of turbine start-ups per MWh generated is 

lower. Thermal storage allows the plant to operate more hours at full load close to peak 

efficiency and reduces the number of hours the plant is operating at part load efficiencies. 

Thermal storage also allows thermal energy to be collected even when it is not sufficient to 

operate the power plant. 

• The power cycle efficiency of the mid-term and long-term cases increases to 39% and 40% as 

solar field operating temperatures are increased to 450°C and 500°C, respectively. 
 

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4.2.6 Electric Parasitic Load 

The main parasitic electric loads are the motors for the heat transfer fluid (HTF) pumps, condensate/feedwater 

pumps, cooling water pumps, cooling tower fans, and boiler of heater forced draft fans. Additional parasitic 

loads are a result of instrumentation, controls, computers, valve actuators, air compressors, and lighting. The 

solar field also adds parasitic loads for the collector drives and communications. 

• A significant reduction in parasitic electric load for the near-term trough technology is based 

primarily on the replacement of flex hoses with balljoint assemblies in the solar field. These 

ball-joint assemblies reduce the pressure drop across the solar field by approximately 50%. The 

addition of thermal storage is also expected to reduce parasitics by spreading the station load 

over increased annual generation. 

• A further reduction in pumping parasitics will occur when the switch is made to molten-salt 

HTF. Because of the higher density of molten salt, lower volumetric HTF flow rates, and thus 

less pumping power, are required. 

4.2.7 Power Plant Availability 

Availability accounts for forced and scheduled outages and deratings of the power plant. Typically, plant 

availability is only affected if solar energy collection/conversion is reduced by an outage or derating. 

• For the most part, the SEGS plants have demonstrated very high power plant availability. 

Normally, plants will take a 1- to 2-week outage during the winter to conduct required annual 

inspections and any corrective maintenance that cannot be accomplished during the normal 

daily operation. Every 10 years, a 5-week major turbine overhaul is conducted. During 1999, 

SEGS VI had a power plant availability of approximately 98% but did not take any planned 

scheduled maintenance outages during the year. 

• Future plants are conservatively assumed to have a 6% annual outage rate. This includes both 

scheduled and forced outages. 

If a higher temperature HTF and compatible thermal storage system can be developed and implemented in the 

mid-term, a 17.0% annual net solar-to-electric efficiency is feasible. Additional investigation and development 

of storage systems, including the optimum HTF for steam cycle efficiency and storage compatibility is required 

to achieve the mid-term efficiency projection. Long-term objectives will require continuing investigation and 

development of thermal storage systems and high temperature HTF. The long-term objectives will also 

necessitate an advanced HCE absorber coating for the projected 500°C operating temperature. 
 

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4.3 EVALUATION OF MAJOR COST COMPONENTS 

The major cost contributors in direct cost of a parabolic trough solar plant with thermal storage are the solar 

collector field (53%), thermal storage system (23%), and power block (14%), as illustrated in Figure 4-1. 

Figure 4-1 — Major Cost Categories for Parabolic Trough Plant 

2004 Near-Term Case: 100 MWe, 12 hours TES, 2.5 Solar Multiple 

58%

23%

3%

14% 2%

Structures and Improvements

(2%)

Solar Collection System

(58%)

Thermal Storage System

(23%)

Steam Gen or HX System

(3%)

Power Block (EPGS, BOP)

(14%)

The major component costs in the solar field are illustrated in Figure 4-2. The key cost elements in the solar 

field are the receiver (20%), the mirrors (19%), and the concentrator structure (29%). 

Figure 4-2 — Solar Field Component Cost Breakdown for Parabolic Trough Plant 

2004 Near-Term Case: 100 MWe, 12 hours TES, 2.5 Solar Multiple 

20%

19%

29%

6%

5%

7%

3%

4%

4% 3%

Receiver (HCE) (20%)

Mirror (19%)

Metal support structure (29%)

Drive (6%)

Interconnection Piping (5%)

Electronics & control (7%)

Header piping (3%)

Pylon Foundations (4%)

Other Civil Works (4%)

Heat Transfer Fluid (3%)

The S&L review focuses on these five major cost components: concentrator structure, mirrors, receivers, 

thermal energy storage, and the power block. Table 4-4 provides a summary of the SunLab and S&L cost 

projections for these five cost elements. 
 

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Table 4-4 — Trough Capital Cost Summary 

 SunLab Sargent & Lundy

Case Baseline

Near 

Term

Mid 

Term

Long 

Term

Near 

Term

Mid 

Term

Long 

Term

Project SEGS 

VI

Trough 

50

Trough 

150

Trough 

400

Trough 

50

Trough 

150

Trough 

400

In Service 1989 2004 2010 2020 2004 2010 2020

Solar Collection System ($/m2) 250 234 161 122 234 195 181 

Support Structure, $/m2 67 61 54 46 67 56 52 

Heat Collection Elements, $/unit 847 847 635 400 847 675 525 

Mirrors, $/m2 43 43 28 18 40 32 26 

Power Block, $/kWe 527 367 293 197 306 270 198 

Thermal Storage, $/kWe NA 958 383 383 958 383 383 

 Total Plant Cost, $/kWe 3,008 4,856 3,416 2,225 4,816 3,562 3,220 

4.3.1 Solar Field Support Structure 

The structure consists of the metal support system of the collectors consisting of the pylons and reflector support 

elements. Wind loads during maximum wind speeds dictate the required strength of these units. Recent wind 

tunnel testing has provided improved data for use in optimizing the structural design, and reducing the weight, 

necessary for long-term reliability. 

The SunLab projections for the structure material and erection are shown in the following Table 4-5. 

Table 4-5 — SunLab Cost Projections 

 Reduction from

 SEGS VI $/kWe

SEGS VI $67/m2 — 420* 

2004 $61/m2 9% 683 

2007 $57/m2 15% 591 

2010 $54/m2 19% 531 
 

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 Reduction from

 SEGS VI $/kWe

2015 $50/m2 25% 489 

2020 $46/m2 31% 450 

*Smaller solar field per kWe due to no storage. 

The baseline cost of $67/m2 is consistent with estimates prepared by Pilkington International (1999) indicating 

$63/m2

. Cost comparisons based on weight for the various structures are illustrated below in Table 4-6. 

Additional cost reductions will be realized by minimization of the number of required parts, simplification of 

fabrication and field erection reducing labor costs for on-site assembly and erection. This cost reduction 

potential has not been quantified in this evaluation since there has not been an actual erection of a new collector 

structure. The individual metal parts of the structure can readily be manufactured by suppliers worldwide, 

leading to potential cost reductions through competition. However, structure cost reductions due to 

commercialization were not specifically considered in this evaluation. 

Table 4-6 — Costs of Various Structures 

LS-2 $58/m2

LS-3 $66/m2

EuroTrough $58/m2

Duke Solar $48/m2

IST $48/m2

Based on the current activity in progress by the various suppliers, obtaining the projected cost reductions for the 

structure represents a low risk. The current weight reduction presented by the suppliers has the potential to meet 

the projected cost reduction. 

4.3.2 Solar Field Heat Collection Elements (HCE) 

The receivers, or heat collection elements (HCEs), are a major contributor to trough solar field performance. 

Luz manufactured this solar field component in-house, which has continued under Solel Solar Systems who 

acquired the Luz manufacturing facilities. HCEs supplied to the SEGS plants for spare parts over the last decade 

by Solel have shown improvements in performance and reliability. These include improved optical properties 
 

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with regards to absorptivity and better protection of the glass-to-metal seal to increase in-service lifetime. The 

SunLab projected HCE deployment and costs are shown in Table 4-7. 

Table 4-7 — SunLab Projected HCE Deployment and Costs 

Project SEGS VI Trough 

100 

Trough 

100 

Trough 

150 

Trough 

200 

Trough 

400 

In Service 1999 2004 2007 2010 2015 2020 

Number of HCE 9,600 57,216 45,700 65,072 86,101 172,201 

Number of HCE Accumulative 9,600 66,816 112,516 177,588 263,688 435,889 

Cost, $/m2 field 43 43 34 28 22 18 

Cost, $/unit 847 847 762 635 508 400 

A comparison of the S&L estimated HCE costs and the SunLab projected costs is shown below in Table 4-8. 

Table 4-8 — Comparison of HCE Costs 

Year 

SunLab Projected 

Cost, $/unit 

S&L Estimate, 

$/unit 

2004 847 847 

2007 762 762 

2010 635 675 

2015 508 625 

2020 400 600 

The heat collection elements, which constitute a major portion of the direct capital cost, currently have only one 

supplier (Solel). Additional suppliers will promote competition and reduce costs. A major European and 

worldwide specialty glass parts supplier, Schott Rohrglas, has recently announced its intent to produce this 

component. An increase in the number of HCEs as projected by SunLab will reduce the cost based on the 

experience curve cost reduction, but not to the projected $400/unit. 

Advanced development of the HCE is required for the higher operating temperatures in the planned molten-salt 

heat transfer fluid (HTF) applications, as discussed in the thermal storage section of this report. Additional 

development is also required to address the excess failure rates that have occurred at the SEGS plants compared 
 

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to expected levels. The HCE development focus now is on developing a more robust and lower cost glass-tometal seal design and on identifying higher-temperature selective coating with better thermo/optic properties. 

Sandia has identified new materials that could be used in the glass-to-metal seal to reduce the potential stress in 

the seal. In general, however, the current Housekeeper seal used in the HCE is very expensive and a significant 

part of the total receiver cost. Sandia has also identified some new glass-to-metal seal options that have the 

potential to be much lower in cost to manufacture and be more robust at the same time. NREL has been 

evaluating new selective coatings. Several new cermet coatings have been identified that may be easier to 

manufacture and have better thermo/optic properties. These are multi-layer cermets as opposed to the graded 

cermet used by Solel. The graded cermets require a sputtered manufacturing process, whereas the multilayer 

coating can probably be deposited with simpler coating processes and should also have better quality control of 

the final properties. NREL is also looking into changing the materials used in the cermet to give better high 

temperature performance and stability. Both the design work and the coating development are being funded in 

the current DOE budget and will be continued next year. 

Alternate HCE designs (Zhang et al. 1998; Morales and Ajona 1998; San Vicente, Morales, and Gutiérrez 

2001), which are in various stages of development, indicate a lower cost than the Solel UVAC HCE, but at 

reduced efficiency levels. Reduced HCE efficiency will result in a lower net annual solar-to-electric efficiency 

and require a larger collector area. As noted above, Schott Rohrglas, a large international supplier of specialty 

glass and related products, has recently announced its entry into the HCE supply market. However, start-up of 

HCE production is a significant cost, and a viable market growth is imperative to justify market entry for a new 

supplier. 

4.3.3 Solar Field Mirrors 

The reflectors used in the SEGS plants consist of 4-mm low-iron float glass mirrors thermally sagged during 

manufacturing into a parabolic shape. A single manufacturer supplied the mirrors for the SEGS plants at 

construction and for spare parts since that time. Mass production and competition can lower the cost 

significantly, as can technical improvements. The SunLab projected mirror costs are shown in Table 4-9. 
 

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Table 4-9 — SunLab Projected Mirrors Costs 

Project SEGS 

VI 

Trough

100 

Trough

100 

Trough 

150 

Trough 

200 

Trough 

400 

In Service 1999 2004 2007 2010 2015 2020 

Mirrors, $/m2 field 40 40 36 28 22 16 

Alternatives to glass mirror reflectors have been in service and under development for more than 15 years. It is 

noted that all the identified alternatives are in various stages of initial development or testing. The major current 

developments are listed below. 

• Thin glass mirrors are as durable as a glass reflector and relatively lightweight in comparison to 

thick glass. However, the mirrors are more fragile, which increases handling costs and breakage 

losses. To address corrosion problems, new thin glass experimental samples were recently 

developed and are being tested under controlled conditions. 

• 3M is developing a nonmetallic, thin-film reflector that uses a multi-layer Radiant Film 

technology. The technology employs alternating co-extruded polymer layers of differing 

refractive indices to create a reflector without the need for a metal reflective layer. 3M plans to 

develop an improved solar reflector with improved UV screening layers and a top layer 

hardcoat to improve outdoor durability. 

• ReflecTech and NREL are jointly developing a laminate reflector material that uses a 

commercial silvered-polymer reflector base material with a UV-screening film laminated to it to 

result in outdoor durability. Initial prototype accelerated-exposure test results have been 

promising, although additional work on material production is needed. The material would also 

benefit from a hardcoat for improved washability. 

• Luz Industries Israel created a front surface mirror that consists of a polymeric substrate with a 

metal or dielectric adhesion layer; a silver reflective layer; and a proprietary, dense, protective 

top hardcoat. 

• SAIC of McLean, Virginia, and NREL have been developing a material called Super Thin 

Glass. This is also a front surface mirror concept with a hard coat protective layer. 

• Alanod of Germany has developed a front surface aluminized reflector that uses a polished 

aluminum substrate, an enhanced aluminum reflective layer, and a protective oxidized alumina 

topcoat. These reflectors have inadequate durability in industrial environments. A product with 

a polymeric overcoat to protect the alumina layer has improved durability. 

At this point, thick glass will likely remain the preferred approach for large-scale parabolic trough plants, 

although alternative reflector technologies may be more important in the future as more advanced trough 

concentrator designs are developed. 
 

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Based on the current activity underway by the various suppliers, obtaining the projected cost reductions for the 

mirrors represents a low risk. The current costs presented by the suppliers have the potential to meet the 

projected cost reduction. Having active suppliers performing development promotes lower costs through 

competition. It is expected a portion of the mirror development will be in the realm of the manufacturers. 

4.3.4 Power Block 

There are recognized scale-up cost reductions for the power block. Using the SOAPP software program (SOAPP 

undated), S&L estimated the scale-up factor for increasing the plant size from 100 MW to 400 MW, as depicted 

on Figure 4-3. The projected SunLab values are included for comparative purposes. Power block costs (Figure 

4-3A) include the steam turbine and generator, steam turbine and generator auxiliaries, feedwater, and 

condensate systems. Balance-of-plant costs (Figure 4-3B) include general balance-of-plant equipment, 

condenser and cooling tower system, water treatment system, fire protection, piping, compressed air systems, 

closed cooling water system, plant control system, electrical equipment, and cranes and hoists. 

Figure 4-3A — Scale-Up Cost Reductions: Power Block ($/kW) 

y = 1275.8x-0.3145

150

200

250

300

350

400

100 150 200 250 300 350 400

Megawatts

$/kW

Power block costs include the steam turbine and generator, 

steam turbine and generator auxiliaries, feedwater and 

condensate systems
 

 4-17 

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Figure 4-3B — Scale-Up Cost Reductions: Balance-of-Plant ($/kW) 

y = 461.33x-0.1896

100

150

200

250

100 150 200 250 300 350 400

MW

$/kw

SunLab Projections Power (Calculated (SOAAP))

Balance of Plant costs include general balance of plant 

equipment, condenser and cooling tower system, water 

treatment system, fire protection, piping, compressed air 

systems,closed cooling water system, plant control 

system, electrical equipment, and cranes and hoists.

A comparison of the SunLab projected cost versus the SOAPP predicted $/kW cost for the power block plus the 

balance-of-plant is shown in Table 4-10. 

Table 4-10 — Power Block and BOP Cost Comparison 

Total Power Block + BOP 2004 – 2007 2010 2015 2020 

Plant size, MWe 100 150 200 400 

SunLab Projected Cost, $/kWe 581 525 472 383 

SOAPP Estimate Cost, $/kWe 499 450 399 346 

The estimated costs based on the SOAPP program indicate that the SunLab projected costs for the power block 

are conservative (on the high side), approximately $50/kW higher than estimated by the SOAPP program. The 

SunLab power block cost estimates are based on a 1990 ABB quotation for a 100-MW steam turbine. The ABB 

quotation was escalated and scaled-up for the larger sizes. The SunLab power block cost estimates are based on 

dated information, and the escalation and scale-up factors add to the uncertainty of the data with respect to 
 

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current pricing. Equipment prices in the SOAPP program reflect 2001 actual costs. Since the SOAPP pricing is 

current, the SOAPP-generated costs were used in this evaluation. 

As previously discussed, to achieve the near-term increased Rankine cycle efficiency, the HTF will have to be 

changed to obtain higher inlet steam temperatures. For the near-term, additional development and field testing is 

required on alternate HTF for higher temperature applications. For the long-term, not only is alternate HTF 

development required but the current HCE absorber coating upper temperature limit must be raised by new 

developments to the projected 500°C operating temperature. 

4.3.5 Thermal Storage 

The SunLab projected thermal storage costs are shown in Table 4-11. Note that the SunLab projections are 

based on 12 hours of thermal storage for each case. 

Table 4-11 — SunLab Projected Thermal Storage Cost 

2004 2007 2010 2015 2020

Plant size, gross, MWe 110 110 165 220 440 

Storage, MWht 3,525 3,349 4,894 6,525 13,050 

Type Indirect 

Two-Tank 

Direct 

Thermocline 

Direct 

Thermocline 

Direct 

Thermocline 

Direct 

Thermocline 

Heat Transfer Fluid VP-1 / Solar 

Salt 

HitecXL HitecXL HitecXL HitecXL 

HTF Temperature, °C 400 450 500 500 500 

SunLab Projected $/kWh 27.1 12.7 11.7 11.7 11.7 t

 $/kWe 958 425 383 383 383 

Definitive cost estimates for an indirect two-tank storage system based on detailed design drawings and material 

takeoffs were developed by Nextant. The unit costs were $36.4/kWht for a 470-kWht system and $31/kWht for a 

688 kWht system. The SunLab projection appears to be conservative (on the high side) based on the previous 

estimates. 

However, the goal to reduce the thermal storage system capital cost in the $10/kWht to $12/kWht range will 

require additional investigation and development of both indirect and direct storage systems, including the 
 

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optimum HTF and storage fluid for steam cycle efficiency and storage compatibility. The amount and type of 

storage have significant impacts on the total cost of the plant and are key considerations for cost reductions. 

The year 2007 projection for a direct thermocline storage uses HitecXL (ternary) HTF in both the solar field and 

the thermal storage system, which eliminated the need for the heat exchangers between the solar field and 

storage system. In addition, the solar field can be operated to higher outlet temperatures (450°C), increasing the 

power cycle efficiency and further reducing the cost of thermal storage. The 2007 direct thermocline storage 

value of $12.7/kWht in the SunLab projection appears to be reasonable, if the direct thermocline storage system 

is successfully developed, based on the following: 

• The power tower storage cost is $8.3/kWht for 12 hours at Solar 100. 

• Trough plants have a smaller temperature differential in the thermal energy storage system 

450°C – 293°C (157°C) vs. 566°C – 288°C (278°C) in tower plants. 

• Trough plants have a lower power cycle efficiency, 39% at 450°C vs. 44% at 550°C. 

• The trough plants use a thermocline storage system that eliminates one tank and replaces the 

majority of storage fluid with a lower-cost filler material. Nextant estimates indicate that a 35% 

cost reduction can be achieved going from a two-tank system to a thermocline system. 

Trough Storage Cost (2007) = $8.3/kWht * (278°C/157°C) * (44%/39%) * (1-0.35) 

 = $10.7/kWht 

Subsequent projections after the year 2007 also use a direct thermocline system with HitecXL (ternary) solar salt 

as the storage media and HTF. The SunLab TES cost estimate of $11.7/kWht appears to be reasonable, if the 

solar field can be operated to higher outlet temperatures of 500°C and an advanced heat collection element for 

the 500°C HTF operating temperature is developed, based on the following calculation: 

Trough Storage Cost (2010) = $8.3/kWht * (278°C/207°C) * (44%/40%) * (1-0.35) 

 = $7.9/kWht 

4.3.6 Total Investment Costs 

The SunLab model projects parabolic trough plant capital and O&M costs based on various technology 

advances and commercial deployment predictions. The SunLab projections are considered the best-case analysis 

where the technology is optimized and a high deployment rate is achieved. S&L developed capital and O&M 

costs based on a more conservative approach whereby the technology improvements are limited to current 

demonstrated or tested improvements and with a lower rate of deployment than used in the SunLab model. The 
 

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two sets of estimates, by SunLab and S&L, provide a band in which the costs can be expected to fall. The capital 

costs without thermal storage is included for informational purposes. 

Table 4-12 and Figure 4-4 illustrates the SunLab projected total installed capital cost ($/kWe) compared to 

S&L’s more conservative values. Figure 4-4 also shows the total installed capital cost based on achieving the 

annual net efficiencies projected by SunLab, but not the projected cost reductions. The curves highlight the 

impact of the annual net efficiencies on the capital cost. The curves also indicate that additional cost reductions 

above and beyond the more conservative S&L values, due to technology improvements and increased 

deployment rates, will result in convergence of the capital costs toward the SunLab values. 

Table 4-12 — Comparison of Total Investment Cost Estimates ($/kWe): 

SunLab vs. Sargent & Lundy 

2004 2007 2010 2015 2020

SunLab $ 4,859 $ 3,408 $ 2,876 $ 2,546 $ 2,221 

S&L – S&L Efficiencies 4,816 3,854 3,562 3,389 3,220 

S&L – SunLab Efficiencies 4,791 3,687 3,331 3,165 2,725 

S&L – No Storage 2,453 2,265 2,115 1,990 1,846 
 

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Figure 4-4 — Total Installed Capital Costs: Operations and Maintenance 

Sargent & Lundy reviewed the SunLab O&M cost model based on our experience with fossil and other power 

plant technologies and in the course of a site visit to KJC Operating Company, the operator of the five 30-MWe 

trough projects located at Kramer Junction. KJC Operating Company provided proprietary information on the 

last five years of operation. The SunLab O&M estimate is based largely on the experience at the KJC Operating 

Company SEGS plants. The model assumes a stand-alone trough power plant (as opposed to the five co-located 

plants at Kramer Junction) and adjusts cost depending on the size of the solar field and total electric generation 

per year. It breaks out the specific staffing requirements for operations and maintenance crews for both the 

conventional power plant and for the solar field. Administrative staffing is also included. In addition to labor 

breakdown, the model breaks out service contracts, water treatment costs, spares and equipment costs, 

miscellaneous costs, and periodic capital equipment requirements. S&L conducted a review of the SunLab 

model and compared it to general power industry experience. 
 

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The Sargent & Lundy O&M costs for comparison to the SunLab projections are based on the following: 

• Solar Field 

 The initial unit costs are based on the SunLab values, and cost reductions for years beyond 

2004 are based on a PR = 0.92 

 Replacement rate for the mirrors and HCE are based on the average actual replacement 

rates for SEGS III – VII for the period 1997–2001 

 The replacement rates for the balance of the solar field are based on the SunLab values 

• Power Block and Balance-of-Plant 

 Costs are based on S&L data for the respective MW-size plant for the steam turbine 

systems and balance-of-plant 

• Water and Process 

 Costs are based on the average actual costs for SEGS III – VII for the period 1997–2001 

• Staffing, Services Contracts, Miscellaneous, and Capital Equipment 

 The costs are based on the SunLab values since the SunLab values were determined to be 

reasonable 

• Thermal Storage 

 The costs are based on 0.4% of the capital cost per annum 

Analyzing the two estimates revealed the major component to account for the cost difference is the HCE 

replacement rate. Table 4-13 shows a comparison of the SunLab and S&L projected replacement rates. 

Table 4-13 — Projected Trough Receiver Replacement Rates 

Annual Failures 

(Percent of Field) Current 2004 2007 2010 2015 2020 

SunLab 3.5% 2% 1% 0.5% 0.5% 0.5% 

S&L 5.5% 5.5% 2.5% 1.5% 1.0% 0.5% 

The SunLab near-term values are not consistent with the average actual HCE replacement rate of 5.5% reported 

for SEGS III – VII for the period 1997–2001. 

Sargent & Lundy reviewed the actual receiver (HCE) replacement rate reported by KJC Operating Company 

over the last five years. The S&L evaluation is based on total HCE replacement reported for the SEGS III – VII 

for the period 1997–2001. S&L’s evaluation is based on the current replacement rate at all the SEGS plants, 

with step reductions in the replacement rate based on the following considerations: 
 

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• The average actual HCE replacement rate of 5.5% was reported for SEGS III – VII for the 

period 1997–2001. The total HCE replacement includes breakage and fluorescence. 

Fluorescence is due to cermet coating failures. This failure is due to the existence of 

molybdenum in the original Luz cermet coating. Solel no longer uses molybdenum in the 

UVAC cermet coating, so this type of failure will presumably no longer occur. Eliminating 

replacements due to these failures reduces the site failure/replacement rate. 

• SunLab used the SEGS VI plant as the baseline reference plant. The SEGS III – V plants had 

problems during initial startup and the early years of operation that caused bowing of the HCEs, 

which increased breakage at those plants. SEGS VII has had higher breakage on the LS-3 half 

of the field, although the LS-2 failures are similar to SEGS VI. SEGS VI was the last full plant 

constructed with LS-2 collectors and represents the most mature version of this generation of 

collector technology. The HCE total replacement rate at SEGS VI during the 5 years is in the 

5.5% range. Discounting the fluorescence failures, the replacement rate was 4.2% over the 

5-year period. 

• The high HCE failure rate at the existing plants is due in part to issues that would not be found 

at a future plant. A significant portion of the failures has been due to the hydrogen remover 

(HR) device installed in the HCEs at SEGS VI – X, operational problems that caused bowing, 

and HCE installation procedures. The HR is no longer part of the HCEs provided by Solel. 

Based on these factors, it is very possible that future plants will have substantially lower HCE failure rates than 

those currently found at the SEGS plants. The SunLab assumption of a 2% failure rate assumes that current 

approaches for reducing failures are successful. S&L believes that this is an aggressive assumption that cannot 

be assured for future plants without the field data to verify the failure rate reduction. Using the current 

replacement rate occurring at all the SEGS plants, with step reductions in the replacement rate, reflects the 

current conditions and allows for the aforementioned improvements to reduce the replacement rate. 

Additional development of the HCE will likely be necessary to achieve the future receiver reliability goals. The 

current glass-to-metal seal is one of the more expensive elements and the key failure point of the current 

receiver design. The current seal design, known as a Housekeeper seal, relies on a sharp metal point being 

inserted into a glass bead. Failures occur when concentrated light focuses on seal and the differential expansion 

between the glass and metal causes the failure of the seal. New designs are currently under investigation that 

attempt to improve the match between the coefficient of thermal expansion of the metal and glass. Kramer 

Junction is currently testing a new design, UVAC2, with a revised internal shield. 

To achieve the SunLab projected replacement rates, the reliability of the HCE will have to improve 

significantly. Table 4-14 and Figure 4-5 compare the O&M costs and illustrate the impact of the HCE 

replacement rate. The O&M costs without thermal storage are included for informational purposes. 
 

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Table 4-14 — Comparison of O&M Cost Estimates ($/kWhe): 

SunLab vs. S&L 

2004 2007 2010 2015 2020

SunLab 0.0228 0.0171 0.0135 0.0118 0.0097 

S&L – S&L HCE Replacement 0.0280 0.0218 0.0180 0.0157 0.0139 

S&L – SunLab HCE Replacement 0.0246 0.0197 0.0167 0.0154 0.0139 

S&L – No Storage 0.0377 0.0339 0.0278 0.0241 0.0206 

 

Figure 4-5 — Levelized O&M Cost Comparison 

0.008

0.013

0.018

0.023

0.028

0.033

0.038

2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

O&M Cost, $/kWe

SunLab Projection S&L - Based on S&L HCE Replacement S&L - Based on SunLab HCE Replacement No Storage

 

 

 HCE Replacement Rate

 SunLab S&L

2004 2.0% 5.5%

2007 1.0% 4.0%

2010 0.5% 2.5%

2015 0.5% 1.0%

12 hours thermal storage

No thermal storage

The reduction in O&M cost is primarily a result of the increase in plant size and the increase in annual plant 

capacity factor. The plant capacity increases directly as a result of the increases in thermal storage. Increasing 

the size (MWe) and capacity factor of the power plant incurs minimal increase in the fixed O&M expenses 

($/year). 
 

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4.4 LEVELIZED ENERGY COSTS 

Table 4-15 and Figure 4-6 below illustrate the SunLab projected levelized energy cost ($/kWhe) compared to 

the S&L values. The figure also shows the levelized energy cost based on achieving the annual net efficiencies 

projected by SunLab. For comparison, the estimated levelized energy cost for the trough plants without thermal 

storage is included in Figure 4-6 to underscore the importance of thermal storage in the reduction of the 

levelized energy cost. 

Table 4-15 — Comparison of Levelized Energy Cost Estimates ($/kWhe): 

SunLab vs. S&L 

2004 2007 2010 2015 2020

SunLab 0.0991 0.0681 0.0566 0.0476 0.0428 

S&L – S&L Efficiencies 0.1037 0.0795 0.0713 0.0664 0.0621 

S&L – SunLab Efficiencies 0.1031 0.0763 0.0670 0.0624 0.0534 

S&L – No Storage 0.1201 0.1100 0.0989 0.0910 0.0826 

 
 

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Figure 4-6 — Levelized Energy Costs 

0.04

0.05

0.06

0.07

0.08

0.09

0.1

0.11

0.12

0.13

2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

Levelized Energy Cost, $/kWhe

SunLab S&L - S&L Efficiencies S&L -SunLab Efficiencies S&L - Without Storage

 

 Annual Net Solar to 

 Electric Efficiency

 SunLab S&L

2004 14.3% 14.0%

2007 16.2% 15.1%

2010 17.0% 15.4%

2015 17.1% 15.5%

2020 17.2% 15.5%

12 hours thermal storage

No thermal storage

The curves highlight the impact of the annual net efficiencies on the levelized energy costs. The curves also 

indicate that additional cost reductions above and beyond the more conservative S&L values, due to technology 

improvements, reduced HCE replacement rates, and increased deployment rates, will result in further 

convergence of the levelized energy costs toward the projected SunLab values. 

Figure 4-7 shows the levelized energy cost for the SunLab technology forecasts with a breakdown that shows 

the source of the cost reduction from plant scale-up, technology R&D, and cost reduction through learning. Of 

the projected cost reduction in 2020, plant scale-up is projected to provide 20% of the total cost reduction, 

technology development will provide over half of the cost reduction at 54%, and production volume and 

competition will provide approximately 26% of the cost reduction. 
 

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Figure 4-7 — Breakdown of LEC Cost Reduction 

(Scale-up, R&D, Volume Production) 

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

1989 2004 2007 2010 2015 2020

SEGS VI Near-Term

Scale-up R&D

Volume Production

20%

54%

26%

Figure 4-8 below shows the importance of the five major cost components in Section 4.3 in reducing the LEC. 

Figure 4-8 — Breakdown of LEC Cost Reduction 

(by Major Cost Component) 

19%

13%

26% 16%

20%

6%

Concentrator (19%)

Mirror (13%)

HCE (16%)

Storage (26%)

Power Block (20%)

Other (6%)
 

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The impact of levelized cost of energy for tax credit is shown in Table 4-16. The difference between 10% tax 

credit and no tax credit is about 8% in 2020. 

Table 4-16 – Impact of Tax Credit on Levelized Cost of Energy 

 Levelized Energy Cost, $/kWhe, by Case 

 Near 

Term 

Mid 

Term 

Long 

Term 

 

Solar 

Tres 

USA 

Solar 50 Solar 

100 

Solar 

200 

Solar 

220 

 IRR % Debt DSCR 2004 2006 2010 1015 2020 

10 % Tax Credit 12.12% 59.90% 1.35 0.0991 0.0681 0.0566 0.0476 0.0428 

No Tax Credit 12.12% 66.50% 1.35 0.1075 0.0737 0.0613 0.0541 0.0461 

4.5 TECHNOLOGY STEP CHANGES AND COMPARISON 

The following tables provide a summary of the major 2004 through 2020 technology changes and a comparison 

of the SunLab and S&L values. 

Table 4-17 — Current (SEGS VI) to Trough 100 – 2004 

 Trough 100 – 2004

 Current Sun Lab S&L Basis

Plant Size 30 MWe 100 MWe 

Field Aperture Area 188,000 m2 1,120,480 m2 1,138,709 m2 Greater aperture area required for S&L 

estimate due to lower estimated annual 

efficiency 

Thermal Storage 0 hours 12 hours 2-tank Indirect Based on Nexant design being proposed 

for 50-MW trough project in Spain 

Annual Plant Capacity 22.2% 53.5% Capacity increased by thermal storage. 

Heat Transfer Fluid VP-1 oil VP-1 oil 

Storage Media None Solar Salt Technically proven at Solar 2 

Operating Temperature 391oC 391oC 

Receiver Luz Solel Solel 2nd Generation UVAC HCE 
 

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 Trough 100 – 2004

 Current Sun Lab S&L Basis

Coating 

Cermet UVAC2 

Second-generation Solel UVAC cermet 

coating currently being field tested at 

KJCOC 

Collector 

LS-2 LS-2+ 

Updated version of LS-2 collector based 

on discussions with Duke Solar and 

KJCOC 

Annual solar-to-electric 

efficiency 10.6% 14.3% 14.0% S&L used lower receiver efficiency than 

SunLab based on current data 

Solar Field Optical 

Efficiency: 

53.3% 56.7% 56.7% 

 IAM, end loss 89.9% 91% 91% 

 Mirror reflectivity 93.5% 93.5% 93.5% 

 Envelope transmittance 92.5% 96.5% 96.5% 

 Solar absorption 92% 94.4% 94.4% 

 Mirror cleanliness 93.1% 95% 95% 

 Envelope cleanliness 98% 98.5% 98.5% 

 Dumped energy 99.9% 95.6% 95.6% 

 Concentrator length 50 meters 50 meters 50 meters 

The incident angle modifier improves 

slightly in plants with thermal storage, 

because more energy is collected early in 

the day. 

The increase in envelope transmittance 

is based on improved anti-reflective 

coatings on inside and outside of the 

receiver glass envelope. The new value 

is based on property testing of Solel 

UVAC HCE by Sandia National Labs. 

SunLab increase of absorption based on 

property measurement of secondgeneration UVAC receiver (SPF, 2001). 

Mirror and envelope cleanlinesses of 

95% and 98.5% are reasonable based 

on Kramer Junction experience. 

Receiver Efficiency: 72.9% 85.9% 84.3% 

 Thermal emittance 0.135 at 

400°C 

0.091 at 

400°C 

0.100 at 

400°C 

Latest Solel UVAC selective coating. 

Solel testing at SPF showed an 

emittance of 0.091, however field testing 

required. S&L used 0.10 based on the 

test data 

Piping Thermal Losses 96.1% 96.5% 96.5% 

Thermal Storage Thermal 

Losses 

NA 99.1% 99.1% Based on thermal losses at Solar Two 

and detailed thermal storage design 

model. 

Gross steam cycle efficiency 35.1% 37.0% 37.0% 

 Turbine Design 37.5% 37.5% 37.5% 

 Part Load 98% 99.5% 99.5% 

 Startup 96.9% 99.2% 99.2% 

 Turbine Minimum 98.5% 100% 100% 

Verified by SEGS IX ABB Heat Balances 

HTDG 582395, Sheets 1-7 (in LUZ 

International Limited 1990)

The addition of thermal storage reduces 

part load operation, reduces the percent 

of energy used for startup, and eliminates 

losses due to minimum turbine load. 
 

 4-30 

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 Trough 100 – 2004

 Current Sun Lab S&L Basis

Parasitics 82.4% 87.7% 87.7% 

 Solar Field 0.23% 0.20% 0.20% 

 HTF Cold Pumps 5.90% 3.75% 3.75% 

 HTF Hot Pumps 0.00% 1.06% 1.06% 

 HTF Freeze Protection 1.52% 1.16% 1.16% 

 Backup Heater/Boiler 0.00% 0.00% 0.00% 

 Hotel Load (24 hr) 3.67% 1.62% 1.62% 

 Balance-of-Plant 4.36% 2.73% 2.73% 

 Cooling Towers 1.89% 1.81% 1.81% 

Conversion from Flex hoses to ball joint 

assemblies. Reduces pressure drop in 

collector loop. Demonstrated in KJCOC 

O&M cost reduction study. 

The fixed station load is spread over 

higher plant capacity factor. For a larger 

plant the station load is a smaller % of 

total load. 

SEGS VI parasitics included control 

building and Maintenance shop at SEGS 

VII. 

Plant-wide Availability 98.0% 94.0% 94.0% Reasonable based on Kramer Junction 

experience. 

Table 4-18 — Trough 100 – 2004 (Near-Term Case) to Trough 100 – 2007 

Trough 100 - 2007 Trough 

100 - 2004 Sun Lab S&L Basis

Plant Size 100 MWe 100 MWe 

Field Aperture Area 1,120,480 m2 1,037,760 m2 1,108,830 m2 Greater aperture area required for S&L 

estimate due to lower estimated annual 

efficiency 

Thermal Storage 

12 hours 

2-tank Indirect 

12 hours 

Thermocline Direct 

Next generation of storage under 

development at SunLab. Uses single 

tank storage system. 

Annual Plant Capacity 53.5% 56.2% 

Heat Transfer Fluid 

VP-1 oil Hitec XL nitrate salt 

Freezes at 120oC, must keep field at 

150C minimum temperature. Cold salt 

from storage used for night time freeze 

protection. 

Storage Media Solar Salt HitecXL, rock & sand filler Thermal cycling testing of rock & sand 

filler at SNL 

Operating Temperature 293-400o

C 293-450oC Salt HTF allows operating temperature to 

be increased. 

Receiver Solel Advanced 1 Next generation receiver design 
 

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Trough 100 - 2007 Trough 

100 - 2004 Sun Lab S&L Basis

Coating UVAC2 Advanced 1 Advanced cermet either by Solel or other 

source 

Collector LS-2+ LS-3+ 

Assumes the larger aperture of the LS-3 

and 1.5x the length. Optical performance 

is assumed to be similar to the LS-2 

collector. This is the EuroTrough or 

equivalent. 

Annual solar-to-electric 

efficiency 14.2% 16.1% 15.1% 

Solar Field Optical 

Efficiency: 

56.4% 57.9% 57.0% 

 IAM, end loss 91% 91.8% 91.8% 

 Mirror reflectivity 93.5% 93.5% 93.5% 

 Envelope transmittance 96.5% 97% 96.5% 

 Solar absorption 94.4% 96% 94.4% 

 Mirror cleanliness 95% 95% 95% 

 Envelope cleanliness 98.5% 98.5% 98.5% 

 Dumped energy 95.6% 95.2% 95.6% 

 Concentrator length 50 meters 150 meters 150 meters 

The incident angle modifier improves 

slightly with longer collector. 

Mirror cleanliness of 95% is reasonable 

based on Kramer Junction experience. 

SunLab increase in envelope 

transmittance based on Sandia test data.

SunLab assumed increase in absorption 

based on selective coating modeling at 

NREL. 

Receiver Efficiency: 85.9% 86.2% 82.3% 

 Thermal emittance 0.091 at 

400°C 

0.070 at 

400°C 

0.100 at 

400°C 

SunLab decrease in emittance based on 

SunLab selective coating modeling. 

Gross steam cycle efficiency 37.0% 39.0% 39.0% 

 Turbine Design 37.5% 39.4% 39.4% 

 Part Load 99.5% 99.7% 99.7% 

 Startup 99.2% 99.2% 99.2% 

 Turbine Minimum 100% 100.0% 100.0% 

Reasonable based on increase of 

temperature from 400o

C to 450oC. 

GEPerf computer program check used to 

verify increase. 
 

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Trough 100 - 2007 Trough 

100 - 2004 Sun Lab S&L Basis

Parasitics 87.7% 91.1% 91.1% 

 Solar Field 0.20% 0.13% 0.13% 

 HTF Cold Pumps 3.75% 1.75% 1.75% 

 HTF Hot Pumps 1.06% 0.53% 0.53% 

 HTF Freeze Protection 1.16% 1.06% 1.06% 

 Backup Heater/Boiler 0.00% 0.00% 0.00% 

 Hotel Load (24 hr) 1.62% 1.60% 1.60% 

 Balance of Plant 2.73% 2.05% 2.05% 

 Cooling Towers 1.81% 1.81% 1.81% 

SunLab parasitics reduction based on 

replacement of VP-1 with HitecXL in the 

solar field and elimination of need to run 

two sets of pumps in the indirect storage 

system. 

The Nexant piping model calculates a 

65% reduction in HTF pumping parasitics 

with molten-salt. 

Plant-wide Availability 94.0% 94.0% 94.0% 

Table 4-19 — Trough 100 – 2007 (mid-Term) to Trough 150 – 2010 

 Trough 150 - 2010 Basis

 

Trough 100 - 

2007 Sun Lab S&L 

Plant Size 100 MWe 150 MWe 

Field Aperture Area 1,120,480 m2 1,477,680 m2 1,632,301 m2 Greater aperture area required for S&L 

estimate due to lower estimated annual 

efficiency 

Thermal Storage 

12 hours 

2-tank Direct 

12 hours 

Thermocline Direct 

 

Annual Plant Capacity 56.2% 56.2% 

Heat Transfer Fluid HitecXL HitecXL nitrate salt Testing currently in progress to make 

sure Hitec XL can be used up to 500oC. 

Storage Media HitecXL, rock 

& sand filler HitecXL, rock & sand filler Thermal cycling testing of rock & sand filler at SNL 

Operating Temperature 450oC 500oC 

Receiver Advanced 1 Advanced 2 Higher temperature capability 

Coating Advanced 1 Advanced 2 Same thermal & optical properties but 

able to operate to 500oC 
 

 4-33 

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 Trough 150 - 2010 Basis

 

Trough 100 - 

2007 Sun Lab S&L 

Collector 

LS-3+ Next Generation 

New design based on use of front 

surface reflectors and structural mirror 

facets. 

Annual solar-to-electric 

efficiency 14.2% 17.0% 15.4% 

Solar Field Optical 

Efficiency: 

57.9% 59.8% 57.0% 

 IAM, end loss 91.8% 91.8% 91.8% 

 Mirror reflectivity 93.5% 95% 93.5% 

 Envelope transmittance 97.0% 97.0% 96.5% 

 Solar absorption 96% 96% 94.4% 

 Mirror cleanliness 95% 96% 95% 

 Envelope cleanliness 98.5% 98.5% 98.5% 

 Dumped energy 95.2% 95.2% 95.2% 

 Concentrator length 150 meters 150 meters 150 meters 

S&L estimate mirror cleanliness of 95% 

based on Kramer Junction experience. 

SunLab mirror reflectivity increase from 

0.935 to 0.95 based on use of front 

Surface mirror with anti-soiling coating to 

reduce mirror soiling rate, mirror 

cleanliness from 0.95 to 0.96. 

Receiver Efficiency: 86.2% 85.2% 81.0% 

 Thermal emittance 0.070 at 

400oC 

0.070 at 

400oC 

0.100 at 

400oC 

S&L assumes no improvement over 

current demonstrated Solel UVAC 

receiver, except higher temperature 

capability to 500o

C. 

Gross steam cycle efficiency 39.0% 40.0% 40.0% 

 Turbine Design 39.4% 40.5% 40.5% 

 Part Load 99.7% 99.7% 99.7% 

 Startup 99.2% 99.2% 99.2% 

 Turbine Minimum 100.0% 100.0% 100.0% 

GEPerf computer program check used to 

verify increase. 
 

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 Trough 150 - 2010 Basis

 

Trough 100 - 

2007 Sun Lab S&L 

Parasitics 91.1% 91.8% 91.8% 

 Solar Field 0.13% 0.13% 0.13% 

 HTF Cold Pumps 1.75% 1.33% 1.33% 

 HTF Hot Pumps 0.53% 0.42% 0.42% 

 HTF Freeze Protection 1.06% 1.02% 1.02% 

 Backup Heater/Boiler 0.00% 0.00% 0.00% 

 Hotel Load (24 hr) 1.60% 1.62% 1.62% 

 Balance of Plant 2.05% 1.91% 1.91% 

 Cooling Towers 1.81% 1.81% 1.81% 

Reduction in parasitics is reasonable. 

SunLab reduction in HTF parasitics 

based on increasing operating 

temperature to 500o

C. 

BOP parasitics reduced due to larger 

plant size. 

Plant-wide Availability 94.0% 94.0% 94.0% 

Table 4-20 — Trough 150 – 2010 to Trough 200 – 2015 

 Trough 150 - Trough 200 - 2015

 2010 Sun Lab S&L Basis

Plant Size 150 MWe 200 MWe 

Field Aperture Area 1,477,680 m2 1,955,200 m2 2,161,485 m2 Greater aperture area required for S&L 

estimate due to lower estimated annual 

efficiency 

Thermal Storage 

12 hours 

Thermocline 

Direct 

12 hours 

Thermocline Direct 

 

Annual Plant Capacity 56.2% 56.2% 

Heat Transfer Fluid Hitec XL Hitec XL 

Operating Temperature 500oC 500oC 

Receiver Advanced 2 Advanced 2 

Coating Advanced 2 Advanced 2 

Collector Next 

Generation Next Generation 

Annual solar-to-electric 

efficiency 17.0% 17.1% 15.4% 
 

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 Trough 150 - Trough 200 - 2015

 2010 Sun Lab S&L Basis

Solar Field Optical 

Efficiency: 

59.8% 60.2% 57.0% 

 IAM, end loss 91.8% 91.8% 91.8% 

 Mirror reflectivity 95% 95% 93.5% 

 Envelope transmittance 97.0% 97.0% 96.5% 

 Solar absorption 96% 96% 94.4% 

 Mirror cleanliness 96% 96% 95% 

 Envelope cleanliness 98.5% 99% 98.5% 

 Dumped energy 95.2% 95.2% 95.2% 

 Concentrator length 150 meters 150 meters 150 meters 

SunLab estimate assumes anti-soiling 

treatment added to receiver envelope to 

improve cleanliness. 

Sargent & Lundy assumes no 

improvement from earlier case. 

Receiver Efficiency: 85.2% 85.3% 81.0% 

 Thermal emittance 0.070 at 

400°C 

0.070 at 

400°C 

0.100 at 

400°C 

No change for SunLab case, S&L 

assumes current UVAC design. 

Gross steam cycle efficiency 40.0% 40.0% 40.0% 

 Turbine Design 40.5% 40.5% 40.5% 

 Part Load 99.7% 99.7% 99.7% 

 Startup 99.2% 99.2% 99.2% 

 Turbine Minimum 100.0% 100.0% 100.0%

Parasitics 91.8% 91.8% 91.8% 

 Solar Field 0.13% 0.13% 0.13% 

 HTF Cold Pumps 1.33% 1.32% 1.32% 

 HTF Hot Pumps 0.42% 0.42% 0.42% 

 HTF Freeze Protection 1.02% 1.01% 1.01% 

 Backup Heater/Boiler 0.00% 0.00% 0.00% 

 Hotel Load (24 hr) 1.62% 1.62% 1.62% 

 Balance of Plant 1.91% 1.91% 1.91% 

 Cooling Towers 1.81% 1.81% 1.81% 

Plant-wide Availability 94.0% 94.0% 94.0% 
 

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Table 4-21 — Trough 200 – 2015 to Trough 400 – 2020 

 Trough 400 - 2020

 

Trough 200 -

2015 Sun Lab S&L Basis

Plant Size 200 MWe 400 MWe 

Field Aperture Area 1,955,200 m2 3,910,400 m2 4,348,931 m2 Greater aperture area required for S&L 

estimate due to lower estimated annual 

efficiency 

Thermal Storage 

12 hours 

Thermocline 

Direct 

12 hours 

Thermocline Direct 

 

Annual Plant Capacity 56.2% 56.5% 

Heat Transfer Fluid Hitec XL Hitec XL 

Operating Temperature 500oC 500oC 

Receiver Advanced 2 Advanced 2 

Coating Advanced 2 Advanced 2 

Collector Next 

Generation Advanced Generation 1 

Annual solar-to-electric 

efficiency 17.1% 17.2% 15.5% 

Solar Field Optical 

Efficiency: 

59.8% 60.2% 57.0% 

 IAM, end loss 91.8% 91.8% 91.8% 

 Mirror reflectivity 95% 95% 93.5% 

 Envelope transmittance 97.0% 97.0% 96.5% 

 Solar absorption 96% 96% 94.4% 

 Mirror cleanliness 96% 96% 95% 

 Envelope cleanliness 98.5% 99% 98.5% 

 Dumped energy 95.2% 95.2% 95.2% 

 Concentrator length 150 meters 150 meters 150 meters 

S&L & SunLab estimates assume no 

change from earlier case. 

Receiver Efficiency: 85.3% 85.3% 81% 

 Thermal emittance 0.070 at 

400o

C 

0.070 at 

400oC 

0.100 at 

400oC 
 

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 Trough 400 - 2020

 

Trough 200 -

2015 Sun Lab S&L Basis

Gross steam cycle efficiency 40.0% 40.0% 40.0% 

 Turbine Design 40.5% 40.5% 40.5% 

 Part Load 99.7% 99.7% 99.7% 

 Startup 99.2% 99.2% 99.2% 

 Turbine Minimum 100.0% 100.0% 100.0% 

GEPerf computer program check used to 

verify increase. 

Parasitics 91.8% 92.4% 92.4% 

 Solar Field 0.13% 0.13% 0.13% 

 HTF Cold Pumps 1.32% 1.45% 1.45% 

 HTF Hot Pumps 0.42% 0.43% 0.43% 

 HTF Freeze Protection 1.01% 1.01% 1.01% 

 Backup Heater/Boiler 0.00% 0.00% 0.00% 

 Hotel Load (24 hr) 1.62% 0.90% 0.90% 

 Balance of Plant 1.91% 1.92% 1.92% 

 Cooling Towers 1.81% 1.81% 1.81% 

SunLab parasitics assume increase in 

HTF pumping parasitics for larger size 

solar field and a reduction in hotel load 

based on scale-up in size to 400 MWe 

Plant-wide Availability 94.0% 94.0% 94.0% 

4.6 RISK ASSESSMENT FOR TROUGH TECHNOLOGY 

This section provides an overview and assessment of the risks associated with attaining competitive 

commercialization for the parabolic trough technology on a short-term, mid-term, and long-term basis. 

Competitiveness is measured by the levelized energy cost (LEC), expressed as $/kWh, consisting of two 

elements: total investment cost and operation and maintenance (O&M) cost. 

The major total investment cost drivers of the trough plant are the solar field, power block, and thermal storage, 

which account for approximately 90% of the total costs (based on 12 hours of thermal storage). Also, the net 

annual solar-to-electric efficiency has a significant impact on the cost of a trough plant. For every one 

percentage point improvement in the net efficiency, the cost is reduced by approximately 7%. 

Total cost reductions occur from technical improvements, increase in plant size (scaling), and volume 

production (learning curves). All three are dependent on deployment of the technology. Deployment provides a 
 

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means for continued research in technology improvements, cost reductions due to increased production, and 

economy of scale from constructing larger plants. 

The second element of the levelized energy cost is the O&M costs. For the trough plant, O&M costs represent 

25% or more of the LEC. 

As such, the focus of the risk assessment covers the following main categories: 

• Deployment 

• Net Annual Solar-to-Electric Efficiency 

• Total Investment Cost 

• Operation and Maintenance 

4.6.1 Deployment 

Market expansion of trough technology will require incentives to reach market competitiveness. Numerous 

potential incentives exist, such as: environmental (CO2 emission credits), favorable tax credits, favorable peak 

energy tariff, premium consumer pricing, loan guarantees, low interest loans, and grants. Analysis of incentives 

required to reach market acceptance is not within the scope of this report. 

4.6.1.1 Near Term (2004) 

The SunLab near-term deployment projection is one identical 100-MW plant per year in the years 2004 through 

2006 (three plants total). 

The actual strategy employed by the plant suppliers can be significantly diverse, with more emphasis on nearterm cost reduction with a minimum of risk. The trough plant suppliers may opt to provide multiple plants in the 

50 MWe, to 100 MWe size with no thermal storage but with a supplemental steam generator, replicating the 

proven technology of the existing SEGS plants. The suppliers can rely more on initial production volume to 

reduce costs as opposed to efficiency and technology improvements and scale-up factors. Minimizing or 

eliminating thermal storage, with its current elevated cost, appreciably reduces the total direct cost of the plant. 

Without thermal storage, the direct capital cost is approximately 50% less for the 100-MW plant deployed in the 

2004–2006 time frame. However, due to the lower annual MWh generation, the LEC ($/MWh) is approximately 

20% higher than for a plant with 12 hours of thermal storage. 
 

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4.6.1.2 Mid Term (2010) 

The SunLab mid-term deployment projection is six 100-MW plants and one 150-MW plant with improved 

technology being deployed in the years 2007 through 2010. 

4.6.1.3 Long Term (2020) 

The SunLab long-term deployment projection is eight 150-MW plants with improved technology being 

deployed in the years 2010 through 2014; twelve advanced technology 200-MW plants in the years 2015 

through 2020; and one 400-MW advanced technology plant in 2020. The SunLab total long-term deployment is 

4,900 MW of installed capacity. 

4.6.2 Net Annual Solar-to-Electric Efficiency 

4.6.2.1 Near Term (2004) 

The SunLab projected near-term net annual solar-to-electric efficiency is 14.3%, an improvement of 

3.7 percentage points from the SEGS VI 10.6% efficiency. The increased efficiency is mainly attributable to 

improved receiver optical and thermal emittance properties. The demonstrated improvements are the following: 

• Significant improvements in selective coatings have occurred since the last SEGS plant was 

built. The solar absorptance of the cermet tubes used at SEGS VI was approximately 91.5%. 

According to test data (SPF 2001), the Solel UVAC receiver tubes have a solar weighted 

absorptance of 94.4%. 

• Anti reflective coatings for glass have been improved in the last 10 years to improve durability. 

The new receiver tubes have anti-reflective coatings that deliver solar transmittances of 96.5%, 

compared with earlier coating that only allowed 92.5%. 

• SEGS VI had a combination of black chrome and the original generation of Luz Cermet 

receiver tubes. The average thermal emittance of these tubes is approximately 20% greater at 

350°C. The UVAC receiver first installed at SEGS VI had a thermal emittance of 14% at 

400°C. According to tests performed for Solel, the second-generation UVAC receiver had a 

thermal emittance of about 9% at 400°C 

There is a low risk of achieving the near-term net annual solar-to-electric efficiency of 14.3%, since the receiver 

properties that the improvement is dependent on have been demonstrated either by operating experience at the 

SEGS plants or from test data. 
 

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4.6.3 Mid Term (2010) 

The SunLab projected mid-term net annual solar-to-electric efficiency is 17.0%, an improvement of 

2.7 percentage points from the near-term projected efficiency of 14.3%. This improvement is mainly attributable 

to the following: 

• Second-generation advanced receiver with an optical design point efficiency of 79.1% 

(compared to near-term 75%) as a result of a solar absorptance of 96% (compared to near-term 

94.4%) and mirror reflectivity of 95% (compared to near-term 93.5%). 

• Improved steam turbine cycle efficiency of 3 percentage points as a result of increasing the 

solar field operating temperature to 500°C. 

There is a high risk of achieving the mid-term net annual solar-to-electric efficiency of 17.0% based on the 

following considerations: 

• The optical efficiency improvement is based on two steps of receiver advancements, an 

advanced heat collection element (HCE) coating for the projected 500°C operating temperature. 

Alternate HCE designs are under various stages of development that indicate lower cost than the 

Solel UVAC HCE, but at reduced efficiency levels. Reduced HCE efficiency will result in a 

lower net annual solar-to-electric efficiency. 

• While there are no steam turbine technological risks in achieving the improved efficiency, the 

type of heat transfer fluid (HTF) will have to be changed to obtain the 500°C inlet steam 

temperature. The SunLab projections assume a nitrate salt HTF with an upper operating range 

of 500°C. Alternate HTF development will be required since use of nitrate salt has not been 

demonstrated for the trough technology. 

• A direct thermocline thermal storage system is assumed for the mid-term case. At the present 

time, preliminary assessments have been made on the potential impact that a thermocline 

storage system might have on the annual performance of the plant and more detailed analyses 

and research are required. The current ball joints will not work with the high-temperature salt 

HFT, and flexhose and ball joint sealing options have to be researched and developed. Various 

thermal storage options are in the early stages of development. 

A mid-term net annual solar-to-electric efficiency in the 15.4% range represents a low risk by limiting the 

technology improvements to currently demonstrated or tested improvements. 

The reduction in efficiency from the projected 17.0% to 15.4% results in an increase in the mid-term levelized 

energy cost of approximately $0.0045/kWhe. 
 

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4.6.3.1 Long Term (2020) 

The SunLab projected long-term net annual solar-to-electric efficiency is 17.2%, an improvement of 

0.2 percentage points from the mid-term projected efficiency of 17.0%. This modest improvement is mainly 

attributable to operational improvements to reduce thermal losses and reducing the amount of dust on the 

envelope. 

There is a high risk of achieving the long-term net annual solar-to-electric efficiency of 17.2% due to the midterm risks discussed previously. However, the risk is greatly reduced if the trough technology is successfully 

deployed to the extent that the competitive market prompts research and development of technological 

advances. 

4.6.4 Total Investment Cost 

The major cost contributors in total investment cost of a parabolic trough solar plant with thermal storage are the 

solar collector field (53%), thermal storage system (23%), and the power block (14%). 

In combination with thermal storage, increased annual net efficiency, and reduced equipment cost via 

technology advancements, competition and deployment are the primary elements in reducing the long-term cost 

of the trough plant. 

4.6.4.1 Near Term (2004) 

The SunLab projected near-term total investment cost, with the exception of the thermal storage, is based on 

actual values from the SEGS plants. Costs for components such as the HCE and mirrors are based on current 

pricing of replacement parts for the SEGS plants. 

The near-term indirect two-tank thermal storage system is based on cost estimates from detailed design 

drawings and material takeoffs developed by Nextant. The technological risk using the two-tank molten-salt 

storage system is low based on the successful utilization at the Solar Two plant. 

Estimated costs based on the SOAPP program indicate that the SunLab projected capital costs for the power 

block are conservative (on the high side), approximately $50/kW higher than estimated by the SOAPP program. 

The SunLab power block cost estimates are based on a 1990 ABB quotation for a 100-MW steam turbine. The 

ABB quotation was escalated and scaled-up for the larger sizes. The SunLab power block cost estimates are 

based on dated information and the escalation and scale-up factors add to the uncertainty of the data with respect 
 

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to current pricing. Equipment prices in the SOAPP program reflect 2001 actual costs. Since the SOAPP pricing 

is current, the SOAPP-generated costs are more characteristic of current power block costs. 

Based on the above considerations, there is a low risk of achieving the near-term total investment cost. 

4.6.4.2 Mid Term (2010) 

The SunLab projected mid-term total investment cost indicates a total cost of $2,876/kWe, a reduction of 

$1,983/kWe from the near-term projected cost of $4,859/kWe, mainly attributable to the following: 

• An increase in the plant size from 100 MW to 150 MW, which reduces the $/kWe cost by virtue 

of the larger kWe size. 

• Reduced cost of solar collection system components, such as HCE and mirrors, of 

approximately 35% as a result of technological advances, competition, and production volume. 

• Reduction of the thermal storage capital cost from the near-term $958/kWe to $383/kWe by 

using a direct thermocline thermal storage system. 

There is a high risk of achieving the SunLab projected mid-term total investment cost of $2,876/kWe, based on 

the following considerations: 

• The SunLab projected reduced cost of solar collection system components, such as HCE and 

mirrors, is based on six 100-MW plants and one 150-MW plant with improved technology 

being deployed in the years 2007 through 2010. Market expansion of trough technology will 

require incentives to reach the projected level of deployment. 

• The SunLab projected mid-term net annual solar-to-electric efficiency is 17.0%, an 

improvement of 2.7 percentage points from the near-term projected efficiency of 14.3%. The 

solar field size, and thus the solar field cost, is directly proportional to the net annual solar-toelectric efficiency of a trough plant. As previously discussed, there is a high risk of achieving 

the mid-term net annual solar-to-electric efficiency of 17.0%. Using a mid-term net annual 

solar-to-electric efficiency in the 15.4% range, which represents a lower risk by limiting the 

technology improvements to currently demonstrated or tested improvements, results in a 8% 

decrease in the solar field size compared to 19% decrease for a 17.0% efficiency. 

• The SunLab projected mid-term direct thermocline system with HitecXL (ternary) solar salt as 

the storage media and heat transfer fluid (HTF), allowing the solar field to be operated to higher 

outlet temperatures (500°C). No thermal storage technology has been commercially 

demonstrated for the higher solar field operating temperatures. Additional development is 

required for the thermocline system. In addition to the development of a thermocline system, an 

advanced HCE will be required to obtain the 500°C HTF operating temperature. 
 

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4.6.4.3 Long Term (2020) 

The SunLab projected long-term total investment cost indicates a total cost of $2,221/kWe, a reduction of 

$655/kWe from the mid-term projected cost of $2,876/kWe, mainly attributable to the following: 

• An increase in the plant sizes from the 100–150-MW range to the 200–400-MW range, which 

reduces the $/kWe cost by virtue of the larger kWe size. 

• Reduced cost of solar collection system components from mid-term costs, such as HCE and 

mirrors, of approximately 25% as a result of technological advances, competition, and 

production volume. 

There is a high risk of achieving the SunLab projected long-term total investment cost due to the mid-term risks 

discussed previously. However, the risk is mitigated if the trough technology is successfully deployed to the 

extent that the competitive market prompts research and development of technological advances and plant sizes 

in the 200–400-MW range. 

4.6.5 Operation and Maintenance (O&M) Costs 

The SunLab O&M estimate is based largely on the experience at the KJC Operating Company SEGS plants. The 

model assumes a stand-alone trough power plant (as opposed to the five co-located plants at Kramer Junction) 

and adjusts costs depending on the size of the solar field and total electric generation per year. KJC Operating 

Company provided proprietary information on the last five years of operation. 

The major cost contributors for O&M costs are as follows: 

• Solar field replacement of the heat collection elements (HCE) 

• Staffing 

The staffing is a fixed cost, and the SunLab projected manpower requirements are reasonable based on data 

from similar-sized power plants. 

The industry plan keys on thermal storage to obtain a high capacity factor, which reduces the O&M costs 

($/MWh) by obtaining a higher annual MWh generation. The net annual solar-to-electric efficiency has a 

significant impact on the O&M costs. Increased efficiency reduces the size of the solar field and thus reduces 

the number of mirror and HCE replacements required. 
 

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4.6.5.1 Near Term (2004) 

The SunLab projected near-term O&M cost is based on an HCE replacement rate of 2%, a net annual solar-toelectric efficiency of 14.3%, and 12 hours of thermal storage. As previously indicated, there is a low risk of 

achieving the near-term net annual solar-to-electric efficiency and the technological risk using the two-tank 

molten-salt storage system is low. However, the HCE replacement rate of 2% is not consistent with the average 

actual HCE replacement rate of 5.5% reported for SEGS III – VII for the period 1997–2001. Using the average 

replacement rate of 5.5% increases the levelized O&M cost by approximately $0.004/kWhe, an increase of 17%. 

There is a high risk of achieving the SunLab projected near-term O&M cost since the SunLab assumption of a 

2% HCE replacement rate assumes that current approaches for reducing failures are successful. S&L believes 

this is an aggressive assumption that cannot be assured for future plants without the field data to verify the 

failure rate reduction. A lower risk would be using a HCE replacement rate of 5.5% and an annual solar-toelectric efficiency of 14.0% 

4.6.5.2 Mid Term (2010) 

The SunLab projected mid-term O&M cost is based on an HCE replacement rate of 0.5%, a net annual solar-toelectric efficiency of 17%, and 12 hours of thermal storage using a direct thermocline system with HitecXL 

(ternary) solar salt. 

As previously indicated, there is a high risk of achieving the mid-term net annual solar-to-electric efficiency of 

17.0% and a mid-term net annual solar-to-electric efficiency in the 15.4% range represents a low risk by limiting 

the technology improvements to currently demonstrated or tested improvements. Also, the direct thermocline 

thermal storage system has not been commercially demonstrated for the higher solar field operating 

temperatures and additional development is required for the thermocline system. In addition to the development 

of a thermocline system, an advanced HCE will be required to obtain the 500°C HTF operating temperature. 

New designs are currently under investigation that attempt to improve the reliability of the HCE. Kramer 

Junction is currently testing a new design UVAC2 with a revised internal shield. A more conservative 

replacement rate for the S&L comparison is 2.5%. 

There is a high risk of achieving the SunLab projected mid-term O&M cost. A lower risk would be using a HCE 

replacement rate of 2.5% and an annual solar-to-electric efficiency of 15.4%. 
 

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4.6.5.3 Long Term (2020) 

The SunLab projected long-term O&M cost is based on an HCE replacement rate of 0.5%, a net annual solar-toelectric efficiency of 17.2%, and 12 hours of thermal storage using a direct thermocline system with HitecXL 

(ternary) solar salt. The projected long-term plant is basically the same configuration as the projected mid-term 

plant with the reduction in O&M cost primarily as a result of the increase in plant size to 400 MW. As such, 

there is the same high risk of achieving the SunLab projected O&M cost. 

4.7 COST SENSITIVITIES 

In this section, variations in the inputs for levelized energy costs are shown to illustrate the sensitivity of energy 

calculated cost to variations. The sensitivity analysis revealed that the impact on the LEC of the various 

scenarios are basically the same for both trough and tower technologies. The base case for the sensitivity 

analysis for the trough in 2020 is 400 MW with a capital cost of $3,204 per kW and annual O&M costs of 

$14,129, as is shown in Table 4-22. The tower base case is shown for reference. 

Table 4-22 — S&L Base Case for the Year 2020 

 Trough Tower 

Year 2020 2020 

Capacity, MWe 400 200 

Capacity Factor, 56.2% 72.9% 

Capital Cost, $/kW $3,220 $3,591 

Annual O&M Cost, $k $14,129 $9,132 

LEC, $/kWh $0.0621 $0.0547 

Economic Life 30 yrs 

General Inflation 2.5 % 

Equity Rate of Return 14% 

Cost of Construction 7% 

Construction Duration 1 yr. 

Investment Tax Credit 10% 

Taxes 40.2% 

Depreciable Life 5 yrs. 
 

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 Trough Tower 

IRR 14% 

DSCR 1.35 

4.7.1 Depreciable Life 

The tax depreciation allowances for renewable energy provide a favorable 5-year depreciable life. The Modified 

Accelerated Cost Recovery System (MACRS) defined depreciation schedules for 5, 10, and 15 years. If the tax 

laws are changed or reinterpreted, the variation in LEC in 2020 is shown below. 

Table 4-23 — Effect of Depreciable Life on Levelized Energy Cost 

Depreciable Life LEC in 2020 

(years) $/kWh % difference 

5 $0.0621 Base Case 

10 $0.0658 6.1% 

15 $0.0698 12.5% 

4.7.2 Investment Tax Credits 

The investment tax credits have a major impact on the economic feasibility of a renewable energy power plant. 

Current tax law allows a 10% investment tax credit. Future tax laws may allow a larger tax credit such as the 

15% before 1985 or disallow investment tax credits. Tax credits from 0% to 15% and Energy Production Tax 

Credit (PTC) result in the LEC in 2020 to vary as shown below. 

Table 4-24 — Effect of Investment Tax Credits on Levelized Energy Cost 

Tax Credits LEC in 2020 

(%) $/kWh % difference 

0% $0.0670 7.8% 

5% $0.0645 3.4% 

10% $0.0621 Base Case 

15% $0.0596 -4.0% 

PTC of 1.8¢/kWh $0.0490 -26.9% 
 

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4.7.3 Corporate Tax Rate 

Corporate tax rates are currently at 35%. State taxes vary depending on the plant location but are assumed to be 

8%. The composite base tax rate is 43%. The present Government Administration is currently considering 

reductions in the corporate tax rate, but the rate can vary depending on the economic conditions at the time. The 

impact on LEC in 2020 from changes in the tax rate is shown below. 

Table 4-25 — Effect of Corporate Tax Rates on Levelized Energy Cost 

Corporate Tax Rates LEC in 2020 

Federal State Composite $/kWh % Difference 

30% 8% 38% $0.0632 1.9% 

35% 8% 43% $0.0621 Base Case 

38% 10% 48% $0.0610 -1.7% 

4.7.4 Inflation 

Inflation assumptions do not affect the real dollar levelized energy cost. Increases and decreases in the inflation 

rate impact the LEC in 2020 as shown below. 

Table 4-26 — Effect of Inflation on Levelized Energy Cost 

Inflation Rate LEC in 2020 

Rate IRR $/kWh % difference 

1.5% 12.9% $0.0614 -1.0% 

2.5% 14.0% $0.0621 Base Case 

3.5% 15.1% $0.0627 1.1% 

4.7.5 Cost of Capital 

Cost of capital for the base case is such that there is an internal rate of return (IRR) of 14%. The impact on LEC 

in 2020 from a change in the cost of capital is shown in the following table. 
 

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Table 4-27 — Effect of Cost of Capital on Levelized Energy Cost 

Cost of Capital LEC in 2020 

IRR $/kWh % Difference 

13% $0.0575 -7.3% 

14% $0.0621 Base Case 

15% $0.0668 7.7% 

4.7.6 Construction Duration 

The plant construction period for the base case is one year based on experience at the SEGS plants. The amount 

of interest during construction (IDC) is included in the LEC. The impact on LEC in 2020 for construction of two 

and three years is shown below. 

Table 4-28 — Effect of Construction Duration on Levelized Energy Cost 

Construction LEC in 2020 

Period 

(yr) $/kWh % Difference 

1 $0.0621 Base Case 

2 $0.0655 5.5% 

3 $0.069 11.3% 

4.7.7 Capital Cost 

The variation for increases in capital costs is shown below. 

Table 4-29 — Effect of Capital Cost Increases on Levelized Energy Cost 

Increase in Capital LEC in 2020 

Cost 

(%) $/kWh % difference 

0% $0.0621 Base Case 

10% $0.0675 8.8% 

20% $0.0730 17.7% 
 

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4.7.8 Annual O&M Cost 

The variation for increases in annual O&M costs is shown below 

Table 4-30 — Effect of O&M Cost Increase on Levelized Energy Cost 

Increase in Annual LEC in 2020 

O&M Cost 

(%) $/kWh % difference 

0% $0.0621 Base Case 

10% $0.0628 1.2% 

20% $0.0635 2.3% 

4.7.9 Ownership 

The S&L base case considers ownership by an Independent Power Producer (IPP). An investment by 

developer/owners and financial institutions would require an IRR of at least 14%. It is more likely that the first 

several power plants will be owned by utilities. Utilities require a lower IRR and would be more receptive to 

renewable initiatives. As the industry matures (e.g., capital cost declines and the technology is proven), the IPPs 

would become involved. There is the potential for private ownership in the early plants, but it would most likely 

be from manufacturers who could offset the lower IRR with increased sales for solar equipment. The impact of 

ownership on LEC for 2020 is shown below. 

Table 4-31 — Effect of Ownership on Levelized Energy Cost 

 IPP Utility 

Ownership Muni 

IRR, % 14% 11.5% 0% 

Leverage 60/40 50/50 100/0 

Cost of Debt 5% 7% 5% 

DSCR 1.35 1.74 1.0 

LEC, $/kWh $0.0621 $0.0597 $0.0458 

% difference Base Case -3.9% -26.1% 
 

 5-1 

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5. EVALUATION OF POTENTIAL FOR COST REDUCTIONS — TOWER 

5.1 INDUSTRY PLAN FOR COST REDUCTION 

SunLab worked closely with industry in the development and demonstration of Solar One and Solar Two. The 

key industry participants were Boeing, Nexant (formerly Bechtel) and numerous utilities led by Southern 

California Edison. Since Solar Two, SunLab has continued working with industry to solve problems identified 

during the Solar Two demonstration project and identify technology improvements to reduce costs. The 

problems identified during Solar Two demonstration project are discussed in detail later. The tower industry has 

developed a comprehensive plan to lower costs. Industry participants have certain confidential information that 

cannot be shared since it would compromise their ability to compete in the domestic and international markets. 

The SunLab model (SunLab 2002) provides a cost estimate and plan that closely follows the industry 

comprehensive plan. S&L used the SunLab plan as the basis of our independent review and supplemented with 

industry information and our experience. Table 5-1 lists the SunLab tower development plant and indicates the 

‘near-term’, ‘mid-term’ and ‘long-term’ cases discussed previously. 

Table 5-1 — Tower Technology Summary: SunLab Reference Case 

Case* Baseline Near-Term Mid-Term Long-Term

Project Solar Two Solar Tres

USA Solar 50 Solar 100 Solar 200 Solar 220

In Service Date 1996 2004 2006 2008 2014 2018

Power Cycle Rankine Rankine Rankine Rankine Rankine Supercritical 

Rankine 

Net Power, MWe 10 13.65 50 100 200 220 

Capacity Factor, % 21% 78% 75% 73% 74% 72% 

Heliostat Size 39/95 95 95 148 148 148 

Heliostat Design glass/metal glass/metal glass/metal glass/metal glass/metal Advanced 

Solar Field Size, km2 0.08 0.23 0.72 1.32 2.61 2.65 

Receiver Area, m2 100 280 710 1,110 1,930 1,990 

Receiver Peak 

Incident Flux, 

MW/m2

0.8 0.95 1.2 1.4 1.6 1.6 
 

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Case* Baseline Near-Term Mid-Term Long-Term

Project Solar Two Solar Tres

USA Solar 50 Solar 100 Solar 200 Solar 220

In Service Date 1996 2004 2006 2008 2014 2018

Ratio Average/Peak 

Incident Flux 

0.60 0.51 0.50 0.50 0.50 0.50 

Receiver Average 

Incident Flux, 

MW/m2

0.48 0.49 0.60 0.70 0.80 0.80 

Heat Transfer Fluid solar salt solar salt solar salt solar salt solar salt solar salt 

Operating 

Temperature, °C 

565 565 565 565 565 650 

Thermal Storage 

Fluid 

solar salt solar salt solar salt solar salt solar salt solar salt w/ 

O2 blanket 

Thermal Storage, hr 3 16 16 13 13 17 

Land Area, km2 0.4 1.1 3.4 6.6 13.8 14 

* All cases assume Kramer Junction 1999 radiation of 8.054 kW/m2/day. 

Industry and the national laboratories are actively working together to enhance technology to reduce costs. This 

is being accomplished with industry research and development (IRD) funding and cooperative work with the 

national laboratories. For example, Boeing and Sandia are currently participating in solar research through a 

joint Cooperative Research and Development Agreement (CRADA). Boeing reported that they committed 

$2 million of IRD funds for the Solar Two demonstration project. Boeing is continuing to pursue improvements 

to the receiver and other systems through internal funding. This effort has resulted in multiple patents and 

disclosures and in advanced codes (SUNSPOT and RISROC) for field and receiver optimization. A previous 

CRADA with SunLab was completed to study fabrication of large heliostats. Nexant and Sandia have worked 

closely to develop improved plant designs and specifications to utilize the lessons learned at Solar Two. 

Some of the design improvements that are or will be pursued are listed below. 

• Collector 

 Mirrors will improve by the use of higher reflectivity thin glass or films, and additional 

support structure will be made cost-effective by higher volume production (see 

Appendix H). 
 

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 Cleanliness can improve though the development of contact cleaning tools for heliostats 

and the adaptation of ‘self-cleaning’*

 glass for use with solar mirrors. 

 Novel heliostat designs like stretched membrane (drum-like) or inflatable/rolling concepts 

that are lower in weight than traditional glass/metal designs. 

 Drive mechanisms can be simplified. Presently the drives use complex gearing. 

 New flux monitoring and management systems that will permit higher solar flux levels on 

the receiver. 

• Receiver 

 Changes in receiver tube material have been accomplished to correct problems identified 

during Solar Two. The tube material changes were validated by molten salt corrosion tests 

and high flux testing at Sandia. The development of this material was performed jointly by 

Boeing and Sandia (CRADA). 

 Simplified redesign of the receiver panels was accomplished jointly by Boeing and Sandia 

(CRADA). 

 Tube internal heat transfer enhancements can improve receiver flux capability. 

 Simpler and more efficient header oven covers can allow faster preheat in the morning and 

more efficient operation in partly cloudy weather and high winds. 

 Redesigned fill and drain system can accelerate receiver start-up and simplifies operation. 

 High-temperature selective surfaces for receiver tubes can reduce radiative losses while 

maintaining high absorptivity. 

 Advanced header design, including new materials and nozzle designs, was modified and 

parts deleted. This is the key reason in achieving cost reduction from $8.33 per kWt for 

Solar Two to $3.96 per kWt for Solar Tres. 

• HTF and Thermal Storage 

 Improved tank venting system and better instrumentation. 

 Advanced tower piping design that eliminates drag valves in the down flow pipe. 

 Simplified foundation cooling system can lower cost. 

 Optimize the tank overall configuration (shape and location). 

 Higher temperature molten salt to improve cycle performance. 

 An advanced molten salt with a lower freezing point can reduce heat tracing, simplify 

operation, and result in decreased parasitic power consumption. 

 Direct resistance heating of piping and components can lower maintenance costs. 

• Steam Generator System 

 Installing the hot and cold pumps directly in the hot and cold storage tanks eliminates 

significant piping and valves, which results in reduced cost. 

 

*

 Several glass manufacturers are releasing ‘self-cleaning’ glass, including Pilkington Active TM 

(www.activglass.com/index_eng.htm) and PPG SunClean TM (www.ppg.com/gls_sunclean/) 
 

 5-4 

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 Elevating the steam generator heat exchangers allows full gravity draining, which provides 

less equipment and simplifies operation of the system. 

 Improved operating procedures have been developed to provide more reliable operation. 

• Electric Power Block 

 Larger plants can utilize the more efficient Rankine cycles that are currently available 

technology. 

 Even higher cycle efficiencies are possible via parallel paths: (1) the availability of more 

efficient Rankine cycles in the appropriate size range and (2) the introduction of 

supercritical steam turbines operating at higher temperatures can increase Rankine cycle 

efficiencies. 

5.2 TOWER EFFICIENCY 

Many of the advances just described can reduce capital costs and/or improve plant efficiency, which indirectly 

decreases capital costs. For example, given a fixed plant size and capacity factor, the net annual solar-electric 

efficiency sets the required collector area (Appendix E.3). As the efficiency increases, the collector area and cost 

decrease in proportion. Table 5-2 lists the subsystem annual efficiencies of selected tower plants from the 

development plan and summarizes the S&L analysis of these projections. 

Table 5-2 — Tower Annual Efficiency Summary 

 SunLab Sargent & Lundy 

Baseline Near 

Term

MidTermLong 

Term

Near 

Term

MidTermLong 

Term 

1996 2004 2008 2020 2004 2008 2020 

Solar 

Two

Solar 

Tres

Solar 

100

Solar 

220

Solar 

Tres

Solar 

100 Solar 220 Discussion

Detailed 

Discussion

Collector 

Efficiency 

50.3% 

58% at 

Solar 

One 

56.0% 56.3% 57.0% 56.0% 56.0% 56.0% The collector efficiency should decrease 

at larger plants because the average 

distance between heliostat field and tower 

increases, as does the atmospheric 

attenuation of light. The SunLab projected 

improvements in reflectivity and 

cleanliness more then compensate for 

this effect, but S&L projects that the 

mirror cleanliness will not exceed 95% 

based on discussions with operators at 

Kramer Junction. 

Section 

E.3.6 

Receiver 

Efficiency 

76.0% 78.3% 83.1% 82.0% 78.3% 83.1% 82.0% Efficiency increases in with solar flux level 

the mid-term plant due to reduced thermal 

losses. Flux increases cannot 

compensate for increased losses due to 

higher temperature operation in the longterm plant. 

Section 

E.7.2 
 

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 SunLab Sargent & Lundy 

Baseline Near 

Term

MidTermLong 

Term

Near 

Term

MidTermLong 

Term 

1996 2004 2008 2020 2004 2008 2020 

Solar 

Two

Solar 

Tres

Solar 

100

Solar 

220

Solar 

Tres

Solar 

100 Solar 220 Discussion

Detailed 

Discussion

Gross 

Cycle 

Efficiency 

31.7% 40.5% 42.0% 46.3% 38.0% 41.4% 45.6% The Solar Two steam turbine was 

designed for marine propulsion and 

lacked reheat. Current, proven Rankine 

technology is being used up to Solar 200. 

Solar 220 is projecting that current 

research on advanced turbines will be 

complete and available to support in 

2018. The turbine efficiencies are 

reasonable based on guarantees. Actual 

efficiencies will be less depending on 

actual conditions (i.e., cooling water 

temperature). 

Section 

E.6.2 

Parasitic 73.0% 86.4% 90.0% 90.0% 86.4% 90.0% 90.0% The parasitic efficiency will increase 

based on higher capacity factors, larger 

plants, design improvements and lessons 

learned from Solar Two and Solar Tres. 

Section 

E.3.5 

Thermal 

Storage 

97.0% 98.3% 99.5% 99.5% 98.3% 99.5% 99.5% Efficiencies increase at future plants 

because tank surface area to volume ratio 

(and heat losses) decreases with 

increasing tank size. 

Section 

E.8.2 

Piping 99.0% 99.5% 99.9% 99.9% 99.5% 99.9% 99.9% The piping efficiencies are reasonable 

and increase due to larger piping and 

shorter lengths per kWe 

— 

Availability 90.0%* 92.0% 94.0% 94.0% 92.0% 94.0% 94.0% The availability should be reached after 

the first 12 to 18 months of operation. 

Actual availability for SEGS VI in 1999 

was 98% 

— 

Annual 

Solar-toElectric 

Efficiency

7.6% 13.7% 16.6% 18.1% 13.0% 16.1% 17.3% The large jump from Solar Two to Solar 

Tres is due to the use of (1) a steam 

turbine with reheat, (2) a new collector 

field that performs to the level proven at 

Solar One, and (3) miscellaneous small 

improvements due mostly to the increase 

in plant size. S&L agrees with these 

projections, except uses a lower mirror 

cleanliness estimate for Solar 220. 

Section E.3 

* Based on the mature plant operation of Solar One. 

The projected increases in net annual solar-to-electric efficiency have a significant impact on the capital cost of 

the plants. The S&L analysis of the impact of these incremental efficiency improvements the SunLab capital 

cost at the subsystem level appears in Table 5-2. More details of this analysis are presented in Section E.4.6. For 

illustration, the impact of solar-to-electric efficiency improvements on required collector area and cost is shown 

in Figure 5-1. 
 

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Figure 5-1 — Comparison of Annual Solar-to-Electrical Efficiency Technology Step Changes: 

SunLab vs. S&L 

5.2.1 Annual Collector Efficiency 

Collector efficiency includes mirror reflectivity (see Appendix H for the definition of reflectivity and the impact 

of microscopic defects on plant performance), field optical efficiency,*

 field availability, mirror corrosion 

avoidance, mirror cleanliness, and high wind outages. SunLab projections for each of these contributing 

collector field efficiencies are listed in Appendix E, Table E-6 for all plants. The detailed S&L analysis of 

collector field efficiency appears in Appendix E, Section E.3.6. The prime adjustment was regarding mirror 

 

*

 Includes the cosine effect, blocking of incident sunlight, shading of reflected sunlight by adjacent heliostats, and the 

intercept. The intercept is the fraction of light directed toward the receiver that actually strikes it. Errors in heliostat 

tracking, focal length, and shape reduce the intercept below unity. Economic optimizations typically yield an intercept of 

about 95%. 
 

 5-7 

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cleanliness. Based on discussions during the KJC site visit, S&L estimates the upper bound on mirror 

cleanliness to be 95%, as opposed to the SunLab upper limit of 97%. 

5.2.2 Annual Receiver Efficiency 

Receiver efficiency includes absorptivity, thermal efficiency, and plant operational losses. When sunlight strikes 

the receiver, some energy is reflected. The fraction absorbed is called the absorptivity, and the Pyromark paint 

used on the tower receiver has an absorptivity of 95% when new. Slow degradation of the paint observed at 

Solar One dictates that it be reapplied every few years and results in a lower time-average absorptivity 

(Radosevich 1988). Improved durability of the paint and/or ease of application and curing can raise the average 

up to the as-new value of 95%. In addition, the receiver suffers radiation and convective losses that reduce its 

thermal efficiency below 100%. 

Increasing the solar flux levels on the receiver permits a reduction in size that reduces these losses and increases 

thermal efficiency. A new high-nickel receiver tube material will be used on future plants because (1) it 

eliminates stress corrosion cracking, which can occur in the receiver because moist air can enter when it is 

drained at night, and (2) it permits higher solar flux levels. The stress corrosion cracking resistance has been 

validated in testing with Sandia. A small prototype panel of the new material has been tested to flux levels in 

excess of 1.6 MWt/m2

. A full size panel was also constructed and installed at Solar Two where it operated at the 

lower flux levels of that plant. Achieving the increased solar flux levels will require improved flux monitoring 

and management systems. 

Plant operational losses occur when the plant is unable to use all of the available energy for a short period. For 

example, times of very high solar resource can ‘overpower’ the receiver so part of the field must be ‘defocused’ 

to avoid damage. This reduces annual efficiency. Times of very low solar resource (e.g., sunrise) do not justify 

plant operation because losses outpace gains. Likewise, when clouds shade the plant, the receiver enters a cloud 

standby state with salt circulating through the receiver and incurring thermal losses without any energy 

collection. The plant operating and dispatch strategy can also create a situation where the thermal storage system 

is full and cannot accept any additional energy, so energy collection must again be curtailed (called ‘dumping.’) 

Economic optimization of the plant design typically results in a few percent of defocusing and dumping losses. 
 

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5.2.3 Annual Gross Cycle Efficiency 

The annual gross cycle efficiency includes the design point gross cycle efficiency, startup losses, and part-load 

operation. Losses due to minimum turbine load requirements do not apply because all of the plants have thermal 

storage. The gross cycle efficiency is the thermal input to the turbine divided by the gross (nameplate) output. 

Electrical parasitic loads are considered next. The high-storage, high-capacity factor plants have minimal startup 

losses and are normally not run at part load, so these losses are minimal. 

5.2.4 Annual Parasitic Efficiency 

The main parasitic electric loads are the motors for the salt pumps, condensate/feedwater pumps, cooling water 

pumps, cooling tower fans, and boiler. Additional parasitic loads are a result of instrumentation, controls, 

computers, valve actuators, air compressors, and lighting. The solar field also adds parasitic loads for the 

collector drives and communications. Electric parasitic loads decrease with larger plant size and are based on 

detailed analysis at Solar One and Solar Two (Reilly and Kolb 2001) 

5.2.5 Annual Thermal Storage Efficiency 

The annual thermal storage efficiency accounts for thermal losses from the thermal storage system. Storage 

thermal losses are a function of the surface area of the storage tanks and the temperature of the fluid above 

ambient. Large high-temperature thermal storage systems have been demonstrated at SEGS I and Solar Two. In 

these systems, thermal losses have been shown to be small; thus, the storage thermal efficiency is very close to 

100%. As the size of the tanks increases, their surface area increases more slowly than their volume, so that 

thermal losses are reduced and efficiency increases. 

5.2.6 Annual Piping Efficiency 

The piping efficiency includes losses from the salt piping in the tower and at ground level. 

5.2.7 Annual Plant Availability 

Annual plant availability accounts for scheduled plant outages for regular maintenance and unscheduled plant 

outages due to equipment failures. 

5.3 EVALUATION OF MAJOR COST COMPONENTS 

The solar field, electric power block, and receiver encompass approximately 74% of the total direct costs as 

shown in Figure 5-2. The major cost component is the heliostat field, which encompasses 43% of total costs for 
 

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Solar Tres. The next three categories are electric power block, 13%; receiver, 18%; and balance-of-plant, 6%. 

Our review focused on these three major cost components, with a less stringent review of thermal storage and 

steam generator. Table 5-3 provides a summary of the SunLab and S&L cost projection. 

Figure 5-2 — Cost Components for Solar Tres 

Table 5-3 —Summary of Tower Cost Projections 

SunLab Forecast Sargent & Lundy

Case Near 

Term

Mid 

Term

Long 

Term

Near 

Term

Mid 

Term

Long 

Term

Project Solar 

Tres 

Solar 

100 

Solar 

220 

Solar 

Tres 

Solar 

100 

Solar 

200 

Year In Service 2004 2010 2020 2004 2010 2020

Structures and Improvements, 

$/m2

 field 

12.3 4.0 2.7 11.6 3.9 2.7 

Heliostat Field, $/m2 field 145 107 76 160 134 117 

Receiver, $k/m2 recv 50 27 21 57.143 30.631 23.834 

Tower and Piping, $/m2 field 12.1 9.1 9.2 11.6 8.7 9.1 

Thermal Storage, $/kWt 49 41 40 49 41 40 
 

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SunLab Forecast Sargent & Lundy

Case Near 

Term

Mid 

Term

Long 

Term

Near 

Term

Mid 

Term

Long 

Term

Project Solar 

Tres 

Solar 

100 

Solar 

220 

Solar 

Tres 

Solar 

100 

Solar 

200 

Year In Service 2004 2010 2020 2004 2010 2020

Steam Generator, $/kWt 14 8 7 14 8 7 

Electric Power, $/kWe 733 400 380 557 306 231 

Balance of Plant, $/kWe 532 116 7 733 367 169 

Subtotal Direct Costs, $/kWe 5,700 2,700 1,900 6,424 3,375 2,684 

Indirect Costs, $/kWe 440 241 183 1,134 629 524 

Contingency, $/kWe 453 202 152 890 604 383 

Risk Pool, $/kWe 580 0 0 642 0 0 

Total Cost, $/kWe 7,110 3,100 2,270 9,090 4,608 3,591 

5.3.1 Collectors 

The first plants (Solar Tres and Solar 50) will use the 95-m2

 heliostats. The heliostat size will be increased to 

148 m2

 for Solar 100. S&L evaluation focused on the capital costs and cost improvement for the 148 m2 

heliostat. Our review is primarily based on the SunLab model, the detailed cost model developed by AD Little, 

and Winsmith drive cost and technology improvement studies. The 148-m2

 heliostat was compared against the 

95 m2

 heliostat. We reviewed the major cost components and provided a discussion of the assumptions and 

reasonableness of the cost estimate in Appendix E. 

AD Little (ADL) was contracted by the DOE to prepare a detailed cost estimate for the current 148 m2

 Heliostat 

design from Advanced Thermal Systems (Arthur D. Little, 2001). The study was based on detailed design 

drawings, material takeoff, and proven assembly techniques. ADL applied manufacturing and assembly times 

based on their experience and material costs to develop a rigorous cost estimate. Manufacturers and vendors 

were contacted to develop and validate material costs. ADL used the detailed design information from 

Advanced Thermal Systems (ATS)*

 to estimate the costs. This bottoms-up cost estimate is rigorous and provides 

 

*

 Advanced Thermal Systems is a small company formed in 1985 by former ARCO engineers with licensing rights for the 

tracker technology. DOE funded the development of the previous generation 53-m2

 heliostat. ARCO funded the design, 

development, and first prototype 95- and 148-m2

 trackers for use as heliostats or PV trackers. The design was optimized to 
 

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a fairly accurate cost estimate. It is our opinion that the cost estimate prepared by ADL is a reasonable cost 

estimate of manufacturing 148 m2

 based on producing 300 units (444,000 m2). Our estimate of heliostat costs is 

shown in Table 5-4. We reviewed the ADL study in detail and compared cost material cost estimates to our 

internal cost database (e.g., $ per lb for steel). Based on our evaluation, we determined that the cost of a 95-m2

heliostat for initial deployment is about $160. The cost for the 95-m2

 heliostat was estimated based on a scaling 

factor of 0.8, which is more conservative that the industry average of 0.7. 

Table 5-4 — Heliostat Cost Estimate Comparison: 

Direct Capital Cost – Initial Deployment 

SunLab Sargent & Lundy

Heliostat Size Heliostat 

Cost $/m2 Heliostat Cost $/m2

95 m2 (scaled from 148 m2 at a 

scaling factor of 0.8) 

$14,214 $150 $15,168 $160 

148 m2 (from Table E-14) $20,288 $137 $21,688 $146 

Cost improvements are categorized into technology improvements, scaling factor and volume production. 

5.3.1.1 Technology Improvements 

The technology improvements include (1) thinner glass to increase reflectivity and reduce cost, (2) improved 

aiming techniques, (3) better maintenance practices and updated control system to increase field availability, and 

(4) advanced heliostat for Solar 220. 

Sargent & Lundy has evaluated the technology improvements for efficiency: 

• Mirror cleanliness efficiency shows an increase from 95% to 97%. Based on our interviews at 

Kramer Junction, there is no evidence that the cleanliness will get much better than 95% 

without a major technology breakthrough. There is current research on glass with surfaces to 

maintain high cleanliness efficiencies for large high-rise buildings.*

 S&L’s cost estimate 

assumes that the mirror cleanliness will stay at 95%. 

 

use the maximum number of commodity parts and provide the lowest possible cost for near-term deployment. 

Approximately 1000 solar trackers of this basic design have been built. Most were the 95-m2

 units. One hundred eight of 

the heliostats used at Solar Two were second-hand ATS trackers. 

*

 Several glass manufacturers are releasing ‘self-cleaning’ glass, including Pilkington Active TM 

(www.activglass.com/index_eng.htm) and PPG SunClean TM (www.ppg.com/gls_sunclean/) 
 

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• Mirror reflectivity efficiency shows an increase from 93.5% to 95%. This will require additional 

research in the use of thin glass. The use of thin glass will have to overcome several issues: 

breakage, corrosion, manufacturing, and maintaining cleanliness. The current glass with a low 

lead content has a reflectivity of 93.5% to 94% depending on the amount of lead. As production 

volume increases, there will be greater incentive and quality control to provide higher 

reflectivity glass. For additional discussion on glass research, see Section 4.3.3. 

• The field optical efficiency shows a decrease from 64.6% to 62.8%. This is reasonable based on 

the larger collector field size and longer distance to the receiver. 

• The field availability shows an increase from 98.5% to 99.5%. This is based on better 

maintenance practices, better quality of heliostats as a result of volume production, and an 

updated control system. Solar One demonstrated a field availability of 99%. We assumed that 

actual field availability based on longer-term commercial operation would increase from 98.5% 

to 99%. The field availability of 99.5% will be difficult to achieve without at least a 5% 

additional collector field to cover maintenance and outages. 

• Mirror corrosion avoidance efficiency is projected to be 100%. This is reasonable using the 

present glass based on the experience at Kramer Junction. Additional research, which is 

presently ongoing, will be required as thinner glass is used. 

5.3.1.2 Scaling Factor 

Scaling factor cost improvements are based on heliostat size changes: Solar Two (48 m2

) to Solar Tres (95 m2) 

and Solar 50 (95 m2

) to Solar 100 (95 m2). Increasing to a 148-m2 heliostat can be achieved based on detailed 

engineering performed by ATS and actual construction and operation as PV trackers. The scaling factor of 0.8 is 

a reasonable assumption, even though there have not been a larger quantity of 148-m2

 heliostats built. The 

average industry standard used if no information is available is 0.7 (Humphreys and English 1993). Additional 

discussion is provided in Appendix B, Methodology. 

5.3.1.3 Production Volume 

Production Volume has a significant impact on cost improvements. The SunLab cost estimate for production 

volume cost reductions is based on evaluating each cost component and determining the impact on cost 

reduction (see Appendix E.4.4). S&L performed a detailed review of each cost component to determine the 

impact. For example the PR ratio for mirrors was calculated to be 0.97, which is reasonable since mirror costs 

will decrease due to the increased production runs by mirror manufacturers resulting in lower costs (see 

Appendix E.5.1 for additional discussion). 

The comparison of heliostat costs based on a cumulative deployment of 8.7 GWe for S&L and SunLab is shown 

in Figure 5-3. The range of cost estimates by SunLab and S&L fall within a reasonable cost range established by 
 

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S&L (see Appendix B for additional discussion). The range of progress ratios used for the comparison by S&L 

is between 0.85 and 0.96. Various studies on learning curves from actual data suggest that a progress ratio of 

0.82 has been observed for photovoltaics (PV) and 0.82 for development of wind energy during early 

deployment (1980 to 1995). The higher end of the range is from the Enermodal study for the World Bank, which 

identified a PV of 0.96 and the Wind Learning Rates compiled by Kobos for development of wind plants. 

The progress ratio calculated for the S&L base case is 0.97 and 0.96 for 95-m2

 heliostats and 0.93 for 148-m2

heliostats. The average progress ratio calculated for SunLab is 0.93. These values fall within the range of 0.85 to 

0.96, as shown in Figure 5-3. 

Figure 5-3 — Heliostat Cost Improvements (Cumulative Deployment of 8.7 GWe) 

$145

$127

$96 $107

$75

$150

$108

$115

$129

$87

$160

$40

$60

$80

$100

$120

$140

$160

$180

2004

Solar Tres

2006

Solar 50

2008

Solar 100

2010 2012

Solar 200

2014 2016 2018

Solar 220

2020

Heliostat Cost ($/m2

)

Lower Range [PR-0.85]

Upper Range [PR-0.96]

S&L: 95 m2 

S&L: 148 m2

S&L 

Sunlab [PR-0.96]

95 m2

 heliostat 148 m2 heliostat

enhanced 148 m2 

heliostat

S&L [PR-0.97]

The comparison of heliostat costs for various deployments are shown Table 5-5. The S&L cost estimate is based 

on a deployment of 2.6 GWe. 
 

 5-14 

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Table 5-5 — Heliostat Cost vs. Deployment 

Case Solar Tres 

USA Solar 50 Solar 100 Solar 200 Solar 220 

Year 2004 2006 2010 2015 2020 

Field Area, m2 232,809 721,838 1,330,792 2,622,777 2,678,000 

S&L Heliostat Cost at 1.4 GWe 

deployment, $/m2

$160 $150 $136 $128 $98 

S&L Heliostat Cost at 2.6 GWe 

deployment, $/m2

$160 $150 $134 $124 $94 

S&L Heliostat Cost at 4.7 GWe 

deployment, $/m2

$160 $150 $132 $119 $91 

S&L Heliostat Cost at 8.7 GWe 

deployment, $/m2

$160 $150 $129 $114 $87 

The cost estimates shown in the above table do not include contingency. Contingency is included in the total 

plant installed cost as shown in Table E-2. 

5.3.1.4 Summary 

Cost improvements for the three categories—technology, economy of scale, and volume production—are shown 

in Table 5-6 based on our evaluation and assumptions. The method and analysis to arrive at the breakdown is 

described in Section E.4.7. 

Table 5-6 — Breakdown of Tower Collector System Cost Improvements 

Solar Two to 

Solar Tres

Solar Tres 

to Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220

Average

Heliostat Size, m2 48/95 to 95 95 95 to 148 148 148 to 

advanced 148 

— 

Technology 27% 11% 35% 5% 72% 30% 

Economy of Scale 36% 0% 57% 0% 0% 19% 

Production 

Volume 

37% 89% 8% 95% 28% 51% 
 

 5-15 

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5.3.1.5 Conclusion 

DOE, SunLab, and the industry have spent considerable time and effort in research and development of 

heliostats. The technology has been successfully demonstrated for design, manufacturing, construction, and 

operation. S&L reviewed the information available and it is our opinion as substantiated by our review that the 

heliostat costs and cost reductions are within an acceptable range assuming deployment of the technology. 

5.3.2 Electrical Power Block 

Sargent & Lundy estimated the cost for the power block based on the SOAPP model, compared it to our internal 

database, and then adjusted the output for labor and productivity rates in the Southwest. The results of our 

review are shown in Table 5-7 and Figure 5-4. The power block costs include the steam turbine and generator, 

steam turbine and generator auxiliaries, feedwater and condensate systems. 

Table 5-7 — Capital Cost of Electrical Power Block 

Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Output, MWe 13.5 50 100 200 220 

SunLab, $M $10.0 $24.5 $40.0 $64.0 $83.6 

S&L, $M $7.6 $18.6 $30.6 $46.2 $61.8 

Cost improvements are categorized into technology improvements, plant scaling, and volume production. 

5.3.2.1 Technology Improvements 

The technology improvements include (1) reheat turbine at 540°C for Solar Tres, Solar 50 and Solar 100, 

(2) dual reheat turbine 540°C for Solar 200, and (3) an advanced dual reheat turbine at 640°C. 

The near-term turbine efficiency is verified based on the ABB-Brown Boveri heat balances (HTGD 582395, 

Sheets 1-7) for SEGS IX, which show an efficiency of 37.7% (in LUZ International Limited 1990). The Rankine 

cycle efficiency gains for increasing the inlet steam temperature from 540°C to 640°C were verified by S&L 

using General Electric STGPER software program (Version 4.08.00, January 2002). The results from the 

STGPER software for Solar 200 and Solar 220 were extrapolated to account for dual reheat turbines. The 

turbine efficiencies are summarized in Table 5-8. 
 

 5-16 

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Table 5-8 — Turbine Efficiencies 

Solar One Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

SunLab 32% 34% 40.5% 42% 42.5% 43% 46.3% 

S&L — — 38% 40.6% 41.4% 42.8% 45.6% 

The type of heat transfer fluid (HTF) determines the operational temperature and thus the maximum power cycle 

efficiency that can be obtained. The HTF molten nitrate salt (60 wt % NaNO3 and 40 wt % KNO3) nitrate salt 

used in Solar Two demonstrated that steam temperatures of 540°C were achieved (Pacheco et al. 2002); for 

example, test no. 5 at full flow conditions measured actual HTF at 557°C and steam temperature at 542°C. 

There are no steam turbine technological risks in achieving the SunLab projected efficiencies up to Solar 200. 

There are currently numerous steam turbines operating with steam inlet conditions over 250 bar pressure and 

590°C temperature, with gross efficiencies over 44%.*

 The advance from Solar 200 to Solar 220 is based on 

current research on increasing the inlet steam pressure and temperature conditions. This increase in efficiency 

for steam turbines is technically feasible and should be available by 2018. The major issue will be the higher 

temperatures and impact on materials. The S&L cost estimate did not consider the advanced turbine, but 

included it as a sensitivity analysis. 

5.3.2.2 Scaling Factor 

Scaling factor is the major factor for cost improvement. There are recognized scale-up cost reductions for the 

power block. Using the SOAPP software program and S&L’s internal database, the scale-up factor was 

estimated for the projected increased of increasing the power block from 13.5 MW to 200 MW, as depicted on 

Figure 5-4. 

 

*

 Plant (commercial operation date): Nanaoota 1 (1995), Noshiro 2 (1995), Haramachi 1 (1997), Haramachi 2 (1998), 

Millmerran (2002), Matauura 2 (1997), Misumi 1 (1998), Tachibana Bay (2000), Bexback (2002), Lubeck (1995), Aledore 

1 (2000), Nordjylland (1998). From Power (Swanekamp 2002). 
 

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Figure 5-4 — Capital Cost of Electrical Power Block 

$0

$100

$200

$300

$400

$500

$600

$700

$800

0 50 100 150 200 250

Megawatts

$/kW

S&L 

SunLab

Power block costs include the steam turbine and generator, 

steam turbine and generator auxiliaries, feedwater and 

condensate systems

Advanced Turbine Generator for Solar 220

SunLab - $320 per kW

S&L - $281 per kW

5.3.2.3 Production Volume 

Production volume has no impact on cost improvements since a single steam turbine is supplied with each tower 

plant. 

5.3.2.4 Summary 

Cost improvements for the three categories—technology, economy of scale, and volume production—are shown 

in Table 5-9 based on our evaluation and assumptions. 
 

 5-18 

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Table 5-9 — Breakdown of Power Block Cost Improvements 

Solar Two to 

Solar Tres

Solar Tres 

to Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220 Average

Net Electrical Generation, MWe 10 to 13.5 13.5 to 50 50 to 100 100 to 200 200 to 220 — 

Technology 3% 3% 1% 1% 80% 18% 

Economy of Scale 97% 97% 99% 99% 20% 82% 

Production Volume 0% 0% 0% 0% 0% 0% 

5.3.3 Receiver 

Sargent & Lundy reviewed the cost estimate and cost improvements provided by Boeing and SunLab. The 

SunLab cost estimate for the capital cost for receiver is lower than the latest Boeing cost estimate. The SunLab 

cost estimate should be adjusted to be in accordance with the detailed Boeing cost estimate. The Boeing cost 

estimate is reasonable. Boeing is allocating funds for research (e.g., $2M was spent for Solar Two). Boeing is 

looking for the DOE to support CSP technology and continued collaboration with the national laboratories. 

Table 5-10 — Capital Cost of Receiver 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Receiver System Capital Cost – 

SunLab, $M 

39.2 9.1 14.7 23 29.1 39.4 43.3 

Receiver System Capital Cost – 

S&L (based on Boeing), $M 

— — 16 26 34 46 — 

5.3.3.1 Technology Improvements 

The technology improvements include (1) increases in receiver absorbtivity, (2) decrease of absorbtivity from 

selected coatings, (3) high nickel tubes to allow higher solar flux and smaller tube surface, (4) improved 

heliostat aiming allows higher average flux, and (5) improved insulation and receiver header covers to further 

reduce heat loss. 
 

 5-19 

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The increased receiver efficiency is reasonable based on the following: 

• Reduction in heat loss, which is approximately proportional to reduction in receiver surface area 

per incident power. 

• Increase of receiver absorbtivity through Industry Research & Development (IR&D). 

• Decrease of receiver emissivity from selected coatings achieved through IR&D. 

• High nickel tubes to allow higher solar flux and smaller tube surface for Solar 200. 

• Improved heliostat aiming. 

• Gradual increase in solar flux as operating experience is gained from the preceding plant. 

• Constant defocus, dump, startup, and cloud factor at 93.4%. The increase from Solar Two is 

reasonable based on design changes and revised operating methods. 

• Increase in absorbance from 93% to 94.5%. This increase will require additional research into 

receiver tube material and coatings and/or more frequent painting. 

• Change in receiver thermal losses from 93.1% to 94.7%. This increase will require additional 

research to increase thermal flux. The research includes new materials, smaller tube surfaces, 

operating experience, better heliostat aiming, and improved insulation and receiver header 

covers. 

Cost improvements are categorized into technology improvements, scaling factor, and volume production. 

5.3.3.2 Scaling Factor 

Scaling factor cost improvements is the major factor for cost improvements. Boeing, based on their experience 

in manufacturing receivers and similar components, used a scaling factor of 0.7. The estimated capital cost for 

receivers was calculated based on a scaling factor of 0.7 as shown in Table E-42. The difference between the 

capital cost calculated for a scale-up of 0.7 and the projected capital cost is cost savings, which are attributed to 

technical and volume production (for example: the receiver cost for Solar 50 is estimated to be $26 million. The 

cost projection based on a scaling factor of 0.7 would be $31.6 million [Receiver Cost for Solar 100 = $16 x 

(710/269) 0.7 = $31.6 million]). The difference is $5.6, which is attributed to technical improvements and 

production volume as discussed in Section E.7.4. 

5.3.3.3 Production Volume 

Production volume (fabrication learning curve) from previous projects will provide cost improvements due to 

the repetitive assembly related with manufacturing receiver panels. For Solar Tres, 6,000 clips are welded onto 

850 individual tubes that are then welded to 34 headers, which are part of 17 identical receiver panels. Boeing is 
 

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expecting 85% to 90% learning curve based on experience. Boeing has also identified cost improvements due to 

improved manufacturing and quantity discount of material, which are reasonable assumptions. Material and 

components are about 35% of receiver costs. The cost improvements are shown below in Table 5-11: 

Table 5-11 — Effect of Production Volume (Percent of Total Savings) 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

1988 1999 2004 2006 2008 2012 2018

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

 Total, % — — 7% 14% 12% 5% — 

The cost improvements for technology, scaling, and production volume are shown below in Table 5-12: 

Table 5-12 — Cost Improvements for Technology, Scaling, and Production Volume 

Solar Two 

to Solar 

Tres

Solar Tres 

to Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220 Average

Cost Reduction Due 

to Technical 

(Efficiency) 

32% 35% 66% 65% 31% 46% 

Cost Reduction Due 

to Scaling 50% 43% 25% 24% 61% 41% 

Cost Reduction Due 

to Production 

Volume 

18% 22% 9% 11% 8% 13% 

5.3.3.4 Conclusion 

Sargent & Lundy reviewed the information provided and the capital cost and cost improvements are reasonable 

based on the following: 

• The Boeing cost estimate is based on actual costs from Solar Two, with adjustments to 

compensate for design improvements, manufacturing improvements, construction labor rates, 

and escalation. 

• The Boeing cost estimate is based on detailed design drawings and material take-offs (bottomsup cost estimate), which provides a high degree of accuracy. 
 

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• Estimates for Solar 50, 100, and 200 receivers were developed from Solar Two and Solar Tres 

with appropriate scale-up and available industry data. 

• Boeing has considerable experience in the design and manufacturer of receivers for the tower 

technology. 

• Boeing has a dedicated technical team presently working on technical improvements and 

preparing for authorization of Solar Tres. 

• Boeing is actively pursuing markets for tower technology. 

5.3.4 Thermal Storage 

The SunLab capital cost estimates for thermal storage are as follows: 

Table 5-13 — Capital Cost for Thermal Storage 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Thermal Storage - Duration at 

peak output, hr 

NA 3 16 16 13 13 12.7 

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Thermal Storage System Direct 

Cost, $M 

$20.1 $3.7 $5.9 $18.7 $28.9 $56.3 $57.2 

Thermal Storage System Direct 

Cost, $/kWe 

— — $431 $374 $289 $281 $261 

The SunLab cost estimate for the capital cost for thermal storage is reasonable based on the following: 

• The cost estimate is a definitive cost estimate based on detailed design drawings and material 

takeoff. 

• The unit cost parameters are within typical industry values. 

• The contingency is 10%. 

• The binary nitrate salt cost is based on vendor quotes, which includes shipping. 
 

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5.3.4.1 Technology Improvements 

Solar Two demonstrated molten salt as a viable, large-scale thermal energy storage medium. Energy storage 

efficiencies of 99% were achieved. The storage design point efficiency is projected to be 99.9% for all cases. 

The efficiency of Solar Two was demonstrated to be 99.9%, and since there is no significant technology 

changes, it can be expected to remain constant. The design, construction, and performance of large, fielderected, externally insulated tanks for storing molten salt were demonstrated during Solar Two. 

There are several ongoing studies for improvement of the design and construction: 

• Alternative valve designs for hot salt service. 

• Alternative salt downcomer designs. 

• Materials testing on stainless steels 347 and 321, which have demonstrated their resistance to 

IGC in salt service. 

The scaling factor from Solar Two to Solar 220 power block for the SunLab cost estimate is 0.78. 

Table 5-14 — Economy of Scale for Thermal Storage 

Steam Generator Solar 

Two 

Solar 

Tres 

Solar 

50 

Solar 

100 

Solar 

200 

Solar 

220 

Direct Cost $3.70 $5.90 $18.70 $29.30 $56.30 $57.30 

Cost Reduction Due to Scaling based 

on Scaling Factor of 0.78 

— — $3.75 $5.81 $9.69 $9.40 

Cost Reduction Due to Scaling, $M — — $13.85 $29.39 $48.94 $56.30 

Cost Due to Technology 

Improvements, $M 

— — $4.85 ($0.09) $7.36 $1.00 

Cost Due to Technology 

Improvement, % 

— — 26.0% -0.3% 13.1% 1.7% 

These values are reasonable based on the following: 

• The main components are the hot storage tank, cold storage tank, and piping. 

• The SunLab estimate is conservative, since the typical industry standard for economy of scale is 

0.7. 

Since the thermal storage system is comprised of single components, production volume is not a consideration 

for cost improvement. 
 

 5-23 

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Cost improvements for thermal storage and parasitic were evaluated against technical efficiency improvements. 

Parasitic was included since thermal storage is the key contributor to minimizing parasitic losses. 

The cost improvements for technology, scaling, and production volume are shown below in Table 5-15:

Table 5-15 — Cost Improvements for Technology, Scaling, and Production Volume 

Solar Two to 

Solar Tres

Solar Tres 

to Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220 Average

Cost Reduction Due to 

Technical (Efficiency) 0% 23% 0% 11% 2% 7% 

Cost Reduction Due to 

Scaling 100% 77% 100% 89% 98% 93% 

Cost Reduction Due to 

Production Volume 0% 0% 0% 0% 0% 0% 

5.3.5 Steam Generator 

The capital cost estimated by SunLab and the cost improvement for production volume is shown in Table 5-16. 

Table 5-16 — Steam Generator Capital Cost and Economy of Scale 

Steam Generator Solar 

Two 

Solar 

Tres Solar 50 Solar 100 

Solar 

200 

Solar 

220 

Direct Cost — $1.6 $3.7 $5.8 $9.4 $9.3 

Cost Reduction Attributed to Scaling 

based on Scaling Factor of 0.74 

— — $3.75 $5.81 $9.69 $9.69 

Note: The difference between cost reduction due to scaling and direct cost is attributed to technology improvements 

and calculates to an average of 3.7%. 

5.3.6 Balance of Plant 

Sargent & Lundy estimated the cost for the balance of plant based on the SOAPP model,*

 compared it to our 

internal database, and then adjusted the output for labor and productivity rates in the Southwest. The results of 

our review are shown in Table 5-17 and Figure 5-5. The balance-of-plant costs include general balance-of-plant 

 

*

 EPRI SOAPP is a fully integrated program for technology evaluation, conceptual design, costing, and financial analysis of 

combustion-turbine-based power plants for project and proposal development. SOAPP-CT integrates process design, 

costing, and financial analysis of combustion turbine simple- and combined-cycle power plants, including cogeneration. 

Sargent & Lundy developed SOAPP under contract to EPRI. 
 

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equipment, condenser and cooling tower system, water treatment system, fire protection, piping, compressed air 

systems, closed cooling water system, instrumentation, electrical equipment, and cranes and hoists. 

Table 5-17 — Capital Cost of Balance of Plant 

Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Power Block, MWe 13.5 50 100 200 220 

SunLab, $M $4.8 $6.5 $7.8 $9.6 $9.9 

S&L, $M $10 $24.5 $36.7 $33.8 $35.5 

Figure 5-5 — Balance of Plant 

$0

$100

$200

$300

$400

$500

$600

$700

$800

0 50 100 150 200 250

Megawatts

$/kW

S&L

SunLab

Balance of Plant costs include general balance 

of plant equipment, condenser and cooling 

tower system, water treatment system, fire 

protection, piping, compressed air 

systems,closed cooling water system, plant 

control system, electrical equipment, and 

cranes and hoists.
 

 5-25 

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5.3.7 Technology Improvements 

5.3.7.1 Efficiencies 

There are no efficiency improvements projected for the balance of plant. 

Table 5-18 — Cost Improvements for Technology, Scaling, and Production Volume 

Solar Two to 

Solar Tres

Solar Tres 

to Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220 Average

Cost Reduction Due to 

Technical (Efficiency) 0% 0% 0% 0% 0% 0% 

Cost Reduction Due to 

Scaling 100% 100% 100% 100% 100% 100% 

Cost Reduction Due to 

Production Volume 0% 0% 0% 0% 0% 0% 

5.4 OPERATIONS AND MAINTENANCE 

The SunLab O&M estimate is based on the data and experience from the operating solar trough power plants 

with adjustments accordingly for tower solar field and technology. The reduction in O&M cost is primarily a 

result of the increase in annual plant capacity factor. The plant capacity increases directly as a result of the 

increases in thermal storage. Increasing the size (MWe) and utilization (capacity factor) of the power plant 

incurs very little increase in O&M expenses ($/year). This is because the quantity and complexity of the 

equipment remain constant and staffing remains fairly constant. Our review of conventional fossil power plants 

show this ‘economy of scale’ in staffing for increases in plant size. The details of the S&L review are provided 

in Appendix G. 

The comparison between the SunLab cost estimate and S&L’s estimate is shown in Table 5-19. The major 

differences are the following: 

• Sargent & Lundy scaled-up the cost of collector field maintenance contracts associated with 

increase in field size (e.g., weed control). 

• Sargent & Lundy scaled-up the cost of fuel and maintenance of vehicles to account for the 

increase in field size. 

• Sargent & Lundy assumed that the average burdened rate would not decrease between Solar 100 

and Solar 220. 
 

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• Raw water cost used by S&L is based on actual costs reports at SEGS of $0.00122 per gallon 

($0.32 per m3

). SunLab estimated the cost to be $0.021 per m3), which is about 15 times less 

than the S&L estimate. 

• Sargent & Lundy included a contingency of 10%. 

Table 5-19 — Comparison of O&M Cost Estimates: SunLab vs. S&L 

Current SunLab Estimates S&L Estimates

 

Solar 

One/Two 

1987/1999

Solar 

Tres 

 2004 

Solar 100

2008 

Solar 220

2020 

Solar 

Tres 

 2004 

Solar 100

2008 

Solar 220

2020 

Plant Characteristics 

Net Power, MWe 10 15 100 220 15 100 220 

Plant Capacity Factor, % 19.0% 78.0% 73.2% 72.9% 78.0% 73.2% 72.9% 

Annual Solar-Electric Efficiency 7.6% 13.7% 16.6% 18.1% 13.0% 16.5% 17.3% 

Thermal Storage, hrs 3 16 13 13.1 16 13 13.1 

Solar Field, m2 81,400 231,000 1,311,000 2,642,000 233,772 1,354,452 2,771,730

O&M Characteristics 

Number of Staff (FTE) 35 31 47 67 33 46 67 

Avg. Burdened Labor Rate, $k/yr $71 $62 $50 42 $62 $50 $50 

Staff Cost, $k/yr $2,485 $1,922 $2,350 $2,814 $2,046 $2,299 $3,364 

Ann. Material & Services Cost, 

$k/yr 

$750 $600 $1,200 $1,900 $686 $2,065 $4,277 

 Total O&M Cost, $k/yr $3,235 $2,522 $3,550 $4,714 $3,041 $5,127 $9,132 

 Total O&M Cost, $/kWhe $0.194 $0.027 $0.006 $0.003 $0.033 $0.008 $0.006 

Note: the Solar One/Two values are a blended from both plants to provide a “best available” estimate for a typical salt plant 

of this size with utility staffing. Future plants assume lower staffing plans typical of independent, non-utility power plants as is 

also expected for trough plants. 

5.5 LEVELIZED ENERGY COST 

The projections by SunLab and S&L for capital cost and operations & maintenance were used to estimate 

levelized energy costs (LEC). After completing the report, SunLab revised its reference case (from August 2002 

to October 2002) as shown below. The Sunlab LEC projections are based on the October 2002 reference case. 
 

 5-27 

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Revised SunLab Reference Case 

 Solar Two Solar 15 Solar 50 Solar 100 Solar 200 Solar 220 

 1999 2004 2006 2008 2014 2018 

Net Electrical (MWe) 10 13.7 50 100 200 220 

Plant Size Solar (MWt) 42 120 380 700 1400 1400 

Heliostat Size (m2) 39/95 95 95 148 148 148 

Heliostat Field (m2) 81,400 231,000 715,000 1,317,000 2,614,000 2,651,000 

Annual Solar-toElecticity Efficiency 7.6% 13.7% 15.7% 16.5% 16.8% 17.8% 

Capital Cost ($/kWe) — 7,180 4,160 3,160 2,700 2,340 

O&M Annual Cost ($k) — 2,489 3,166 4,005 5,893 6,006 

LEC ($/kWh) — $114.8 $61.5 $47.6 $39.6 $35.0 

The cost estimates were inputted to the financial model developed by S&L (see Appendix B for a description of 

the financial model). The results are shown in Table 5-20. 

Table 5-20 – Capital Cost, O&M Costs and Levelized Energy Cost Summary: 

SunLab and S&L 

 Near Term Mid Term Long Term 

 SunLab S&L SunLab S&L SunLab S&L 

 Solar Tres USA Solar 100 Solar 220 Solar 200 

 2004 2004 2008 2010 2018 2020 

Capital Cost, $/MWh $77.4 $97.1 $36.3 $52.9 $27.0 $41.8 

Fixed O&M Costs, $/MWh $37.4 $46.1 $11.3 $15.3 $8.0 $12.9 

Variable O&M Costs, $/MWh $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 

LEC, $/MWh $114.8 $143.1 $47.6 $68.2 $35.0 $54.7 

SunLab – Deployment of 8.7 GWe / S&L – Deployment of 2.6 GWe 

Sargent & Lundy’s estimate of the direct capital cost and operation & maintenance costs for the near-term 

deployment includes a contingency of about 10%. Based on our review of the SunLab cost estimate, which we 

determined was based on industry cost data and engineering judgment, the cost estimate for the near-term 

deployment (Solar Tres) is reasonable. The projection from near-term deployment (2003) to long-term 
 

 5-28 

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deployment (2020) includes cost reduction due to technology improvements, scaling, and volume production. 

S&L included a composite contingency of 15% for cost reductions (15% for technology, 10% for scaling, and 

20% for volume production). For comparison, the effect of deployment and annual net efficiencies are shown in 

Table 5-21. 

Table 5-21 — Impact of Deployment and Net Solar-to-Electric Efficiency on LEC 

LEC 

Year 2020 

Total 

Deployment 

(GWe) 

Net Solar-toElectric Efficiency

(%) ($/kWh) 

Percent change from 

S&L Base Case 

SunLab 8.7 18.1 0.0350 SunLab Base 

S&L 8.7 16.5* 0.0524 -4.2% 

S&L 4.7 16.5* 0.0538 -1.6% 

S&L 2.6 16.5* 0.0547 S&L Base 

S&L 1.2 16.5* 0.0559 2.2% 

S&L 2.6** 17.3 0.0476 -13.0% 

S&L 2.6** 16.5 0.0547 S&L Base 

S&L 2.6** 14.6 0.0590 7.9% 

* Fixed net solar-to-electric efficiency 

** Fixed total deployment. 

The range of LEC between the SunLab cost estimate and S&L’s estimate is about 56% as shown in Figure 5-6. 
 

 5-29 

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Figure 5-6 — Levelized Energy Cost Comparison: SunLab and S&L 

0

20

40

60

80

100

120

140

160

2004

Solar Tres USA

Near Term

2006

Solar 50

2010

Solar 100

Mid Term

2015

Solar 200

2020

Solar 220

Long Term

$/MWh

SunLab - 8.7 GWe

Sargent & Lundy - 2.6 GWe

56%

Cost improvements were evaluated by S&L against three categories: technical improvements, scale-up, and 

production volume. The contribution of these three categories to the S&L LEC projection is shown in Figure 

5-7. 
 

 5-30 

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Figure 5-7 — Sargent & Lundy LEC Projection Breakout by Category 

$0.0000

$0.0200

$0.0400

$0.0600

$0.0800

$0.1000

$0.1200

$0.1400

2004

Solar Tres USA

Near Term

2006

Solar 50

2008

Solar 100

Mid Term

2016

Solar 200

2018

Solar 220

Long Term

Levelized Energy Cost, $/kWhe

Technical - 23%

Scaling - 49%

Volume Production - 28%

The major contributor to cost reduction from Solar Tres to Solar 50 is due to the increase in electrical generation 

(13.5 MWe to 50 MWe) as shown in Figure 5-8. The annual net energy production increased from 93.2 GWh/yr 

to 331 GWh/yr. 
 

 5-31 

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Figure 5-8 — Comparison of SunLab and S&L LEC Estimates: 2004 to 2020 

0.0000

0.0200

0.0400

0.0600

0.0800

0.1000

0.1200

0.1400

2004

Solar Tres USA

Near Term

2006

Solar 50

2010

Solar 100

Mid Term

1015

Solar 200

2020

Solar 220

Long Term

Levelized Energy Cost, $/kWh

Sunlab - 8.7 GWe

S&L - 2.6 GWe

Technology - 11%

Scaling - 54%

Volume Production - 35%

Major Cost Reduction - 

Increase in Net Electrical 

Output

93.2 GWhe/yr to 331 GWhe/yr

The impact of levelized cost of energy for tax credit is shown in Table 5-22. The difference between 10% tax 

credit and no tax credit is about 9% in 2020. 

Table 5-22 — Impact of Tax Credit on Levelized Cost of Energy 

 Near Term Mid Term Long 

Term 

 IRR Percent 

Debt DSCR Solar Tres USA Solar 50 Solar 100 Solar 200 Solar 220

 2004 2006 2010 1015 2020 

SunLab Tower LEC - 10 % 

Tax Credit 

12.12% 59.90% 1.35 0.1171 0.0621 0.0476 0.0392 0.0348 

SunLab Tower LEC - No 

Tax Credit 

12.12% 66.50% 1.35 0.1257 0.0672 0.0516 0.0426 0.0378 
 

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5.6 POWER TOWER TECHNOLOGY STEP CHANGES AND COMPARISON 

Table 5-23 — Solar Two to Solar Tres Technology Comparison 

 Solar 2 Solar Tres 

 SunLab SunLab S&L Basis 

Plant Size – Net Electrical 10 MWe 13.7 MWe 

Plant Size – Thermal 42 MWt 120 MWt 

Field Area, m2 81,400 231,000 244,966 

Thermal Storage 3 hrs 16 hrs 

Annual Plant Capacity 19% 78% 

Heat Transfer Fluid Solar Salt Solar Salt 

Storage Media Solar Salt Solar Salt 

Operating Temperature 565°C 565°C 

Receiver , m2 280 280 

Heliostat Size, m2 40/95 95 

Number of Heliostats 1,912 2,432 2,579 S&L reference case efficiency lower resulting in a 

larger field area 

Annual Solar-to-Electric 

Efficiency 

7.9% 13.7% 13.0% — 

Collector Efficiency 50.3% 56% 56% — 

 a. Mirror Reflectivity 90.7% 93.5% 93.5% This is reasonable since the increase is due to new 

mirrors. Solar Two mirrors were not maintained after 

Solar One was shut down. 

 b. Field Efficiency 62% 64.6% 64.6% The increase is reasonable due to improvements in 

aiming 

 c. Field Availability 98% 98.5% 98.5% This is reasonable since Solar Two was a 

demonstration plant and did not operate for an 

extended duration and used old heliostats. 

 d. Mirror Corrosion 

 Avoidance 

97% 100% 100% This is reasonable since Solar Two mirrors, which 

had not been maintained since Solar One were 

used for Solar Two. This was done to minimize 

costs. The mirror corrosion avoidance for Solar One 

was 100%. Experience at Kramer Junction shows 

that the mirror surface does not experience 

corrosion as long as they are properly maintained 

(i.e., cleaned) 

 e. Mirror Cleanliness 95% 95% 95% The mirror cleanliness projection of 95% is the 

same as demonstrated for Solar One and Solar 

Two. 
 

 5-33 

 SL-5641 

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 Solar 2 Solar Tres 

 SunLab SunLab S&L Basis 

Receiver Efficiency 76% 78.3% 78.3% The change in annual solar-to-electric efficiency is 

0.4%. Includes heliostat aiming errors ‘spillage’. 

 a. Defocus, Dump, 

 startup, clouds 

90% 92.7% 92.7% The increase is reasonable based design changes 

and operations procedures that have been 

incorporated from Solar Two. 

 b. Absorbance 93% 93% 93.0% Did not change from Solar Two to Solar Tres 

 c. Receiver Thermal 

 Losses 

90.7% 90.9% 90.9% Based on increased thermal flux on the receiver 

Electrical 32.6% 40.3% 38.0% Solar Two used a marine turbine without reheat. A 

single reheat turbine will make a considerable 

increase in efficiency. S&L estimated the efficiency 

being slightly less using actual SEGS heat balance 

diagrams and GE STGPER software. 

Thermal Storage 97.0% 98.3% 98.3% The increased efficiency is due to (a) the tank 

surface area to volume ratio decreases with 

increasing tank size and better insulation, which 

reduces heat losses. 

Parasitic (Aux. Power) 73.0% 86.4% 86.4% The parasitic efficiency will increase based on the 

increase in capacity factor, larger plants, and design 

improvements from Solar Two. 

Piping 99.0% 99.5% 99.5% The piping increases are reasonable. Increases in 

the pipe size and shorter lengths result in higher 

efficiencies. 

Plant-wide Availability 90.0% 92.0% 92.0% The availability of 92% should be reached after the 

first 12 to 18 months of operation. Actual availability 

for SEGS VI in 1999 was 98%. 

Table 5-24 — Solar Tres to Solar 50 Technology Comparison 

Solar Tres Solar 50 

 SunLab SunLab S&L Basis

Plant Size – Net Electrical 13.7 MWe 50 MWe 

Plant Size – Thermal 120 MWt 380 MWt 

Field Area, m2 231,000 709,000 742,703 

Thermal Storage 16 hrs 16 hrs 

Annual Plant Capacity 78% 76% 

Heat Transfer Fluid Solar Salt Solar Salt 
 

 5-34 

 SL-5641 

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Solar Tres Solar 50 

 SunLab SunLab S&L Basis

Storage Media Solar Salt Solar Salt 

Operating Temperature 565°C 574°C 

Receiver, m2 280 580 710 

Heliostat Size, m2 95 95 

Number of Heliostats 2,432 7,463 7,818 S&L reference case efficiency lower resulting in a 

larger field area 

Annual Solar-to-Electric 

Efficiency 

13.7% 16.1% 15.5% — 

Collector Efficiency 56% 56.5% 56.5% — 

 a. Mirror Reflectivity 93.5% 94% 94% The change is due to improved glass. 

 b. Field Efficiency 64.6% 64.6% 64.6% Field efficiency did not change from Solar Tres to 

Solar 50. 

 c. Field Availability 98.5% 99% 99% This is reasonable due to better maintenance 

practices and the updated control system. 

 d. Mirror Corrosion 

 Avoidance 

100% 100% 100% Mirror corrosion avoidance did not change from 

Solar Tres to Solar 50. 

 e. Mirror Cleanliness 95% 95% 95% Mirror cleanliness did not change from Solar Tres to 

Solar 50. 

Receiver Efficiency 78.3% 80.9% 80.9% The change in annual solar-to-electric efficiency is 

0.5%. Includes heliostat spillage. 

 a. Defocus, Dump, 

 startup, clouds 

92.7% 93.4% 93.4% The increase of 0.7 is reasonable based better 

operating methods learned during operation of Solar 

Tres. 

 b. Absorbance 93% 93% 93% Did not change from Solar Tres to Solar 50 

 c. Receiver Thermal 

 Losses 

90.9% 93.1% 93.1% Based on increased thermal flux on the receiver 

Electrical 40.3% 41.8% 40.4% S&L estimated the efficiency being slightly less 

using actual SEGS heat balance diagrams and GE 

STGPER software. 

Thermal Storage 98.3% 99.5% 99.5% The increased efficiency is due to (a) the tank 

surface area to volume ratio decreases with 

increasing tank size and better insulation, which 

reduces heat losses. 

Parasitic (Aux. Power) 86.4% 90.0% 90.0% The parasitic efficiency will increase based on the 

increase in capacity factor, larger plants, and design 

improvements from Solar Two. 
 

 5-35 

 SL-5641 

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Solar Tres Solar 50 

 SunLab SunLab S&L Basis

Piping 99.5% 99.9% 99.9% The piping increases are reasonable. Increases in 

the pipe size and shorter lengths result in higher 

efficiencies. 

Plant-wide Availability 92.0% 94.0% 94.0% The availability of 94% should be reached after the 

first 12 to 18 months of operation. Actual availability 

for SEGS VI in 1999 was 98%. 

Table 5-25 — Solar 50 to Solar 100 Technology Comparison 

Solar 50 Solar 100 

 SunLab SunLab S&L Basis

Plant Size – Net Electrical 50 MWe 100 MWe 

Plant Size – Thermal 380 MWt 700 MWe 

Field Area, m2 709,000 1,311,000 1,366,100 

Thermal Storage 16 hrs 13 hrs 

Annual Plant Capacity 76% 73% 

Heat Transfer Fluid Solar Salt Solar Salt 

Storage Media Solar Salt Solar Salt 

Operating Temperature 574°C 574°C 

Receiver, m2 580 930 1,110 

Heliostat Size, m2 95 148 

Number of Heliostats 7,463 8,858 9,230 S&L reference case efficiency lower resulting in a 

larger field area 

Annual Solar-to-Electric 

Efficiency 

16.1% 16.6% 16.1% — 

Collector Efficiency 56.5% 56.3% 56.0% The change in annual solar-to-electric efficiency is 

-0.1%. 

 a. Mirror Reflectivity 94% 94% 94% Mirror reflectivity did not change from Solar 50 to 

Solar 100. 

 b. Field Efficiency 64.6% 63.7% 63.7% This is reasonable since the larger field results in a 

longer average distance from the receiver, which 

reduces the accuracy. 

 c. Field Availability 99% 99.5% 99.5% This is reasonable due to better maintenance 

practices and the updated control system. 
 

 5-36 

 SL-5641 

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Solar 50 Solar 100 

 SunLab SunLab S&L Basis

 d. Mirror Corrosion 

 Avoidance 

100% 100% 100% Mirror corrosion did not change from Solar 50 to 

Solar 100. 

 e. Mirror Cleanliness 95% 95.5% 95% The mirror cleanliness avoidance increased by 

0.5%. Based on interviews at Kramer Junction, 

there is no evidence that cleanliness will not get 

much better than 95%. 

Receiver Efficiency 80.9% 83.1% 83.1% The change in annual solar-to-electric efficiency is 

0.6%. 

 a. Defocus, Dump, 

 startup, clouds 

93.4% 93.4% 93.4% Did not change from Solar 50 to Solar 100 

 b. Absorbance 93% 94% 94% Receiver tube surface absorbtivity increase is 

achieved as a result of R&D. This value was 

achieved at Solar Two. 

 c. Receiver Thermal 

 Losses 

93.1% 94.7% 94.7% Increases in thermal flux on the receiver. 

Electrical 41.8% 42.3% 41.2% S&L estimated the efficiency being slightly less 

using actual SEGS heat balance diagrams and GE 

STGPER software. 

Thermal Storage 99.5% 99.5% 99.5% The increased efficiency is due to (a) the tank 

surface area to volume ratio decreases with 

increasing tank size and better insulation, which 

reduces heat losses. 

Parasitic (Aux. Power) 90.0% 90.0% 90.0% The parasitic efficiency will increase based on the 

increase in capacity factor, larger plants, and design 

improvements from Solar Two. 

Piping 99.9% 99.9% 99.9% The piping increases are reasonable. Increases in 

the pipe size and shorter lengths result in higher 

efficiencies. 

Plant-wide Availability 94.0% 94.0% 94.0% The availability of 94% should be reached after the 

first 12 to 18 months of operation. Actual availability 

for SEGS VI in 1999 was 98%. 
 

 5-37 

 SL-5641 

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Table 5-26 — Solar 100 to Solar 200 Technology Comparison 

 Solar 100 Solar 200

 SunLab SunLab S&L Basis

Plant Size – Net Electrical 100 MWe 200 MWe 

Plant Size – Thermal 700 MWt 1,400 MWt 

Field Area, m2 1,311,000 2,606,000 2,667,099 

Thermal Storage 13 hrs 13 hrs 

Annual Plant Capacity 73% 74% 

Heat Transfer Fluid Solar Salt Solar Salt 

Storage Media Solar Salt Solar Salt 

Operating Temperature 574°C 574°C 

Receiver, m2 930 1,870 1,930 

Heliostat Size, m2 148 148 

Number of Heliostats 8,858 17,608 18,021 S&L reference case efficiency lower resulting in a 

larger field area 

Annual solar-to-electric 

efficiency 

16.6% 16.9% 16.5% — 

Collector Efficiency 56.3% 56.1% 55.2% — 

 a. Mirror Reflectivity 94% 94.5% 94.0% SunLab improvement is due to improved glass. S&L 

base case did not consider improved glass. 

 b. Field Efficiency 63.7% 62.8% 62.8% This is reasonable since the larger field results in a 

longer average distance from the receiver, which 

reduces the accuracy. 

 c. Field Availability 99.5% 99.5% 99.5% Field availability did not change from Solar 100 to 

Solar 200. 

 d. Mirror Corrosion 

 Avoidance 

100% 100% 100% Mirror corrosion avoidance did not change from 

Solar 100 to Solar 200. 

 e. Mirror Cleanliness 95.5% 96% 95% The mirror cleanliness increased by 0.5%. Based on 

interviews at Kramer Junction, there is no evidence 

that cleanliness will not get much better than 95%. 

Receiver Efficiency 83.1% 83.5% 83.5% The change in annual solar-to-electric efficiency is 

0.1%. 

 a. Defocus, Dump, 

 startup, clouds 

93.4% 93.4% 93.4% Did not change from Solar 100 to Solar 200 

 b. Absorbance 94% 94.5% 94.5% Receiver tube surface absorbtivity increase is 

achieved as a result of R&D on coatings and/or 

more frequent repainting. 
 

 5-38 

 SL-5641 

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 Solar 100 Solar 200

 SunLab SunLab S&L Basis

 c. Receiver Thermal 

 Losses 

94.7% 94.7% 94.7% Did not change from Solar 100 to Solar 200 

Electrical 42.3% 42.8% 42.6% S&L estimated the efficiency being slightly less 

using actual SEGS heat balance diagrams and GE 

STGPER software. 

Thermal Storage 99.5% 99.5% 99.5% The increased efficiency is due to (a) the tank 

surface area to volume ratio decreases with 

increasing tank size and better insulation, which 

reduces heat losses. 

Parasitic (Aux. Power) 90.0% 90.0% 90.0% The parasitic efficiency will increase based on the 

increase in capacity factor, larger plants, and design 

improvements from Solar Two. 

Piping 99.9% 99.9% 99.9% The piping increases are reasonable. Increases in 

the pipe size and shorter lengths result in higher 

efficiencies. 

Plant-wide Availability 94.0% 94.0% 94.0% The availability of 94% should be reached after the 

first 12 to 18 months of operation. Actual availability 

for SEGS VI in 1999 was 98%. 

Table 5-27 — Solar 200 to Solar 220 Technology Comparison 

 Solar 200 Solar 220

 SunLab SunLab S&L Basis

Plant Size – Net Electrical 200 MWe 220 MWe 

Plant Size – Thermal 1,400 MWt 1,400 MWt 

Field Area, m2 2,606,000 2,642,000 2,789,322 

Thermal Storage 13 hrs 16 hrs 

Annual Plant Capacity 74% 73% 

Heat Transfer Fluid Solar Salt Solar Salt 

Storage Media Solar Salt Solar Salt with O2

blanket 

 

Operating Temperature 574°C 650°C 

Receiver 1,870 1,650 1,990 

Heliostat Size (m2) 148 148 

Number of Heliostats 17,608 17,851 18,847 S&L reference case efficiency lower resulting in a 

larger field area 
 

 5-39 

 SL-5641 

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 Solar 200 Solar 220

 SunLab SunLab S&L Basis

Annual solar-to-electric 

efficiency 

16.9% 18.1% 17.4% — 

Collector Efficiency 56.1% 57% 55.5% — 

 a. Mirror Reflectivity 94.5% 95% 94.5% This is due to improved glass. S&L projected the 

increase to be 0.5% for the first plant with advanced 

heliostats. 

 b. Field Efficiency 62.8% 62.8% 62.8% Field efficiency did not change from Solar 200 to 

Solar 220. 

 c. Field Availability 99.5% 99.5% 99.5% Field availability did not change from Solar 200 to 

Solar 220. 

 d. Mirror Corrosion 

 Avoidance 

100% 100% 100% Mirror corrosion avoidance did not change from 

Solar 200 to Solar 220. 

 e. Mirror Cleanliness 96% 97% 95% The mirror cleanliness increased by 1%. Based on 

interviews at Kramer Junction, there is no evidence 

that cleanliness will not get much better than 95%. 

Receiver Efficiency 83.5% 82.0% 82.0% The change in annual solar-to-electric efficiency 

decreased 1.5%. 

 a. Defocus, Dump, 

 startup, clouds 

93.4% 93.4% 93.4% Did not change from Solar 200 to Solar 220 

 b. Absorbance 94.0% 94.5% 94.5% Receiver tube surface absorbtivity increase is 

achieved as a result of R&D on coatings and/or 

more frequent repainting. 

 c. Receiver Thermal 

 Losses 

94.7% 92.9% 92.9% Decreased 1.8% 

Electrical 42.8% 46.1% 45.4% S&L estimated the efficiency being slightly less 

using actual SEGS heat balance diagrams and GE 

STGPER software. The higher temperatures were 

extrapolated 

Thermal Storage 99.5% 99.5% 99.5% The increased efficiency is due to (a) the tank 

surface area to volume ratio decreases with 

increasing tank size and better insulation, which 

reduces heat losses. 

Parasitic (Aux. Power) 90.0% 90.0% 90.0% The parasitic efficiency will increase based on the 

increase in capacity factor, larger plants, and design 

improvements from Solar Two. 

Piping 99.9% 99.9% 99.9% The piping increases are reasonable. Increases in 

the pipe size and shorter lengths result in higher 

efficiencies. 

Plant-wide Availability 94.0% 94.0% 94.0% The availability of 94% should be reached after the 

first 12 to 18 months of operation. Actual availability 

for SEGS VI in 1999 was 98%. 
 

 5-40 

 SL-5641 

 Final 

 

 

 

5.7 COST REDUCTION STEP CHANGES AND BREAKDOWN COMPARISON 

Table 5-28 — Solar Two to Solar Tres Cost Reduction Comparison 

Heliostat Cost Solar 2 Solar Tres 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

10 13.7 

Plant Size – Thermal, MWt 42 120 

Heliostat Size, m2 48/95 95 

Field Area, m2 81,400 231,000 244,966 

Number of Heliostats 1,912 2,432 2,579 

Capital Cost, $M $33.5 $39.1 

Cost per m2 $145 $160 

A. Technology — 26% The annual heliostat efficiency went from 50.3% to 

56%. Major design improvements include the 

enhanced azimuth drive, elevation drive, and 

communication equipment 

B. Economy of Scale — 37% There is economy of scale since Solar Tres is based 

on 95-2 heliostat whereas Solar Two used mostly 

40-m2

 heliostats (1,818 out of 1,926 heliostats) 

C. Production Volume — 37% Production volume is a significant contributor to the 

cost reduction. As the volume increases the cost per 

unit decreases by three factors: fixed cost decrease 

proportionally to the number of units produced, 

volume purchasing discounts, and learning curve 

from repetitive assembly improvements. 

Electric Power Block Solar 2 Solar Tres 

Cost Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

10 13.7 

Plant Size – Thermal, MWt 42 120 

Capital Cost, $M $10 $7.6 SunLab Cost Estimate 

Cost per installed kWe $733 $557 

A. Technology — 3% The annual efficiency went from 40.3% to 41.8%. 

The turbine generator design is based on proven 

standard industry technology. 

B. Economy of Scale — 97% The economy of scale is the major cost 

improvement. 
 

 5-41 

 SL-5641 

 Final 

 

 

 

Electric Power Block Solar 2 Solar Tres 

Cost Improvements 

SunLab SunLab S&L Basis 

C. Production Volume — 0% No production volume contribution since there is 

only one turbine-generator per plant. 

The learning curve is not a factor due to the turbinegenerator being a standard proven technology. 

Receiver Cost Solar 2 Solar Tres 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

10 13.7 

Plant Size – Thermal, MWt 42 120 

Receiver Surface Area, m2 100 280 

Peak Solar Flux, MWt/m2 0.8 0.95 

Capital Cost, $M $9.1 $14.0 $16.0 

Cost per m2 , k$/m2 $91 $50 $57 

A Technology — 32% The efficiency went from 76% to 78.3%. Major 

design changes include the following: 

Change from 316SS to high nickel alloy provides a 

higher peak solar flux which decreases the surface 

area, elimination of receiver outlet vessel, improved 

inlet vessel operational design, simpler header 

design with fewer components, more internal space, 

elimination of vents & drains, and improved stress 

analysis. 

B. Economy of Scale — 50% The size scale up factor of 3 is feasible based 

technical advances projected by Boeing. 

C Production Volume — 18% Production volume is not a significant factor. The 

cost improvements are for automation of panel 

assembly, improved tools, optimized factory layout, 

replication, and reduced labor rates in Spain (7%). 

Learning curve is reasonable based on repetitive 

assembly operations and Boeing’s experience. 

6,000 clips are welded on 850 individual tubes that 

are welded to 34 headers, which are part of 17 

identical receiver panels. 
 

 5-42 

 SL-5641 

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Table 5-29 — Solar Tres to Solar 50 Cost Reduction Comparison 

Heliostat Cost Solar Tres Solar 50 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

13.7 50 

Plant Size – Thermal, MWt 120 380 

Heliostat Size, m2 95 95 

Field Area, m2 231,000 709,000 742,703 

Number of Heliostats 2,432 7,463 7,818 

Capital Cost, $M $33.5 $89.8 $111.7 

Cost per m2 $145 $127 $150 

A. Technology 26% 11% The annual heliostat efficiency went from 56% to 

56.5%. Major design improvements include the 

enhanced azimuth drive, elevation drive, and 

communication equipment 

B. Economy of Scale 37% 0% There is no economy of scale since Solar 50 is 

based on the same size heliostat as Solar Tres 

(95 m2

). 

C. Production Volume 37% 89% Production volume is the largest contributor to the 

cost reduction. As the volume increases the cost per 

unit decreases by three factors: fixed cost decrease 

proportionally to the number of units produced, 

volume purchasing discounts, and learning curve 

from repetitive assembly improvements. 

Electric Power Block Solar Tres Solar 50 

Cost Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

13.7 50 

Plant Size – Thermal, MWt 120 380 

Capital Cost, $M $10 $24.5 $18.6 SunLab Cost Estimate 

Cost per installed kWe $733 $490 $372 

A. Technology 3% 3.2% The annual efficiency went from 40.3% to 41.8%. 

The turbine generator design is based on proven 

standard industry technology. 

B. Economy of Scale 97% 96.7% The economy of scale is the major cost 

improvement. 
 

 5-43 

 SL-5641 

 Final 

 

 

 

Electric Power Block Solar Tres Solar 50 

Cost Improvements 

SunLab SunLab S&L Basis 

C. Production Volume 0% 0% No production volume contribution since there is 

only one turbine-generator per plant. 

The learning curve is not a factor due to the turbinegenerator being a standard proven technology. 

Receiver Cost Solar Tres Solar 50 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

13.7 50 

Plant Size – Thermal, MWt 120 380 

Receiver Surface Area, m2 280 580 710 

Peak Solar Flux, MWt/m2 0.95 1.2 1.2 

Capital Cost, $M $14.0 $19.8 $26 

Cost per m2 , k$/m2 $50 $34 $37 

A. Technology 32% 35% The efficiency went from 78.3% to 80.9%. Major 

design changes include the following: 

Receiver fluid side heat transfer enhancements, 

improved thermal storage tank design, increase 

peak solar flux based on operational experience 

from Solar Tres, further elimination of vent & drain 

valves 

B. Economy of Scale 50% 43% The size scale up factor of 2 is feasible based 

technical advances projected by Boeing. 

C. Production Volume 18% 22% Production volume is not a significant factor. The 

cost improvement for moderate automation of panel 

assembly, optimized factory layout and quantity 

discount of materials for multiple plant orders based 

on a 3% decrease in material and component cost. 

Learning curve is reasonable based on repetitive 

assembly operations and Boeing’s experience. 
 

 5-44 

 SL-5641 

 Final 

 

 

 

Table 5-30 — Solar 50 to Solar 100 Cost Reduction Comparison 

Heliostat Cost Solar 50 Solar 100 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

50 100 

Plant Size – Thermal, MWt 380 700 

Heliostat Size, m2 95 148 

Field Area, m2 709,000 1,311,000 1,366,100 

Number of Heliostats 7,463 8,858 9,230 

Capital Cost, $M $89.8 $139.8 $182.7 

Cost per m2 $127 $107 $134 

A. Technology 11% 35% The annual heliostat efficiency went from 56.5% to 

56.3%. Major design improvements include the 

enhanced azimuth drive, elevation drive, and 

communication equipment to support the 148 m2 

heliostat. The major technical advance is thin glass 

to increase reflectivity. 

B. Economy of Scale 0% 57% There is economy of scale since Solar 50 uses a 

95-m2

 heliostat and Solar 100 uses a 148-m2

heliostat. 

C. Production Volume 89% 8% Production volume is a small large contributor to the 

cost reduction. 

Electric Power Block Solar 50 Solar 100 

Cost Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

50 100 

Plant Size – Thermal, MWt 380 700 

Capital Cost, $M $24.5 $40 $30.8 

Cost per installed kWe $490 $400 $308 

A. Efficiency 3% 1% The annual efficiency went from 41.8% to 42.3%. 

The turbine generator design is based on proven 

standard industry technology. 

B. Economy of Scale 97% 99% The economy of scale is the major cost 

improvement. 
 

 5-45 

 SL-5641 

 Final 

 

 

 

Electric Power Block Solar 50 Solar 100 

Cost Improvements 

SunLab SunLab S&L Basis 

C. Production Volume 0% 0% No production volume contribution since there is 

only one turbine-generator per plant. 

The learning curve is not a factor due to the turbinegenerator being a standard proven technology. 

Receiver Cost Solar 50 Solar 100 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

50 100 

Plant Size – Thermal, MWt 380 700 

Receiver Surface Area, m2 580 930 1,110 

Peak Solar Flux, MWt/m2 1.2 1.4 1.4 

Capital Cost, $M $19.8 $25 $34 

Cost per m2 , k$/m2 $34 $27 $31 

A. Technology 35% 66% The efficiency went from 80.9% to 83.1%. Major 

design changes include the following: 

Further elimination of components, development of 

Boeing optimization codes, increase peak solar flux 

based on operational experience from Solar 50. 

B. Economy of Scale 43% 25% The size scale up factor of 1.6 is feasible based 

technical advances projected by Boeing. 

C. Production Volume 22% 9% Production volume is not a significant factor. The 

cost improvement for automated equipment 

amortized over several plants, and quantity discount 

of materials for multiple plant orders based on a 3% 

decrease in material and component cost. Learning 

curve is reasonable based on repetitive assembly 

operations and Boeing’s experience. 
 

 5-46 

 SL-5641 

 Final 

 

 

 

Table 5-31 — Solar 100 to Solar 200 Cost Reduction Comparison 

Heliostat Cost Solar 100 Solar 200 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

100 200 

Plant Size – Thermal, MWt 700 1,400 

Heliostat Size, m2 148 148 

Field Area, m2 1,311,000 2,600,000 2,667,099 

Number of Heliostats 8,858 17,608 18,021 

Capital Cost, $M $141.2 $249.6 $330.0 

Cost per m2 $107 $96 $124 

A. Technology 35% 5% The annual heliostat efficiency went from 56.3% to 

56.1%. Major design improvements include the 

enhanced azimuth drive, elevation drive, and 

communication equipment 

B. Economy of Scale 57% 0% There is no economy of scale since Solar 200 is 

based on the same size heliostat as Solar 100 (148 

m2

). 

C.1 Production Volume 8% 95% Production volume is the largest contributor to the 

cost reduction. As the volume increases the cost per 

unit decreases by three factors: fixed cost decrease 

proportionally to the number of units produced, 

volume purchasing discounts, and learning curve 

from repetitive assembly improvements. 

Electric Power Block Solar 100 Solar 200 

Cost Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

100 200 

Plant Size – Thermal, MWt 700 1,400 

Capital Cost, $M $40 $64 $46.2 

Cost per installed kWe $400 $320 $231 

A. Technology 1% 1% The annual efficiency went from 42.3% to 42.8%. 

The turbine generator design is based on proven 

standard industry technology. 

B. Economy of Scale 99% 99% The economy of scale is the major cost 

improvement. 
 

 5-47 

 SL-5641 

 Final 

 

 

 

Electric Power Block Solar 100 Solar 200 

Cost Improvements 

SunLab SunLab S&L Basis 

C. Production Volume 0% 0% No production volume contribution since there is 

only one turbine-generator per plant. 

The learning curve is not a factor due to the turbinegenerator being a standard proven technology. 

Receiver Cost Solar 100 Solar 200 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

100 200 

Plant Size – Thermal, MWt 700 1,400 

Receiver Surface Area, m2 930 1,650 1,990 

Peak Solar Flux, MWt/m2 1.4 1.6 1.6 

Capital Cost, $M $25 $36.9 $46.0 

Cost per m2 , k$/m2 $27 $22 $23 

A. Technology 66% 65% The efficiency went from 83.1% to 83.5%. Major 

design changes include the following: 

Further elimination of components, continued 

development of Boeing optimization codes, increase 

peak solar flux based on operational experience 

from Solar 100. 

B. Economy of Scale 25% 24% The size scale up factor of 1.8 is feasible based 

technical advances projected by Boeing. 

C. Production Volume 9% 11% Production volume is not a significant factor. The 

cost improvement for moderate automation in panel 

assembly and optimized factory layout, costs for 

automated equipment is amortized over several 

plants, and quantity discount of materials for 

multiple plant orders based on a 2% decrease in 

material and component cost. Learning curve is 

reasonable based on repetitive assembly operations 

and Boeing’s experience. 
 

 5-48 

 SL-5641 

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Table 5-32 — Solar 200 to Solar 220 Cost Reduction Comparison 

Heliostat Cost Solar 200 Solar 220 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

200 220 

Plant Size – Thermal, MWt 1,400 1,400 

Heliostat Size, m2 148 148 

Field Area, m2 2,600,000 2,642,000 2,789,322 

Number of Heliostats 17,608 17,851 18,847 

Capital Cost, $M $249.6 $198.8 $263.0 

Cost per m2 $96 $75 $94 

A. Technology 5% 72% The annual heliostat efficiency went from 56.1% to 

57%. Major design improvements are new 

advanced heliostat. 

B. Economy of Scale 0% 0% There is no economy of scale since Solar 220 is 

based on the same size heliostat as Solar 200 

(148 m2

). 

C. Production Volume 95% 28% Production volume is a contributor to the cost 

reduction. As the volume increases the cost per unit 

decreases by three factors: fixed cost decrease 

proportionally to the number of units produced, 

volume purchasing discounts, and learning curve 

from repetitive assembly improvements. 

Electric Power Block Solar 200 Solar 220 

Cost Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

200 220 

Plant Size – Thermal, MWt 1,400 1,400 

Capital Cost, $M $64 $83.6 $61.8 

Cost per installed kWe $320 $380 $281 

A.1 Technology 1% 80% The annual efficiency went from 42.8% to 46.1%. 

The increase is due to turbine advances in 

technology. The cost reduction from the increase in 

efficiency is $6.2 million. The higher efficiency 

turbine is estimated to cost an additional 20%. 

 The cost reduction from increase in efficiency of 

$6.2 million is offset by the higher cost ($83.6 M - 

$64 M = $19.6 M) and increased capacity. 
 

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Electric Power Block Solar 200 Solar 220 

Cost Improvements 

SunLab SunLab S&L Basis 

B. Economy of Scale 99% 20% Economy of scale is a contributor due to the 

increase in size. 

C. Production Volume 0% 0% No production volume contribution since there is 

only one turbine-generator per plant. 

Receiver Cost Solar 200 Solar 220 

Improvements 

SunLab SunLab S&L Basis 

Plant Size – Electrical, 

MWe 

200 220 

Plant Size – Thermal, MWt 1,400 1,400 

Receiver Surface Area, m2 1,650 1,650 1,990 

Peak Solar Flux, MWt/m2 1.6 1.6 1.6 

Capital Cost, $M $36.9 $34.4 $48.0 

Cost per m2 , k$/m2 $22 $21 $24 

A. Technology 65% 31 The efficiency went from 83.5% to 82%. Major 

design changes include the following: 

Further elimination of components, continued 

development of Boeing optimization codes, increase 

peak solar flux based on operational experience 

from Solar 100. 

B. Economy of Scale 24% 61 The size scale up factor of 1.8 is feasible based 

technical advances projected by Boeing. 

C. Production Volume 11% 8 Production volume is not a significant factor. The 

cost improvement for moderate automation in panel 

assembly and optimized factory layout, costs for 

automated equipment is amortized over several 

plants, and quantity discount of materials for 

multiple plant orders based on a 2% decrease in 

material and component cost. Learning curve is 

reasonable based on repetitive assembly operations 

and Boeing’s experience. 

5.8 RISK ASSESSMENT FOR TOWER TECHNOLOGY 

This section provides an overview and assessment of the risks associated with attaining competitive 

commercialization for the tower technology on a short-term, mid-term, and long-term basis. Competitiveness is 

measured by the levelized energy cost (LEC), expressed as $/kWh, consisting of two elements: total investment 

cost and operation and maintenance (O&M) cost. 
 

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• The major total investment cost drivers of the tower plant are the solar field, power block, and 

receiver, which account for approximately 74% of the total costs. Also, the net annual solar-toelectric efficiency has an impact on the cost of a tower plant. The solar field (heliostats and 

receiver) has to be increased proportionally for decrease in efficiency. For every one-percentage 

point improvement in the net efficiency, the LEC for is reduced by approximately 0.5%. 

Total cost reductions occur from technical improvements, increase in plant size (scaling), and volume 

production (learning curves). All three are dependent on deployment of the technology. Deployment provides a 

means for continued research in technology improvements, cost reductions due to increased production, and 

economy of scale from constructing larger plants. 

The second element of the levelized energy cost is the O&M costs. For the tower plant, O&M costs represent 

about 25% of the LEC. 

As such, the focus of the risk assessment covers the following main categories: 

• Deployment 

• Net Annual Solar-to-Electric Efficiency 

• Total Investment Cost 

• Operation and Maintenance 

5.8.1 Deployment 

Market expansion of trough technology will require incentives to reach market competitiveness. Numerous 

potential incentives exist, such as: environmental (CO2 emission credits), favorable tax credits, favorable peak 

energy tariff, premium consumer pricing, loan guarantees, low interest loans, and grants. Analysis of incentives 

required to reach market acceptance is not within the scope of this report. S&L’s estimate corresponds to the 

SunLab Reference Cases with near-term deployment in 2004, mid-term deployment in 2010, and long-term 

deployment in 2020 for comparison. Sensitivity analysis was done to consider the more realistic deployment of 

the first commercial plant being placed in service in 2006. The earliest a plant would be operational in the 

United States is 2009 based on the first commercial plant going in service in 2006 in Spain or South Africa, 

operational experience of at least one year, and two years for design enhancements, manufacturing, and 

construction. 

The risk is mid to high for development in the United States since market expansion will require incentives to 

reach market acceptance (competitive). S&L’s projection is more conservative than the SunLab projection of 
 

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8.7 GWe. The S&L projected range is a maximum deployment of 4.7 GWe and a minimum deployment of 

1.2 GWe. The S&L base case is a deployment of 2.6 GWe. 

5.8.1.1 Near Term (2004) 

The SunLab near-term deployment projection is based on the first commercial plant (Solar Tres) being built in 

Spain in 2004. Upon successful completion of Solar Tres, a 50-MW plant will be built in 2006. 

The risk for meeting the near-term goals is low to mid outside of the United States and mid to high in the United 

States. Project development is in progress for two projects: Solar Tres in Spain and ESKOM in South America. 

The governments have provided the incentives necessary for the projects to be competitive so that financing can 

be secured. The Solar Tres current schedule is for permits and financing to be in place by the end of 2003 with 

commercial operation early in 2006. The risk for meeting the goals in the United States is high since there are no 

current plans for government-sponsored incentives. However, the Western Governors’ Association provided 

recent favorable support for CSP technology (EERE 2002). 

5.8.1.2 Mid Term (2010) 

The SunLab mid-term deployment projection is five 50-MW plants and six 100-MW plants being deployed in 

the years 2007 through 2010. 

The S&L mid-term deployment projection is one 50-MW plan being deployed in the years 2007 through 2010. 

The S&L projection is based on Solar Tres being deployed in 2006 and the first 50-MW plant being deployed in 

2009. The S&L projection took into consideration additional time between the first plant and subsequent plants 

of the same size. The first plant of each size will take longer to complete and reach steady-state operation. 

Sargent & Lundy projects one 50-MW plant being deployed in 2009 and one 100-MW plant being deployed in 

the years 2007 through 2010. SunLab projected the first 50-MW plant for 2006, whereas S&L projected it for 

2007. SunLab projected the first 100-MW plant for 2008, whereas S&L projected it for 2010. Our estimate takes 

into consideration the time to identify and incorporate lessons learned into the subsequent plants. S&L was also 

not as aggressive in deployment projections as SunLab. The difference between the two projections provides a 

range of deployment. Again, deployment is entirely based on market expansion and the incentives to reach 

market acceptance. Without incentives, there is no market for towers in the United States in the near future. If 

market expansion occurs in foreign countries based on incentives, then tower power could be introduced to the 

United States after it reaches market acceptance. 
 

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5.8.1.3 Long Term (2020) 

The SunLab long-term deployment projection is twenty-one 100-MW plants with improved technology being 

deployed in the years 2011 through 2017; twenty-two advanced technology 200-MW plants in the years 2012 

through 2019; and six 220-MW advanced technology plants in the years 2018 to 2020. The SunLab total longterm deployment is 8,734 MW installed capacity. 

The S&L long-term projection is three 50-MWe plants, four 100-MWe plants, and three 200-MWe plants being 

deployed in the years 2011 through 2020. The S&L total long-term deployment is 1,214 MW installed capacity. 

The risk is high for development in the United States since market expansion will require incentives to reach 

market acceptance (competitive). If there are governmental incentives, the risk of deploying 1.2 GWe from 2006 

to 2020, without the advanced 220-MW plant is low. The number or plants is achievable and provides adequate 

duration between each larger plant to allow for lessons learned and design enhancements. 

The impact of deployment on LEC is noted in the following table: 

Table 5-33 — Impact of Deployment on LEC 

(Keeping Net Efficiency Constant) 

LEC 

Year 2020 

Total 

Deployment 

(GWe) 

Net Solar-toElectric Efficiency

(%) ($/kWh) 

Percent change from 

S&L Base Case 

SunLab 8.7 18.1 0.0350 SunLab Base 

S&L 8.7 16.5 0.0524 -4.2% 

S&L 4.7 16.5 0.0538 -1.6% 

S&L 2.6 16.5 0.0547 S&L Base 

S&L 1.2 16.5 0.0559 2.2% 

5.8.2 Net Annual Solar-to-Electric Efficiency 

5.8.2.1 Near Term (2004) 

The SunLab projected near-term net annual solar-to-electric efficiency of 13.7%, an improvement of 6.1 

percentage points from the Solar Two Demonstration Project 7.6% efficiency. The increased efficiency is 
 

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mainly attributable to improved collector properties, parasitic load, receiver, and reheat turbine. The 

demonstrated improvements and design enhancements are as follows: 

• Solar Two demonstration used 40-m2

 and 95-m2 heliostats. The near-term plant uses 95-m2

heliostats. The risk of achieving this technology is low since the technology has been 

demonstrated. There have been 865 95-m2

 ARCO/ATS heliostats built and successfully 

operated. 

• The collector (heliostat) efficiency is 5.7% higher than that demonstrated during Solar Two. 

The risk of achieving the improvements is low for the following reasons: 

 There is no significant change in the technology. 

 Mirror reflectivity efficiency is projected to increase 2.8% as a result of using new mirrors. 

The mirrors used at Solar Two were not maintained after the shutdown of Solar One. 

 Field efficiency is projected to increase 2.6% as a result of improvements in aiming 

technology. This should be achieved since there have been significant improvements in 

controls systems throughout many industries since Solar Two that can be applied to control 

aiming. 

 Mirror corrosion avoidance efficiency is projected to increase 3% as a result of new 

mirrors. The mirrors used for Solar Two had not been maintained. Experience at Kramer 

Junction shows that the mirror surfaces do not corrode as long as they are properly 

maintained. 

 Field availability is projected to increase 0.5%, which is reasonable based on design 

improvements from lessons learned during Solar Two and improved reliability of new 

equipment. 

• Improved steam turbine cycle efficiency projection of 6.5% is as a result of increasing steam 

temperature from 510°C to 540°C and using single reheat turbine technology. There is no steam 

turbine technological risk since there are numerous single reheat steam turbines operating with 

the same steam inlet conditions. 

• Improved parasitic power efficiency projection of 13.4% is a result of increasing the plant size. 

As the size of a plant increases, the parasitic power efficiency decreases exponentially. The risk 

of achieving parasitic power efficiency improvements is low to medium. 

• The receiver efficiency is projected to increase 2.3 percentage points from 76%, as 

demonstrated at Solar 2, to 78.3%. The increase is based on the following design changes: 

receiver fluid side heat transfer enhancements, improved thermal storage tank design, increased 

peak solar flux based on operational data from Solar 2, and elimination of vent and drain valves. 

The risk of achieving these efficiency increases is low based on the demonstration at Solar 2, on 

the design changes, and because Boeing, who is the supplier of the Solar Tres receiver, must 

meet guaranteed design conditions. 

• Improved thermal storage efficiency is projected to be 1.3%. The risk of achieving this is low 

since Solar Two demonstrated (a) molten salt as a viable, large-scale thermal energy storage 

medium and (b) the design, construction, and performance of large, field-erected externally 

insulated tanks for storing molten salt. The increase in efficiency can be achieved as a result 
 

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decreases in heat loss due to the tank surface area-to-volume ratio decreasing with increasing 

tank size. 

The risk of achieving the near-term net annual solar-to-electric efficiency of 13.7% is low, since the technology 

has been demonstrated at Solar One and Solar Two, the proposed enhancements do not constitute a change to 

the basis technology, and the proposed design enhancements are reasonable. 

5.8.2.2 Mid Term (2010) 

The SunLab projected mid-term net annual solar-to-electric efficiency is 16.6%; an improvement of 2.9 

percentage points from the near-term projected efficiency of 13.7%, mainly attributable to these improvements: 

• Improved collector efficiency of 0.3% 

• Improved steam turbine cycle efficiency of 2 percentage points as a result of increasing from 

15 MW to 100 MW. 

• Improved receiver efficiency of 4.8% as a result of increases in the solar flux level from 

reduced thermal losses. 

• Improved parasitic efficiency of 3.6% as a result of the increasing from 15 MW to 100 MW. 

• Improved thermal storage efficiency of 1.2% 

The risk of achieving the mid-term net annual solar-to-electric efficiency of 16.6% is average based on the 

following: 

• The collector size is being increased from 95 m2

 to 148 m2 heliostats. There are no significant 

technical design changes to the heliostat. The risk of increasing to a 148 m2

 heliostat is low 

based on the following: (a) the technology of the 148-m2

 heliostat is essentially the same as the 

95-m2

 heliostat, (b) ATS has performed detailed engineering and design for the 148-m2 heliostat 

and (c) forty-five 148-m2

 collectors (2 heliostats and 43 PV trackers) have been built and are in 

operation. 

• The projected collector efficiency is from (a) increases in field availability from better 

maintenance practices and updated control systems, and (b) increases in mirror cleanliness. 

S&L projected that there would be no increase in efficiency as a result of mirror cleanliness 

efficiency demonstrated at Kramer Junction. The risk of increasing mirror cleanliness is mid to 

high as a result of the research required to develop materials and cleanliness methods. 

• There are numerous steam turbines in the 100-MWe range in operation throughout the world. 

The efficiency was independently determined by S&L using the General Electric STGPR 

software program to be 41.4%, which is slightly lower than the 42.3% efficiency used by 

SunLab. 

• The projected receiver efficiency increase is 4.8 percentage points from 78.3% to 83.1%. 

Boeing has projected the increase based on further elimination of components, development of 
 

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Boeing optimization codes, and increased peak solar flux based on operational experience of 

previous plants. The risk in achieving these projections is average. The information and specific 

basis for the efficiency increase is propriety but the concepts for efficiency increases are 

reasonable: reduced receiver thermal losses due to thermal flux increasing and increased 

receiver tube surface absorbtivity as a result of Boeing R&D. 

• The projected efficiency increase for thermal storage is 1.2% and should be achieved based on 

using the same technology demonstrated at Solar Two and reducing heat loss due to the tank 

surface area-to-volume ratio decreasing with increasing tank size. 

• Improved parasitic power efficiency of 3.6% is a result of increasing the plant size. As the size 

of a plant increases, the parasitic power efficiency decreases exponentially. The risk of not 

achieving parasitic power efficiency improvements is low. 

• Improved plant availability efficiency of 2 percentage points from 92% to 94% is a result of the 

operational knowledge and equipment reliability improvements gained from experience in 

operating numerous plants. The availability of tower technology should be similar to the 

demonstrated high availability of the SEGS plants. 

A mid-term net annual solar-to-electric efficiency of 16.6% represents an average risk. 

Sargent & Lundy estimated net annual solar-to-electric efficiency to be 16.1% by limiting the technology 

improvements to currently demonstrated technology, tested improvements, and realistic assumptions. The 

difference between SunLab and S&L estimates is that S&L limited the mirror cleanliness to an efficiency of 

95% based actual experience at Kramer Junction and there is no proven technology or methods to achieve 

cleanliness above 95%. 

5.8.2.3 Long Term (2020) 

The SunLab projected long-term net annual solar-to-electric efficiency is 18.1%, an improvement of 1.5 

percentage points from the mid-term projected efficiency of 16.6%. This improvement is mainly attributable to 

the following: 

• Improved steam turbine cycle efficiency of 3.8 percentage points as a result of increasing from 

100 MW to 220 MW and use of advanced dual reheat turbine at 640°C. 

• Improved collector efficiency of 0.7% as a result of new advanced heliostat design. 

The risk of achieving the long-term net annual solar-to-electric efficiency of 18.1% is high based on projecting 

advanced technology being available for advanced steam turbines and heliostats. However, the risk is greatly 

reduced if (a) the tower technology is successfully deployed to the extent that the competitive market prompts 

research and development of technological advances for heliostats, (b) the competitiveness of the energy market 
 

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prompts continued research and development on advanced steam turbines, and (c) research continues on hightemperature metallurgy. 

The advanced heliostat design is projected to use thin glass mirrors to increase reflectivity. Conversion to the 

thin glass will require additional structural support. Alternatives to glass mirror reflectors have been in various 

stages of initial development and/or testing. The risk for achieving a heliostat design with thin glass or thin-film 

reflector is high. 

The risk for advanced turbines with higher inlet steam temperature and pressure is high. There is current 

research on increasing steam turbine efficiencies with increased inlet steam temperature and pressure. The 

increase is technically feasible, but is dependent on continued research and market. The focus will be on largersized steam turbines and will not be available for the smaller units unless there is a market. There is also a 

technical risk in identifying and solving the higher temperature impact on materials. 

The risk of achieving thermal storage efficiency of 99.9% is low since it was demonstrated at Solar Two. Use of 

solar salt with an O2 blanket to account for the higher operating temperature (e.g. 650°C) is a medium to high 

risk. 

A long-term net annual to solar efficiency of 17.3%, which does not include the advanced turbine or advanced 

heliostat technology, represents a low to medium risk. In addition, the mirror cleanliness efficiency is 

maintained at a demonstrated value of 95%, and the mirror reflectivity efficiency is maintained at a 

demonstrated value of 94% (e.g., no advanced glass). 

The impact of net annual solar-to-electric efficiency on LEC is as follows: 

Table 5-34 — Impact of Net Solar-to-Electric Efficiency on LEC 

(Keeping Deployment Constant) 

LEC 

Year 2020 

Total 

Deployment 

(GWe) 

Net Solar-toElectric Efficiency

(%) ($/kWh) 

Percent change from 

S&L Base Case 

SunLab 8.7 18.1% 0.0350 SunLab Base 

S&L 2.6 17.3% 0.0476 -13.0% 

S&L 2.6 16.5% 0.0547 S&L Base 

S&L 2.6 14.6% 0.0590 7.9% 
 

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5.8.3 Total Investment Cost 

The major cost contributors in total investment cost of a tower solar plant are the solar collector field (43%), 

receiver system (16%), and the power block (13%). 

In combination with thermal storage, increased annual net efficiency, and reduced equipment cost via 

technology advancements, competition and deployment are the primary elements in reducing the long-term cost 

of the tower plant. 

5.8.3.1 Near Term (2004) 

The SunLab projected near-term total investment cost is $7,135/kWe as compared to S&L’s estimate of 

$8,209/kWe. The SunLab projected near-term total investment cost is based on (a) actual values from Solar 

Two, (b) detailed cost estimates done by industry, and (c) scaling projections and escalation done by SunLab. 

The basis for the near-term cost is as follows: 

• The capital cost of the heliostat estimated by SunLab is $145 per m2

 as compared to the S&L 

estimate of $160. S&L reviewed several detailed cost estimates and developed a composite cost 

analysis. The detailed cost estimates used were developed by ADLittle (2001), PeerlessWinsmith (1989, 1996, 1999), Advanced Thermal Systems (1996), and Solar Kinetics (1996) 

for the 148-m2

 heliostat. S&L evaluated each cost component associated with the manufacturing 

of heliostats. The largest cost components are the drive mechanisms, which are about 50% of 

the total cost. This cost is relativity accurate since there are detailed cost estimates from the 

manufacturer. The cost for the 95-m2

 heliostat was then estimated based on a scaling factor of 

0.80, which is more conservative than the industry standard of 0.7. 

• The receiver cost estimate is based on information provided by Boeing. Boeing is the supplier 

of the receiver for Solar Tres. The receiver cost estimate is based on actual costs from the Solar 

Two demonstration project, detailed design and material lists, and cost estimates by Boeing. 

• The SunLab cost estimate for near term is based on actual costs for Solar Two and vendor 

quotes obtained during the Central Receiver Utility Studies (1989), which was a 100-MWe 

plant. S&L reviewed the vendors’ quotes and validated that the component costs were within 

typical industry costs. 

• The near-term indirect two-tank thermal storage system is based on cost estimates from detailed 

design drawings and material takeoffs developed by Nextant. The technological risk using the 

two-tank molten-salt storage system is low based on the successful utilization at the Solar Two 

plant. 

• Sargent & Lundy estimated costs for the power block and balance of plant using the EPRI 

SOAPP program. The result was that the capital cost estimated by S&L for the electrical power 

block is less than the SunLab estimate ($563/kWe versus $730/kWe). The capital cost estimated 

by S&L for the balance of plant is higher than the SunLab estimate ($741/kWe versus 

$356/kWe). The SunLab power block cost estimates are based on a 1990 ABB quotation for a 
 

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100-MW steam turbine. The ABB quotation was escalated and scaled-up for the larger sizes. 

The SunLab power block cost estimates are based on dated information and the escalation and 

scale-up factors add to the uncertainty of the data with respect to current pricing. Equipment 

prices in the SOAPP program reflect 2001 actual costs. Since the SOAPP pricing is current, the 

SOAPP-generated costs are more characteristic of current power block costs. 

• SunLab cost estimate included an average contingency of 7.8%, compared to S&L’s estimate of 

10% for direct costs and 15% for cost reductions. 

• The SunLab estimate for engineering, management, and development is 7.8%, whereas S&L 

estimated 15%. 

• SunLab estimated a risk pool factor of 10% for only Solar Tres, whereas S&L estimated that 

risk pool factor of 10% for Solar Tres and 5% for Solar 50. 

Based on the above, the risk of achieving the near-term total investment cost is low to average. 

5.8.3.2 Mid Term (2010) 

The SunLab projected mid-term total investment cost indicates a total cost of $3,103/kWe, a reduction of 

$4,032/kWe from the near-term projected cost of $7,135/kWe, mainly attributable to the following: 

• An increase in the plant size from 15 MW to 100 MW, which reduces the $/kWe cost by virtue 

of the larger kWe size. 

• Reduced cost of solar collection system components from near-term cost of $145/m2

 to $107/m2

as a result of technological advances, scale-up, and production volume. 

• Reduced cost of electric power generation system components from a near-term cost of 

$733/kWe to $400/kWe, primarily as a result of scale-up. 

• Reduction of the receiver system capital cost from the near-term cost of $50/m2 to $27/m2

 as a 

result of technology, scale-up, and volume production. 

There is a mid to high risk of achieving the SunLab projected mid-term total investment cost of $2,876/kWe, 

based on the following: 

• The SunLab projected reduced cost of solar collection system components is based on one 

15-MW plant, six 50-MW plants and six 100-MW plants with an increase from 95 m2

 to 148 m2

for the 100-MW plants. Market expansion of tower technology will require incentives to reach 

the projected level of deployment. 

• The SunLab projected mid-term net annual solar-to-electric efficiency is 16.6%; an 

improvement of 2.9 percentage points from the near-term projected efficiency of 13.7%. The 

solar field size, and thus the solar field cost, is directly proportional to the net annual solar-toelectric efficiency of a tower plant. As previously discussed, there is a high risk of achieving the 

mid-term net annual solar-to-electric efficiency of 17.0%. A mid-term net annual solar-to-
 

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electric efficiency of approximately 15.4% represents a lower risk by limiting the technology 

improvements to currently demonstrated or tested improvements. 

5.8.3.3 Long Term (2020) 

The SunLab projected long-term total investment cost indicates a total cost of $2,272/kWe, a reduction of 

$831/kWe from the mid-term projected cost of $3,103/kWe, mainly attributable to the following: 

• Reduced cost of solar collection system components from near-term cost of $107/m2

 to $75/m2

as a result of technological advances, scale-up, and production volume. 

• An increase in the plant sizes from 100 MW to 220 MW, which reduces the $/kWe cost by 

virtue of the larger kWe size. 

There is a high risk of achieving the SunLab projected long-term total investment cost based on the following: 

• The SunLab projected reduced cost of solar collection system components is based on twentyone 100-MW plants, twenty-two 200-MW plants, and six 220-MW advanced technology plants. 

Market expansion of tower technology will require incentives to reach the projected level of 

deployment. 

• The SunLab projected long-term net annual solar-to-electric efficiency is 18.1%, an 

improvement of 1.5 percentage points from the mid-term projected efficiency of 16.6%. The 

solar field size, and thus the solar field cost, is directly proportional to the net annual solar-toelectric efficiency of a tower plant. As previously discussed, there is a high risk of achieving the 

long-term net annual solar-to-electric efficiency of 18.1%. A long-term net annual solar-toelectric efficiency of 16.2% represents a lower risk by limiting the technology improvements to 

those not requiring advanced technology. 

The long-term risks are similar to the mid-term risks discussed previously. However, the risk is mitigated if the 

tower technology is successfully deployed to the extent that the competitive market prompts research and 

development of technological advances and plant sizes in the 200–220-MW range. 

5.8.4 Operation and Maintenance (O&M) Costs 

The SunLab O&M estimate is based largely on the experience at the KJC Operating Company SEGS plants, 

modified to account for tower technology. The model assumes a stand-alone tower power plant (as opposed to 

the five co-located plants at Kramer Junction) and adjusts cost depending on the size of the solar field and total 

electric generation per year. KJC Operating Company provided proprietary information on the last five years of 

operation. 
 

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The major contributor for O&M costs is staffing. The staffing is a fixed cost, and the SunLab projected 

manpower requirements are reasonable based on data from similar-sized power plants and adjusted for the size 

of the solar field. 

The industry plan keys on thermal storage to obtain a high capacity factor, which reduces the O&M costs 

($/MWh) by obtaining a higher annual MWh generation. The net annual solar-to-electric efficiency has a 

significant impact on the O&M costs. Increased efficiency reduces the size of the solar field and thus reduces 

the number of heliostats. 

5.8.4.1 Near Term (2004) 

The SunLab projected near-term O&M cost of $0.027/kWh is based on an annual solar-to-electric efficiency of 

13.7%, annual capacity factor of 78%, and 16 hours of thermal storage. S&L projected near-term O&M costs of 

$0.033/kWe. As previously indicated, there is a low risk of achieving the near-term net annual solar-to-electric 

efficiency, and the technological risk using the two-tank molten-salt storage system is low. 

The risk of not achieving the SunLab projected near-term O&M costs are low because— 

• The labor staffing and average annual rate are consistent with the SEGS plants; similar sized 

fossil-fired power plants adjusted for O&M of the solar field, and labor rates in the Southwest. 

• The material and service costs were developed based on actual costs for SEGS and adjusted for 

the differences in technology. 

5.8.4.2 Mid Term (2010) 

The SunLab projected near-term O&M cost of $0.006/kWh is based on an annual solar-to-electric efficiency of 

16.6%, annual capacity factor of 73%, and 13 hours of thermal storage. S&L projected near-term O&M costs of 

$0.008/kWe. As previously indicated, there is a low risk of achieving the mid-term net annual solar-to-electric 

efficiency, and the technological risk using the two-tank molten-salt storage system is low. 

The risk of not achieving the SunLab projected mid-term O&M cost is average for the reasons identified 

previously for near term and for the following reasons: 

• The staffing does not increase proportionally as the size of the units increases. The core staff for 

operation and management of the plant will be the same. The increases in staff are for 

maintenance of the solar field and are estimated to be proportional to the size of the field. 

• The plant capacity increases directly as a result of thermal storage. Increasing the size (MWe) 

and utilization (capacity factor) of the power plant incurs very little increase in O&M expenses 
 

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($/yr). This is because the quantity and complexity of the equipment remain constant and 

staffing remains fairly constant. Our review of conventional fossil plant shows this ‘economy of 

scale’ in staffing for increases in plant size. 

The S&L projected near-term O&M cost is $0.006/kWh. The differences are as follows: 

• Sargent & Lundy scaled-up the cost of contracts associated with increases in field size. 

• Sargent & Lundy scaled-up the cost of fuel and maintenance of vehicles to account for increase 

in field size. 

• Sargent & Lundy assumed that the average burden rate would not decrease. 

5.8.4.3 Long Term (2020) 

The SunLab projected long-term O&M cost of $0.003/kWh is based on an annual solar-to-electric efficiency of 

18.1%, and annual capacity factor of 73%, and 12.7 hours of thermal storage. S&L projected long-term O&M 

costs of $0.006/kWh. As previously indicated, there is a high risk of achieving the long-term net annual solar-toelectric efficiency as a result of the advanced turbine and heliostat. 

The risk of not achieving the S&L projected long-term O&M cost (e.g., no advanced turbine and heliostats) is 

average for the reasons identified previously for near- and mid-term. 

5.9 COST SENSITIVITIES 

In this section, variations in the inputs for levelized energy costs are shown to illustrate the sensitivity of energy 

calculated cost to variations. The sensitivity analysis revealed that the impact on the LEC of the various 

scenarios is basically the same for both trough and tower technologies. The base case for the sensitivity analysis 

for the tower in 2020 is 200 MW with a capital cost of $3,591 per kW and annual O&M costs of $9,132 is 

shown in Table 5-35. The trough base case is shown for reference. 

Table 5-35 — S&L Base Case for the Year 2020 

 Trough Tower 

Year 2020 2020 

Capacity, MWe 400 200 

Capacity Factor, 56.2% 72.9% 

Capital Cost, $/kW $3,220 $3,591 

Annual O&M Cost, $k $14,129 $9,132 
 

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 Trough Tower 

LEC, $/kWh $0.0621 $0.0547 

Economic Life 30 yrs 

General Inflation 2.5 % 

Equity Rate of Return 14% 

Cost of Construction 7% 

Construction Duration 1 yr. 

Investment Tax Credit 10% 

Taxes 40.2% 

Depreciable Life 5 yrs. 

IRR 14% 

DSCR 1.35 

5.9.1 Depreciable Life 

The tax depreciation allowances for renewable energy provide a favorable 5-year depreciable life. The Modified 

Accelerated Cost Recovery System (MACRS) defined depreciation schedules for 5, 10, and 15 years. If the tax 

laws are changed or reinterpreted the variation in LEC in 2020 is shown below. 

Table 5-36 — Effect of Depreciable Life on Levelized Energy Cost 

Depreciable Life LEC in 2020 

(years) $/kWh % difference 

5 $0.0547 Base Case 

10 $0.0580 6.0% 

15 $0.0614 12.3% 

5.9.2 Investment Tax Credits 

The investment tax credits have a major impact on the economic feasibility of a renewable energy power plant. 

Current tax law allows a 10% investment tax credit. Future tax laws may allow a larger tax credit such as the 

15% before 1985 or disallow investment tax credits. Tax credits from 0% to 15% and Energy Production Tax 

Credit (PTC) result in the LEC in 2020 to vary as shown below. 
 

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Table 5-37 — Effect of Investment Tax Credits on Levelized Energy Cost 

Tax Credits LEC in 2020 

(%) $/kWh % difference 

0% $0.0590 7.8% 

5% $0.0568 3.9% 

10% $0.0547 Base Case 

15% $0.0526 -3.9% 

PTC of 1.8¢/kWh $0.0410 -30.5% 

5.9.3 Corporate Tax Rate 

Corporate tax rates are currently at 35%. State taxes vary depending on the plant location but are assumed to be 

8%. The composite base tax rate is 43%. The present Government Administration is currently considering 

reductions in the corporate tax rate but the rate can vary depending on the economic conditions at the time. The 

impact on LEC in 2020 from changes in the tax rate is below. 

Table 5-38 — Effect of Corporate Tax Rates on Levelized Energy Cost 

Corporate Tax Rates LEC in 2020 

Federal State Composite $/kWh % Difference 

30% 8% 38% $0.0557 1.9% 

35% 8% 43% $0.0547 Base Case 

38% 10% 48% $0.0538 -1.7% 

5.9.4 Inflation 

Inflation assumptions does not affect the real dollar levelized energy cost. Increases and decreases in the 

inflation rate impact the LEC in 2020 as shown below. 
 

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Table 5-39 — Effect of Inflation on Levelized Energy Cost 

Inflation Rate LEC in 2020 

Rate IRR $/kWh % difference 

1.5% 12.9% $0.0542 -1.0% 

2.5% 14.0% $0.0547 Base Case 

3.5% 15.1% $0.0553 1.0% 

5.9.5 Cost of Capital 

Cost of capital for the base case is such that there is an internal rate of return (IRR) of 14%. The impact on LEC 

in 2020 from a change in the cost of capital is shown below. 

Table 5-40 — Effect of Cost of Capital on Levelized Energy Cost 

Cost of Capital LEC in 2020 

IRR $/kWh % Difference 

13% $0.0508 -7.1% 

14% $0.0547 Base Case 

15% $0.0588 7.6% 

5.9.6 Construction Duration 

The plant construction period for the base case is one year based on experience at the SEGS plants. The amount 

of interest during construction (IDC) is included in the LEC. The impact on LEC in 2020 for construction of two 

and three years is shown below. 

Table 5-41 — Effect of Construction Duration on Levelized Energy Cost 

Construction LEC in 2020 

Period 

(yr) $/kWh % Difference 

1 $0.0547 Base Case 

2 $0.0577 5.4% 

3 $0.0608 11.1% 
 

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5.9.7 Capital Cost 

The variation for increases in capital costs is shown below. 

Table 5-42 — Effect of Capital Cost Increases on Levelized Energy Cost 

Increase in Capital LEC in 2020 

Cost 

(%) $/kWh % difference 

0% $0.0547 Base Case 

10% $0.0595 8.7% 

20% $0.0642 17.4% 

5.9.8 Annual O&M Cost 

The variation for increases in annual O&M costs is shown below. 

Table 5-43 — Effect of O&M Cost Increase on Levelized Energy Cost 

Increase in Annual LEC in 2020 

O&M Cost 

(%) $/kWh % difference 

0% $0.0547 Base Case 

10% $0.0554 1.3% 

20% $0.0561 2.6% 

5.9.9 Ownership 

The S&L base case considers ownership by an Independent Power Producer (IPP). An investment by 

developer/owners and financial institutions would require an IRR of at least 14%. It is more likely that the first 

several power plants will be owned by utilities. Utilities require a lower IRR and would be more receptive to 

renewable initiatives. As the industry matures (e.g., capital cost declines and the technology is proven), the IPPs 

would become involved. There is the potential for private ownership in the early plants, but it would most likely 

be from manufacturers who could offset the lower IRR with increased sales for solar equipment. The impact of 

ownership on LEC for 2020 is shown below. 
 

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Table 5-44 — Effect of Ownership on Levelized Energy Cost 

 IPP Utility 

Ownership Muni 

IRR, % 14% 11.5% 0% 

Leverage 60/40 50/50 100/0 

Cost of Debt 5% 7% 5% 

DSCR 1.35 1.74 1.0 

LEC, $/kWh $0.0547 $0.0526 $0.0406 

% difference Base Case -3.8% -25.7% 
Appendix A 

List of Documents 
 

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A. LIST OF DOCUMENTS 

This list contains both the documents cited in footnotes in the text and other documents reviewed for the report. 

Advanced Thermal Systems, Inc., 1996. Solmat Phase 1 Final Review, Model H-150 Heliostat Design, May 15, 

1996 

AeroVironment, Inc., 1995. “Fugitive Emissions Testing - Final Report,” for KJC Operating Company, 

Monrovia, California, January 1995. 

Akhil, A.A., S.K. Swaminathan, and R.K. Sen, 1997. Cost Analysis of Energy Storage for Electric Utility 

Applications, Sandia National Laboratories: February 1997. Report SAND97-0443. 

Alpert, D.J., and G.J. Kolb, 1988. Performance of the Solar One Power Plant as Simulated by the SOLERGY 

Computer Code, Sandia National Laboratories, Albuquerque, NM: 1988. Report SAND88-0321. 

Anderson, 1998. The Economics of Photovoltaic Technologies. 

Anderson, D. and K. Ahmed, 1995. The Case for the Solar Energy Investments, World Bank Technical Paper 

Number 279 - Energy Series, World Bank, Washington D.C.: February 1995. ISBN 0-8213-3196-5. 

Arthur D. Little, Inc., 2001. “Heliostat Cost Review,” June 

ASME, 2001. “EUROTROUGH Design Issues And Prototype Testing At PSA,” Proceedings of ASME 

International Solar Energy Conference - Forum 2001, Solar Energy. 

Bechtel National Inc., 1995. “Central Receiver Commercialization Plan,” for the California Energy 

Commission: June 1995. Report 01-0444-35-3027-2777. 

Boeing, Roadmap: Power Tower Receiver System (not publicly available). 

Boer, Karl W., ed., 1997. Advances in Solar Energy - An Annual Review of Research and Development, 

Volume 11, Chapter 1, article by Mancini, T.R., M.R. Prairie, and G.J. Kolb, American Solar Energy Society, 

Inc., Boulder, CO, 1997. ISBN 0-89553-254-9. 
 

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Central Receiver Utility Studies, 1989. A series of reports prepared by Pacific Gas and Electric (and its principal 

subcontractor, Bechtel National, Inc.) and Arizona Public Service (and its principal subcontractor, Black and 

Veatch Engineers-Constructors) cofunded by the U.S. Department of Energy, the Electric Power Research 

Institute, and the utilities themselves. 

Chiang, C. J., 1987. SUNBURN: A Computer Code for Evaluating the Economic Viability of Hybrid Solar 

Central Receiver Electric Power Plants, Sandia National Laboratories, Albuquerque, NM: June 1987. Report 

SAND86-2165. 

Christiansson, L., 1995. Diffusion and Learning Curves of Renewable Energy Technologies. Working Paper 

WP-95-126. International Institute for Applied Systems Analysis. Laxenburg, Austria. [Note: Christiansson is 

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Cohen, G., and S. Frier, 1997. “Ten Years of Solar Power Plant Operation in the Mojave Desert,” Proceedings 

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on Concentrated Solar Power and Chemical Energy Technologies, Zurich, Sep 4-6, 2002. 

Dudley, V., G. Kolb, A. R. Mahoney, T. Mancini, C. Matthews, M. Sloan, and D. Kearney, 1994. Test Results: 

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Duke Solar, 2000. ‘‘Task 2 Report: New Space-Frame Parabolic Trough Structure,’’ Prepared for NREL by 

Duke Solar, Raleigh, NC. 

Durstewitz, M., 1999. Using information of Germany’s “250 MW Wind” Programme for the construction of 

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distributed, and supported by EPRI. 
 

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Energy Information Administration, 2002. “Annual Energy Outlook 2002 with Projections to 2020,” U.S. 

Department of Energy. 

Energy Information Administration, 2002. “International Energy Outlook 2002,” U.S. Department of Energy. 

Enermodal Engineering Limited, 1999. “Cost Reduction Study for Solar Thermal Power Plants,” prepared for 

the World Bank. 

Falcone, P.K., 1986. A Handbook for Solar Central Receiver Design, Sandia National Laboratories, Livermore, 

CA: December, 1986. Report SAND86-8009. 

Flachglas Solartechnik GmbH, 1994. “Assessment of Solar Thermal Trough Power Plant Technology and Its 

Transferability to the Mediterranean Region - Final Report,” for European Commission Directorate General I 

External Economic Relations, and Centre de Developpement des Energies Renouvelables and Grupo Endesa, 

Cologne, Germany: June 1994. 

Gee, Cohen, and Winston, 2002. “A Non-Imaging Receiver for Parabolic Trough Concentrating Collectors,” 

Proceedings of Solar 2002. 

Gorman, D., 1993. “Heliostat Costs at Reduced Production Volumes - Report to Sandia National Laboratories,” 

Advanced Thermal Systems: 

Hubbard, H., et al., 2000. Renewable Power Pathways; A Review of the U.S. Department of Energy’s 

Renewable Energy Programs, National Research Council, National Academy Press, 2000. 

Humphreys, K.K., and L.M. English, 1993. “Project and Cost Engineers’ Handbook,” Third Edition, AACE 

International, Marcel Dekker, Inc., New York, 1993. 

Humphreys, K.K., and L.M. English, Project & Cost Engineer’s Handbook, AACE International. 

IEA, 2000. Experience Curves for Energy Technology Policy. International Energy Agency, Paris, France. 

(ISBN 92-64-17650-0). 

Integrated Solar Combined Cycle Systems (ISCCS) 1996. Using Parabolic Trough Technology, Phase 1B 

Technical and Financial Review, Spencer Management Associates, Diablo, CA: March 1996, draft. 
 

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International Energy Agency, 2001a. “2000 Energy Technologies and Systems: A View to 2050,” PCADT 

1997, cited in Anderson 1998 as cited in the UK Project on Resource Productivity and Renewable Resource, 

Energy Technologies and Systems: A View to 2050, Part 1. Technical and Economic Potential of Generating 

Technologies, Draft May 4, 2001. 

International Energy Agency, 2001b. “2000, Experience Curves for Energy Policy Assessment” as cited in the 

UK Project on Resource Productivity and Renewable Resource, Energy Technologies and Systems: A View to 

2050, Part 1. Technical and Economic Potential of Generating Technologies, Draft May 4, 2001. 

IST, 2001, “Collector Development,” Presentation at Solar Forum 2001, Solar Energy. 

Kearney, D., 2001a. Engineering Evaluation of a Molten Salt HTF in a Parabolic Trough Solar Field, Task 6 

Report, Final System Performance and Cost Comparisons, August 20, 2001. 

Kearney, D., 2001b. “Engineering Evaluation of a Molten Salt HTF in a Parabolic Trough Solar Field,” Task 7 

Report, Recommendations on Development Needs, September 15, 2001. 

Kearney, D., and C. Miller, 1988. Solar Electric Generating System VI - Technical Evaluation of Project 

Feasibility, LUZ Partnership Management, Inc.: January 15, 1988. 

KJC Operating Company, 1994, “O&M Cost Reduction in Solar Thermal Electric Power Plants - Interim Report 

on Project Status,” for Sandia National Laboratories: September 1, 1994. 

KJCOC, 1999. “O&M Cost Reduction Report,” June. 

Klenow, “Learning Curves and the Cyclical Behavior of Manufacturing Industries.” 

Kobos, P., 2002. “The Implications of Renewable Energy Research and Development: Policy Scenario Analysis 

with Experience and Learning Effects.” Ph.D. thesis, Rensselaer Polytechnic Institute. (Forthcoming). 

Kolb, G. J., 1995. “Evaluation of Power Production from the Solar Electric Generating Systems at Kramer 

Junction: 1988 to 1993”, Solar Engineering - 1995, Proceedings of the ASME Solar Energy Conference, Maui, 

HI (March 19-24, 1995). 
 

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Kolb, G. J., 1996. “Economic Evaluation of Solar-Only and Hybrid Power Towers Using Molten Salt 

Technology”, Proceedings of the 8th International Symposium on Solar Thermal Concentrating Technologies, 

Cologne, Germany (October 6-11, 1996). Accepted for publication in the journal Solar Energy. 

Kolb, G., J. Chavez, and W. Meinecke, 1993. “Second Generation Central Receiver Technologies: A Status 

Report,” M. Becker, and P. Klimas, eds., Verlag C.F. Muller Karlsruhe, DLR, and Sandia National Laboratories: 

1993. Report ISBN 3-7880-7482-5. 

Kouvaritakis, N., Soria, A., and Isoard, S., 2000. “Modeling Energy Technology Dynamics: Methodology for 

Adaptive Expectations Models with Learning by Doing and Learning by Searching.” Int. J. Global Energy 

Issues, Vol. 14, Nos. 1-4, pp. 104-115. 

Kribus, A., P. Doron, R. Rubin, R. Reuven, E. Taragan, S. Duchan, and J. Karni, 2001. “Performance of the 

Directly Illuminated Annular Pressurized Receiver (DIAPR) Operating at 20 Bar and 1200 C,” 123:10-17, 

Journal of Solar Energy Engineering. 

Lotker, M., 1991. “Barriers to Commercialization of Large-Scale Solar Electricity: Lessons Learned from the 

LUZ Experience,” Sandia National Laboratories, Albuquerque, New Mexico: Report SAND91-7014. 

LUZ International Limited, 1990. “Solar Electric Generating System IX Technical Description,” LUZ 

International Limited. 

Mackay, R.M. and S.D. Probert, 1998. “Likely Market-Penetration of Renewable-energy Technologies,” 

Applied Energy. Vol. 59, No. 1. pp. 1-38. 

Marion, W., and S. Wilcox, 1994. “Solar Radiation Data Manual for Flat-Plate and Concentrating Collectors,” 

National Renewable Energy Laboratory, Golden, Colorado: April 1994. Report NREL/TP-463-5607. 

McDonald, A. and L. Schrattenholzer, 2001. “Learning Rates for Energy Technologies.” Energy Policy, Vol. 

29, Issue 4, pp. 255-261, March. 

Meinecke, W., and M. Bohn, 1995. “Solar Energy Concentrating Systems: Applications and Technologies,” 

edited by M. Becker, and B. Gupta, Muller Verlag, Heidelberg, Germany. 
 

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Moller, S., R. Buck, R. Tamme, M. Epstein, D. Liebermann, M. Meri, U. Fisher, A. Rotstein, and C. Sugarman, 

2002. “Solar Production of Syngas for Electricity Generation: SOLASYS Project Test-Phase,” 11th 

SolarPACES International Symposium on Concentrated Solar Power and Chemical Energy Technologies, 

Zurich, Sep 4-6, 2002. 

Morales, A., and Ajona, J. I., 1998. ‘‘Durability, Performance and Scalability of Sol-Gel Front Surface Mirrors 

and Selective Absorbers,’’ Proc. of 9th International Symposium on Solar Thermal Concentrating Technologies. 

Morse, Frederick H., 2000. “The Commercial Path Forward for Concentrating Solar Power Technologies: A 

Review of Existing Treatments of Current and Future Markets,” Morse Associates, Inc., Washington D.C., 

December 13, 2000. 

Muller, M., 1994. “Direct Solar Steam in Parabolic Trough Collectors (DISS), Plataforma Solar de Almeria 

(PSA),” CIEMAT and DLR, May 1994, ISBN 84-605-1479-X. 

National Construction Estimator, 49th Edition, erected structural steel for California. 

National Research Council (NRC) Committee for the Review of a Technology Assessment of Solar Power 

Energy Systems, 2002. “Critique of the Sargent & Lundy Assessment of Cost and Performance Forecasts for 

Concentrating Solar Power,” October 12, 2002 [Note the review was performed on Draft 3 of the Sargent & 

Lundy Report, SL-5641, dated October 2002] 

Neij, Lena, 1997. “Use of Experience Curves to Analyze the Prospects for Diffusion and Adoption of 

Renewable Energy Technology.” 

Neij, Lena, 1999. “Cost dynamics of wind power.” Energy. Vol. 24, pp. 375-389. 

Nextant Inc., 2001. USA Trough Initiative: Nitrate Salt Heat Transport Fluid Rankine Cycle, Steam Generator, 

and Thermal Storage Analysis, January 19, 2001. 

O&M Cost Reduction in Solar Thermal Electric Power Plants - 2nd Interim Report on Project Status, KJC 

Operating Company, for Sandia National Laboratories: July 1, 1996. 
 

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Pacheco, J.E. (ed), G.J. Kolb, H.E. Reilly, S.K. Showalter, S.H. Goods, R.W. Bradshaw, D.B. Dawson, S.A. 

Jones, M.J. Hale, R.L. Gilbert, M.R. Prairie, and P. Jacobs, 2002. “Final Test and Evaluation Results from the 

Solar Two Project,” SAND2002-0120, Sandia National Laboratories, Albuquerque, NM. 

Pacific Gas & Electric Company, 1988. “Solar Central Receiver Technology Advancement for Electric Utility 

Application, Phase 1 Topical Report,” San Francisco, CA: September 1988. Report 007.2-88.2. 

PCADT 1997. “US President’s Committee of Advisors on Science and Technology report the President on 

Federal Energy Research and Development Challenges for the 21st Century.” 

Peerless-Winsmith, Inc, 1989. “Development of a Low-Cost Drive Tracking Mechanism for Solar Heliostats or 

PV Arrays - Final Report,” for Sandia National Laboratories: February 1989. Report 90-5753. 

Peerless-Winsmith, Inc., 1996. “Results of Dual Axis Solar Drive DFMA Workshop,” Contract ACG-5-15209-

01, January 26, 1996. 

Peerless-Winsmith, Inc., 1999. “Enhanced Azimuth Solar Drive Project Summary Report,” for Sandia National 

Laboratories, Contract Number BF-0031, October 1999. 

Pilkington International, 1999. “Solar Steam System Investment Cost,” prepared for Midwest Research Institute, 

December 1999. 

Pilkington Solar International, 1996. “Status Report on Solar Thermal Power Plants,” Report ISBN 3-9804901-

0-6. 

Price, H., E. Lüpfert, D. Kearney, E. Zarza, G. Cohen, R. Gee, and R. Mahoney, 2002. “Advances in Parabolic 

Trough Solar Power Technology,” Journal of Solar Energy Engineering, May 2002. 

Price, H., and Kearney, D., 1999. “Parabolic-Trough Technology Roadmap: A Pathway for Sustained 

Commercial Development and Deployment of Parabolic-Trough Technology,” NREL/TP-550-24748, NREL, 

Golden, Colorado. 

Radosevich, L., 1988. “Final Report on the Power Production Phase of the 10 MWe Solar Thermal Central 

Receiver Power Plant,” SAND87-8022, Sandia National Laboratories, Livermore, CA, March 1988. 
 

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Regional Economic Research, Inc., 1991. “Technical Potential of Alternative Technologies - Final Report,” for 

California Energy Commission, Contract No. 500-89-001, San Diego, CA: December 2, 1991. 

Reilly, H.E., and G.J. Kolb, 2001. “An Evaluation of Molten-Salt Power Towers Including the Results of the 

Solar Two Project,” SAND2001-3674, Sandia National Laboratories. 

San Vicente, G., Morales, A., and Gutiérrez, M. T., 2001. “Preparation and Characterization of Sol-Gel TiO 2 

Antireflective Coatings for Silicon.” 

Sandia National Laboratories, 2001. “Development of a Molten-Salt Thermocline Thermal Storage System for 

Parabolic Trough Plants,” Proceeding of Solar Forum 2001. 

Science Applications International Corporation, 1996. “Heliostat Cost Study for SOLMAT Program,” for 

National Renewable Energy Laboratory, Golden, CO. 

Smith, D.C., and J.M. Chavez, A, 1988. “Final Report on the Phase 1 Testing of a Molten-Salt Cavity 

Receiver,” Sandia National Laboratories, Albuquerque, NM: 1988. Report SAND87-2290. 

Solar Kinetics, Inc., 1996. SolMatT, Mirror Module Assembly Plan and Cost Estimate. 

Stoddard, M.C., et al., 1987. “SOLERGY - A Computer Code for Calculating the Annual Energy from Central 

Receiver Power Plants,” Sandia National Laboratories, Livermore, California: May 1987. Report SAND86-

8060. 

Strachan, J.W., and R.M. Houser, 1993. “Testing and Evaluation of Large-Area Heliostats for Solar Thermal 

Applications,” Sandia National Laboratories, Albuquerque, NM: February 1993. Report SAND92-1381. 

Sugarman, C., A. Ring, R. Buck, R. Uhlig, M. Beuter, M. J. Marcos, and V. Fernandez, 2002. “Solar-Hybrid 

Gas Turbine Power System,” 11th SolarPACES International Symposium on Concentrated Solar Power and 

Chemical Energy Technologies, Zurich, Sep 4-6, 2002. 

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Sutton, W.F., 1989. Prices of Drives at Different Production Volumes - Report to Sandia National Labs, 

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SolarPACES International Symposium on Concentrated Solar Power and Chemical Energy Technologies, 

Zurich, Sep 4-6, 2002. 

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High-Temperature Solar Plants, Int. J. Hydrogen Energy, 23(4):239-245, 1998. 

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Appendix B 

Methodology 
 

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B. METHODOLOGY 

B.1 SUMMARY 

The study was carried out as follows. The methodology Sargent used to carry out the study is described in this 

section. 

• Sargent & Lundy collected data and analyses of the current status of trough and tower 

technologies. 

• Sargent & Lundy reviewed the SunLab Cost Models, industry data, and relevant studies 

regarding capital cost projections for near-term deployment, cost projections for technology 

improvements, and plant scale-up through 2020. 

• Sargent & Lundy assessed the level of cost reductions and performance improvements, based on 

our experience, that are likely to be achieved. 

• Sargent & Lundy developed a financial model to calculate LEC based on project financing 

assumptions, investment costs, and operations and maintenance costs. 

B.2 COLLECTION OF DATA 

Sargent & Lundy received relevant documents from NREL and Sandia Laboratory for our independent review. 

During the review process, additional documents were gathered from industry sources, the Internet, and our 

internal S&L library. The list of documents is included in Appendix A. Our objective was to review relevant 

documents, both pro and con, to make our assessment. For example, the Teagan report was critical of the 

methods used in previous reports to predict cost reductions, in particular learning curves (Teagan 2001). 

B.3 REVIEW OF SUNLAB COST MODEL 

Sargent & Lundy reviewed the SunLab cost model and determined that the SunLab cost model approach and 

methodology is reasonable. The SunLab cost model was developed based on industry cost data and engineering 

evaluation. 

The following industry cost data were used for the cost models: 

• Actual cost data from construction of the SEGS plants and costs of equipment being supplied 

for O&M were used (e.g., HCEs). 

• Actual cost data from Solar Two were used as the “starting point” and adjusted for present 

prices. The steam generator cost estimate was based on four vendors’ designs and quotes for 
 

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100 MWe (SAND93-7083) and actual costs from Solar Two. The scaling factor was calculated 

and used to estimate other plant sizes. 

An example of engineering evaluation is shown in Table B-1. The cost estimate for the tower height is based on 

an engineering formula and vendor cost information provided in the Central Receiver Utility Studies (1989). 

Table B-1 — Cost Estimate for the Receiver Tower Based on the 

Central Receiver Utility Studies 

Receiver Rating 

(MWt) 

Tower Height 

(m) 

Installed Cost 

(000’s) 

2001 Cost 

(000’s) Source 

100 75.8 $1,160 $1,600 Central Receiver Utility Studies 

195 94.7 $1,550 $2,200 Central Receiver Utility Studies 

343 140.0 $3,010 $4,200 Central Receiver Utility Studies 

390 149.3 $3,410 $4,800 Central Receiver Utility Studies 

468 185.0 $5,290 $7,500 Central Receiver Utility Studies 

780 190.0 $5,600 $7,900 Central Receiver Utility Studies 

936 247.5 $10,020 $14,100 Central Receiver Utility Studies 

Notes: 

Tower height, m = 29.1 + 0.51129589 * (Rating, MWt) - 0.0088703442 * (Rating, MWt)1.5 + 32,801.719 * (Rating, MWt)-2

Tower cost = 600,000 + 17.72 * (Tower height, m)2.392 Crane cost = $500,000 

Sargent & Lundy evaluated the assumptions in the SunLab cost model: efficiency improvements, capital cost for 

the near-term deployment, and cost reductions through 2020. The review of cost reductions included technology 

improvements, increase in the size of the plant (scale-up), and production volume. Scale-up and production 

volume is discussed in more detail in this section. The cost model was compared to S&L’s internal cost 

database, where appropriate (e.g., turbine, equipment, and commodities such as steel prices). 

Differences between the SunLab and S&L cost estimates were a result of different assumptions. For example, 

S&L increased the duration between the deployment of the next generation plant from 1 year to 2 years to 

account for lessons learned and an adequate time for steady-state operation. The differences in assumptions are 

identified in the main body of the report. 
 

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B.4 TECHNICAL IMPROVEMENTS 

Projected technical improvements that reduce costs by improving plant efficiency or by reducing initial capital 

costs were evaluated with respect to probability of the improvement and the estimated magnitude of cost 

reduction. The projected technical improvements investigated were those identified in the SunLab models, and 

the probability and magnitude of cost reductions are based on data from DOE, NREL, Sandia, and members of 

the CSP industry, including technology assessments and supporting studies for troughs and towers. 

B.5 ECONOMY OF SCALE 

Economy of scale was used, as appropriate; to estimate or evaluate cost estimates for components. Scaling 

factors were used to estimate the cost of a new size or capacity from the known cost for a different size or 

capacity. The Association for the Advancement of Cost Engineering (AACE) defines this method of estimating 

as plant component ratios (Humphreys and English 1993). The relationship is based on the following formula: 

 C2 = C1 (S2/S1) Sf 

 Where: 

 C2 = desired cost of equipment at size (or capacity) of S2 

 C1 = desired cost of equipment at size (or capacity) of S1 

 Sf = scaling factor 

Example: If the cost of a 95-m2

 heliostat is $13,654 ($143.73 per m2), then the cost of a 148-m2 heliostat is 

estimated at $19,466 ($131.53 per m2

) based on a scaling factor of 0.80. 

 C2 = $13,654 (148/95) 0.8 = $19,466 

B.6 VOLUME PRODUCTION (VOLUME AND LEARNING CURVE) 

Experience curves define how unit costs decrease with cumulative production. The specific characteristics of the 

experience curve are that the cost declines by a constant percentage with each doubling of the total number of 

units produced. The formula is as follows: 

 CCUM = C0 x CUMb 

 Where: 

 CCUM = the cost per unit as a function of output 

 C0 = the cost of the first unit produced 
 

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 CUM = the cumulative production over time 

 b = the experience index 

The cost reduction is (1-2b

) for each doubling of cumulative production, where the value (2b) is called the 

progress ratio (PR). The progress ratio is used to express the progress of cost reductions for different 

technologies. 

The formula is simplified for use as follows: 

 PR = (C2/C1) 1/(no. of doublings) 

 Where: 

 Number of doublings = log 2 (Q2/Q1) 

 C1 = cost of initial unit produced 

 Q1 = production quantity for the initial unit cost 

 C2 = desired cost of unit produced 

 Q2 = cumulative production quantity for desired unit cost 

 PR = Progress Ratio 

Example: The cost of a 148-m2

 heliostat is $160 per m2 based on production of 227,000 m2. The cost estimate 

based on a production of 56,000,000 m2

 is $109. The progress ratio is 0.95. 

 Number of doublings = log 2 (56,000,000/227,000) = 7.9 

 PR = ($109/$160) (1/7.9) = 0.95 

Many of the previous studies that assessed the cost reduction potential for tower and trough technologies based 

their findings on experience curves, including the World Bank (1999). As pointed out in the Tegan report 

(2001), “the review documents do not make a strong case that the cost of technologies (particularly the solar 

field) can be reduced to a point that they approach economic viability....” His primary example was the 

collector field: “the ‘learning curve’ arguments put forth lack sufficient backup to be credible given the fact that 

the materials of construction are already commodities and the fabrication techniques, for the most part 

standard.” He also stated that he believed cost reductions are likely “via a combination of ‘learning curve’ and 

technology refinement.” In response, S&L performed a thorough review of the cost reduction potential for 

heliostats. Heliostat cost reduction potential is more difficult to estimate since it is not based on actual costs with 

significant volume produced, whereas trough costs and the cost reductions are known based on actual SEGS 
 

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construction data and recent costs for replacement during operations and maintenance. Our detailed evaluation 

of cost reduction potential for heliostats is provided in Appendix E.5. 

We reviewed the engineering assumptions, industry data, and studies that constitute the basis of the SunLab 

Cost Model for the major cost drivers. The review was not based on just applying an experience curve, but an 

engineering review. We reviewed the assumptions and made adjustments as deemed appropriate based on our 

experience. We calculated the progress ratio and compared it to actual experience curves from other industries. 

The calculated progress ratio value was then used to determine estimated costs for a range of deployments. 

For example, cost reductions for 148-m2

 heliostats due to a volume production of 100 million m2 were 

calculated to be 0.961 by SunLab and 0.971 by S&L (see Table E-18). Each cost component was reviewed 

based on reviewing the initial cost estimate and final cost estimate and then calculating the progress ratio. One 

of the cost components is fabrication: initial fabrication costs were estimated based on the productivity (hr/unit) 

and labor rate ($/hr) for performing specific tasks (fabricating the mirror support structure, mirror modules, 

controls, and drives), and then final fabrication costs were estimated based on productivity improvements from 

volume production (see Section E.5.5). The calculated progress ratio was 0.96. 

The range of progress ratios used for the comparison by S&L is between 0.85 and 0.96. Various studies on 

learning curves from actual data suggest that a progress ratio of 0.82 has been observed for photovoltaics (PV) 

and 0.82 for development of wind energy during early deployment (1980 to 1995). The higher end of the range 

is from the Enermodal study for the World Bank (1999), which identified a PV of 0.96 and the Wind Learning 

Rates compiled by Kobos (Table B-2) for development of wind plants. The Enermodal study projected a 

reasonable experience curve for trough and tower technologies to be between 0.85 to 0.92. 

Table B-2 — Wind Learning Rates 

Country 

or Region 

Time 

Period 

Est. Learning 

Rate (%) 

Performance Metric 

(dependent variable) 

Experience Metric 

(independent variable) R2* 

Reference or Data 

Source 

OECD 1981–

1995 

17 investment cost ($/kW) cumulative capacity 

(MW) 

0.94 Kouvaritakis, Soria, 

and Isoard (2000) 

USA 1981–

1996 

14 investment cost ($/kW) cumulative capacity 

(MW) 

0.95 Mackay and 

Probert (1998) 

USA 1981–

1987 

16 investment price ($/kW) cumulative “production” 

(MW) 

n.a. Christiansson 

(1995) 

Denmark 1982–

1997 

4 investment price ($/kW) cumulative capacity 

(MW) 

n.a. Wene (2000), Neij 

(1999) ** 
 

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Country 

or Region 

Time 

Period 

Est. Learning 

Rate (%) 

Performance Metric 

(dependent variable) 

Experience Metric 

(independent variable) R2* 

Reference or Data 

Source 

Denmark 1982–

1997 

8 investment price ($/kW) cumulative capacity 

(MW) 

n.a. Neij (1999) *** 

Germany 1990–

1998 

8 investment price ($/kW) cumulative capacity 

(MW) 

0.95 Durstewitz (1999) 

Note: Adapted from Kobos (2002) 

* As described in McDonald and Schrattenholzer (2001), comparing R2

 values between sources must be done with 

caution (e.g., different sources use differently sized data sets; therefore, the respective R2 is relative to that data set). 

** The Wene (2000) reference adapts results from Neij (1999). 

*** The Neij (1999) results include all Danish-produced wind turbines. 

B.7 OPERATION AND MAINTENANCE COSTS 

The O&M cost projections provided in the SunLab cost model are based on actual data from Kramer Junction 

with projections for increased plant size and improvements in operation and maintenance. Kramer Junction 

provides a dependable basis for costs associated for near-term deployment. 

Sargent & Lundy reviewed the SunLab cost model against interviews and actual data provided to us during our 

site visit and our knowledge and internal database information of O&M costs for electric power plants. We 

reviewed the SunLab assumptions and made adjustments as appropriate based on our experience and 

information provided by Kramer Junction. 

B.8 FINANCIAL MODELING 

B.1.1 Analysis Methodology 

The financial model used for developing generating costs is a spreadsheet pro forma financial model of the type 

used in competitive industry to support power project planning and financing. S&L regularly reviews such 

models as part of our due diligence practice, working with lenders and investors in project financing. In some 

cases we also support project developers by writing and maintaining such models for them. 

The main analysis engine is a standard income statement that includes calculations of energy production, 

revenues, operation and maintenance expenses, fuel expenses, depreciation, insurance, property taxes, interest, 

investment tax credit, and income tax. The investment tax credit for solar technologies is represented. Once 

after-tax income was determined in the income statement, depreciation was added back and payback of debt 

principal was subtracted to obtain cash available for dividends. The dividend stream and equity investment into 
 

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the project was combined to compute the equity internal rate of return for the project. All evaluations were done 

on a lifetime $/MWh evaluated cost basis, covering 30 years of service. 

All costs are expressed in constant 2002-dollar terms. Financing rates (return or equity and interest rates) were 

adjusted to remove the inflation premium rates. 

Revenues were set to cover investment-related costs and fixed operation and maintenance costs, including 

property taxes. Revenues covering fixed operation and maintenance costs were treated as pass-through costs, 

with revenue assumed to exactly offset expenses. Investment costs were covered by a level $/kW/year capacity 

payment. 

B.1.2 Cost of Capital 

The financial analyses considered project financing, where the project is set up as a separate project company 

that is financed using borrowed funds and equity investments by the project company’s owners. Costs of debt 

and costs of equity were developed from review of current market rates, resulting in the following assumptions 

shown in Table B-3: 

Table B-3 — Costs of Debt and Equity 

Current Dollars Constant Dollars

Return on equity 14.0% 11.5% 

Permanent debt interest rate 8.5% 6.0% 

Construction debt interest 7.0% 4.5% 

The Project Company is subject to corporate income tax, assumed to be 35% at the federal level and 8% at the 

state level. 

Although a high degree of financial leverage normally is used in project financing, favorable economics for 

solar plants correspond to lower degrees of leverage than with conventional power projects because of the 10% 

investment tax credit and favorable tax depreciation allowances for solar units (5-year MACRS). In these 

analyses, the financial leverage and revenue requirement to cover investment-related costs have been set to 

achieve the target return on equity and target debt service coverage ratio. The target debt service coverage ratio 

is 1.35 for all cases. Debt is paid off using a mortgage-style amortization over 20 years. Annual insurance 

expense was estimated to be 0.5% of initial cost, escalating. Annual property taxes were estimated to be 0.5% of 
 

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initial investment, constant over the evaluation period. The evaluation period covers 30 years. Investment costs 

in the pro forma were adjusted for construction period financing costs by assuming that spending on average 

will be two years before the facility’s initial commercial service. The cost of capital for this interest during 

construction adjustment was assumed to be 7% per year. 

The summary of assumptions used for cost of capital is shown in Table B-4. 

Table B-4 — Summary of Cost of Capital Assumptions 

General 

Length of analysis period, yr 30 

General inflation, %/yr 2.5% For non-fuel expenses 

Base year for cost escalation 2002 When not otherwise specified in the model 

 

Financial Nominal $ Constant $ 

Equity rate of return 14.000% 11.50% 

Debt rate of return 8.50% 6.00% 

Debt repayment period 20 20 

Percent equity in capital structure Varies Varies 

Percent debt in capital structure Varies Varies 

Entity is subject to income tax (yes/no) Yes Yes 

Cost of construction, %/yr 7.00% 4.5% 

Target DSCR 1.35 1.35 

 

Amortization period for non-depreciable 

investment 

20 

Percentage of investment not depreciable 

(exclusive of IDC) 

2% 

Investment tax credit 10% Applies only to solar investment, equal to this 

percentage of depreciable investment 

State income tax rate 8.00% Similar to 8.84% in California or 6.97% in Arizona 

Federal income tax rate 35.00% 

Composite income tax rate 40.20% Income tax rate (composite federal and state) 

Insurance 0.50% Of project cost; escalated at inflation rate 

Property taxes 0.50% Of project cost; remains constant in nominal terms 

throughout project life 

Investment cost escalation rate 1.50% 
 

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B.1.3 Levelized Cost of Energy 

Levelized cost of energy was calculated based on the assumptions for cost of capital and the investment cost 

(capital cost) and operation and maintenance costs. S&L assessed the level of cost reductions and performance 

improvements, based on our experience, that are likely to be achieved in determining the investment and 

operations and maintenance costs. 
Appendix C 

Power Generation Markets 
 

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C. LEVELIZED COST FOR RANKING ALTERNATIVES AND 

EXAMPLE CALCULATIONS 

Economic choice between electricity generating alternatives is often done on the basis of levelized cost, which is 

the level revenue requirement that would cover all operating expenses and capital-related costs for the 

generating facility. Capital-related costs include return on invested debt, return on invested equity, federal and 

state income taxes associated with the return on equity, book depreciation (for recovery of debt and equity 

capital), and property taxes and insurance. Operating costs include fuel and non-fuel operation and maintenance 

costs. 

A levelized unit cost is a delivered product unit cost that, if charged for each year’s production over the analysis 

period, would yield the same net present value of revenues as if the actual annual cost for each alternative were 

collected instead over the period. It is C in the following equation: 

 ∑ ∑ = = +

=

+

n

i 1

n

i 1

i

(1 r)

i

ci Ei

(1 r)

CE

i

where C is a constant $/kWh cost to be charged each ith year over the analysis period (n=30 years, for example), 

Ei is the kWh sold in each such year, and ci is the actual annual $/kWh cost for each year, comprised of a current 

expense for fuel, labor, etc. plus a component for recovery of the investment cost, which may be a level series or 

may vary through time in some fashion. 

The constant C can be brought outside the summation on the left side. Then the expression on the right can be 

divided by the remaining summation on the left, leaving just C on the left side. Since the product inside the 

summation on top on the right, ci Ei , is dollars for each year, and the 1/(1+r)i

 is a discount factor, the top of the 

right side looks like the present value of revenue requirements. The bottom is denominated in kWh and looks 

like the present value of energy. This is why one often hears that levelized cost is computed as the present value 

of costs divided by the present value of energy. 

The levelized costs of energy (LCOE) in this study are computed as described above. In our calculations we 

have assumed that costs which vary over the evaluation period are covered by revenues of equal magnitude (i.e., 

operating costs are treated as a pass-through). Property taxes and insurance also are handled as pass-throughs. 
 

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All other capital-related costs (debt service, return on and of equity, income tax, etc.) are recovered as a uniform 

charge over the evaluation period. 

The financial model which developed the LCOE figures in this report performs the levelized cost calculation 

two ways: (1) in nominal dollars, where capital and operating costs escalate due to inflation and money rates are 

nominal values that include an inflation premium and (2) in real terms, where capital and operating costs do not 

escalate and the cost of debt in the financial calculations has had the inflation premium removed. 

Exhibits C-1 shows an example calculation for a CSP alternative in nominal dollar terms, where inflation is 

included for capital and operating costs and market costs of money are used in the financial calculations. Exhibit 

C-2 is the same calculation when done in real terms, with no inflation in capital and operating costs and using a 

deflated cost of debt. The inflation assumption used in these calculations is 21⁄2% per year. In both cases the 

capacity payment for recovering capital-related charges is set to achieve a 1.35 debt service coverage ratio using 

the financial leverage from the nominal dollar calculation. 
Project Analysis Worksheet: Nominal Dollar Analysis2020 Tower 220 @ 73% , New SunLabCase No.5 

Assumptions: Computed Target

Equity rate of return 14.00% 14.00% 280.66 capacity charge, $/kW/year (constant for analysis period)Required DSCR 1.35 1.35 0 HHV heat rate, Btu/kWh

Solar fuel type

 fixed non-fuel O&M cost, $1000/year in base year 4,920

0.00 variable non-fuel O&M cost, $/MWh in base year

Percent debt in capital structure 59.9% 5 MACRS depreciation schedule to be used (yrs)Percent equity in capital structure 40.1% 98.0% percentage of investment cost which is depreciable, excluding IDCCost of construction debt, %/year 7.00% 8.55% is computed fixed charge rate (from macro)Entity is subject to income tax (Y/N) YInitial weighted after-tax cost of capital (computed) 8.66%

Before ITC adjustment: Depreciable Amortize Total

Net MW 220 Solar inv. excl IDC 661.80 13.51 675.31Capacity factor 72.9% IDC 0.00 47.27 47.27Avg. years lead time for capital spending before COD 1.0 Total 661.80 60.78 722.58Starting year of analysis 2020 ITC amount: 66.18

Depreciable After ITC adjustment 628.71

$/kW $ Millions

Base Year Esc'd Esc'd Sources of Funds $ Millions Term Interest Amort $M/yr.

Project cost 2,383 3,070 675.31 Equity 289.75

Amount of IDC 215 47.27 Debt 432.83 20 8.50% 45.74Installed cost, including IDC 3,284 722.58 Total 722.58

Calendar Year 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 203

Project Year 1 2 3 4 5 6 7 8 9 10 11 12 1Year from 2002 18 19 20 21 22 23 24 25 26 27 28 29 3Analysis years 1 11 111111111

Depreciation, Amortization, and Debt Service Calculations ($ Millions)

Depreciation rates for 5 year MACRS depreciation 100.00% 35.00% 26.00% 15.60% 11.01% 11.01% 1.38% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 

Beginning of year values 628.7 408.7 245.2 147.1 77.9 8.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Tax depreciation (5 year MACRS) 628.7 220.0 163.5 98.1 69.2 69.2 8.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 End year asset value 408.7 245.2 147.1 77.9 8.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

Begin year amortization value 60.8 57.7 54.7 51.7 48.6 45.6 42.5 39.5 36.5 33.4 30.4 27.4 24.3 

Amortization over 20 years 60.8 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 End year asset value 57.7 54.7 51.7 48.6 45.6 42.5 39.5 36.5 33.4 30.4 27.4 24.3 21.3 Begin year debt amount Long-Term Debt 432.8 423.9 414.2 403.6 392.2 379.8 366.4 351.8 335.9 318.7 300.1 279.9 257.9 

Debt service payment 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 45.7 Interest 36.8 36.0 35.2 34.3 33.3 32.3 31.1 29.9 28.6 27.1 25.5 23.8 21.9 Debt principal repayment (mortgage type amortization) 432.83 check sum 8.9 9.7 10.5 11.4 12.4 13.5 14.6 15.8 17.2 18.6 20.2 21.9 23.8 End year debt amount 423.9 414.2 403.6 392.2 379.8 366.4 351.8 335.9 318.7 300.1 279.9 257.9 234.

Energy Calculations

Electric energy production, GWh Discounted energy: 14,889 (to oper yr.) 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 

Unit fuel costs 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Income Statement and Cashflow Statement Calculations ($ 1000)

Capacity revenue 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 

Revenue covering fixed non-fuel O&M revenue, property taxes, and insurance 14,663 14,939 15,222 15,513 15,810 16,115 16,428 16,748 17,076 17,413 17,758 18,112 18,474 Variable non-fuel O&M revenue 0 00 0000000000Fuel cost revenue 0 00 0000000000

Revenue Subtotal 76,408 76,684 76,968 77,258 77,555 77,860 78,173 78,493 78,821 79,158 79,503 79,857 80,219 

Fixed non-fuel O&M (7,674) (7,865) (8,062) (8,264) (8,470) (8,682) (8,899) (9,121) (9,349) (9,583) (9,823) (10,068) (10,320Variable non-fuel O&M 0 00 0000000000Insurance expense (3,377) (3,461) (3,547) (3,636) (3,727) (3,820) (3,916) (4,014) (4,114) (4,217) (4,322) (4,430) (4,54

Property tax expense (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613) (3,613

Fuel cost 0 00 0000000000Tax depreciation and amortization (223,088) (166,504) (101,118) (72,260) (72,260) (11,715) (3,039) (3,039) (3,039) (3,039) (3,039) (3,039) (3,039

Operating income (EBIT) (161,343) (104,759) (39,373) (10,515) (10,515) 50,030 58,706 58,706 58,706 58,706 58,706 58,706 58,706 Interest (36,790) (36,030) (35,205) (34,309) (33,338) (32,284) (31,140) (29,900) (28,554) (27,093) (25,508) (23,789) (21,923Taxable income (198,133) (140,789) (74,578) (44,824) (43,853) 17,746 27,566 28,806 30,153 31,613 33,198 34,917 36,783 Income tax 79,650 56,597 29,980 18,019 17,629 (7,134) (11,081) (11,580) (12,121) (12,709) (13,346) (14,037) (14,787

Investment tax credit (for solar investment only, when owned by taxable entity) 66,180After tax income (52,303) (84,192) (44,597) (26,805) (26,224) 10,612 16,484 17,226 18,031 18,905 19,852 20,881 21,996 Add back depreciation 223,088 166,504 101,118 72,260 72,260 11,715 3,039 3,039 3,039 3,039 3,039 3,039 3,039 Deduct repayment of debt principal (8,947) (9,707) (10,533) (11,428) (12,399) (13,453) (14,597) (15,837) (17,184) (18,644) (20,229) (21,948) (23,814

Equity investments and dividend payouts IRR: 14.0% (289,755) 161,838 72,605 45,988 34,027 33,637 8,874 4,927 4,428 3,887 3,299 2,662 1,971 1,22Discount factor (to year of initial operation) 0.920 0.847 0.779 0.717 0.660 0.608 0.559 0.515 0.474 0.436 0.401 0.369 0.340 Levelized and annual cost of electricity generation, nominal $/kWh 0.056 levelized 0.054 0.055 0.055 0.055 0.055 0.055 0.056 0.056 0.056 0.056 0.057 0.057 0.057 

Coverage Ratios

Cash available for debt service 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 61,745 

DSCR min 1.35 average 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 

Levelized

Discounted revenues (nominal from 2020) PV SumsCapacity 43.93 654,049 56,825 52,297 48,129 44,294 40,764 37,516 34,526 31,775 29,243 26,913 24,768 22,794 20,978 

Fixed O&M 12.53 186,528 13,495 12,653 11,866 11,128 10,438 9,791 9,186 8,619 8,087 7,590 7,123 6,686 6,277 

Variable O&M 0.00 0 - - - - - - - - - - - - - 

Fuel 0.00 0 - - - - - - - - - - - - - 

Total 56.45 840,577 70,319 64,950 59,995 55,422 51,202 47,307 43,712 40,394 37,330 34,502 31,891 29,481 27,255 
Project Analysis Worksheet: Constant Dollar Analysis2020 Tower 220 @ 73% , New SunLabCase No.5 

Assumptions: Computed

Equity rate of return 12.12% 175.58 capacity charge, $/kW/year (constant for analysis period)Required DSCR 1.35 0 HHV heat rate, Btu/kWh

Solar fuel type

 fixed non-fuel O&M cost, $1000/year in base year 4,920

0.00 variable non-fuel O&M cost, $/MWh in base year

Percent debt in capital structure 59.9% 5 MACRS depreciation schedule to be used (yrs)Percent equity in capital structure 40.1% 98.0% percentage of investment cost which is depreciable, excluding IDCCost of construction debt, %/year 4.50% 7.05% is computed fixed charge rate (from macro)Entity is subject to income tax (Y/N) YInitial weighted after-tax cost of capital (computed) 7.01%

Before ITC adjustment: Depreciable Amortize Total

Net MW 220 Solar inv. excl IDC 513.81 10.49 524.30Capacity factor 72.9% IDC 0.00 23.59 23.59Avg. years lead time for capital spending before COD 1.0 Total 513.81 34.08 547.89Starting year of analysis 2020 ITC amount: 51.38

Depreciable After ITC adjustment 488.12

$/kW $ Millions

Base Year Esc'd Esc'd Sources of Funds $ Millions Term Interest Amort $M/yr.

Project cost 2,383 2,383 524.30 Equity 219.71

Amount of IDC 107 23.59 Debt 328.19 20 6.00% 28.61Installed cost, including IDC 2,490 547.89 Total 547.89

Calendar Year 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 203

Project Year 1 2 3 4 5 6 7 8 9 10 11 12 1Year from 2002 18 19 20 21 22 23 24 25 26 27 28 29 3Analysis years 1 11 111111111

Depreciation, Amortization, and Debt Service Calculations ($ Millions)

Depreciation rates for 5 year MACRS depreciation 100.00% 35.00% 26.00% 15.60% 11.01% 11.01% 1.38% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 

Beginning of year values 488.1 317.3 190.4 114.2 60.5 6.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Tax depreciation (5 year MACRS) 488.1 170.8 126.9 76.1 53.7 53.7 6.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 End year asset value 317.3 190.4 114.2 60.5 6.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

Begin year amortization value 34.1 32.4 30.7 29.0 27.3 25.6 23.9 22.2 20.4 18.7 17.0 15.3 13.6 

Amortization over 20 years 34.1 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 End year asset value 32.4 30.7 29.0 27.3 25.6 23.9 22.2 20.4 18.7 17.0 15.3 13.6 11.9 Begin year debt amount Long-Term Debt 328.2 319.3 309.8 299.8 289.2 277.9 266.0 253.3 239.9 225.7 210.6 194.6 177.7 

Debt service payment 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 Interest 19.7 19.2 18.6 18.0 17.3 16.7 16.0 15.2 14.4 13.5 12.6 11.7 10.7 Debt principal repayment (mortgage type amortization) 328.19 check sum 8.9 9.5 10.0 10.6 11.3 11.9 12.7 13.4 14.2 15.1 16.0 16.9 18.0 End year debt amount 319.3 309.8 299.8 289.2 277.9 266.0 253.3 239.9 225.7 210.6 194.6 177.7 159.7 

Energy Calculations

Electric energy production, GWh Discounted energy: 17,423 (to oper yr.) 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 1,406 

Unit fuel costs 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Income Statement and Cashflow Statement Calculations ($ 1000)

Capacity revenue 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 

Revenue covering fixed non-fuel O&M revenue, property taxes, and insurance 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,281 10,28Variable non-fuel O&M revenue 0 00 0000000000Fuel cost revenue 0 00 0000000000

Revenue Subtotal 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 48,908 

Fixed non-fuel O&M (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920) (4,920

Variable non-fuel O&M 0 00 0000000000Insurance expense (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622) (2,622

Property tax expense (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739) (2,739

Fuel cost 0 00 0000000000Tax depreciation and amortization (172,547) (128,616) (77,851) (55,446) (55,446) (8,440) (1,704) (1,704) (1,704) (1,704) (1,704) (1,704) (1,704

Operating income (EBIT) (133,920) (89,989) (39,224) (16,819) (16,819) 30,187 36,923 36,923 36,923 36,923 36,923 36,923 36,923 

Interest (19,691) (19,156) (18,589) (17,987) (17,350) (16,674) (15,957) (15,198) (14,393) (13,540) (12,636) (11,677) (10,66Taxable income (153,611) (109,145) (57,812) (34,806) (34,168) 13,514 20,966 21,725 22,530 23,383 24,288 25,247 26,263 Income tax 61,752 43,876 23,241 13,992 13,736 (5,432) (8,428) (8,734) (9,057) (9,400) (9,764) (10,149) (10,558

Investment tax credit (for solar investment only, when owned by taxable entity) 51,381After tax income (40,478) (65,268) (34,572) (20,814) (20,433) 8,081 12,538 12,992 13,473 13,983 14,524 15,097 15,705 Add back depreciation 172,547 128,616 77,851 55,446 55,446 8,440 1,704 1,704 1,704 1,704 1,704 1,704 1,704 Deduct repayment of debt principal (8,922) (9,457) (10,024) (10,626) (11,263) (11,939) (12,656) (13,415) (14,220) (15,073) (15,977) (16,936) (17,952

Equity investments and dividend payouts IRR: 12.1% (219,705) 123,148 53,891 33,255 24,007 23,750 4,582 1,586 1,281 957 614 251 (135) (543Discount factor (to year of initial operation) 0.934 0.873 0.816 0.763 0.713 0.666 0.622 0.582 0.543 0.508 0.475 0.443 0.414 Levelized and annual cost of electricity generation, nominal $/kWh 0.035 levelized 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 0.035 

Coverage Ratios

Cash available for debt service 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 38,627 

DSCR min 1.35 average 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 

Levelized

Discounted revenues (constant from 2020) PV SumsCapacity 27.48 478,786 36,097 33,732 31,522 29,456 27,526 25,723 24,037 22,463 20,991 19,616 18,330 17,129 16,007 

Fixed O&M 7.31 127,432 9,607 8,978 8,390 7,840 7,326 6,846 6,398 5,979 5,587 5,221 4,879 4,559 4,260 

Variable O&M 0.00 0 - - - - - - - - - - - - - 

Fuel 0.00 0 - - - - - - - - - - - - - 

Total 34.79 606,219 45,704 42,710 39,911 37,296 34,853 32,569 30,435 28,441 26,578 24,836 23,209 21,688 20,267 
Appendix D 

Evaluation of Technology Improvements and 

Capital Cost Projections 

for Parabolic Trough Solar Plants 
 

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D. EVALUATION OF TECHNOLOGY IMPROVEMENTS AND 

CAPITAL COST PROJECTIONS FOR 

PARABOLIC TROUGH SOLAR PLANTS 

CONTENTS 

Section Page

D.1 Cost Drivers ............................................................................................................................................ D-1 

D.2 Deployment ............................................................................................................................................. D-6 

D.3 Efficiency ................................................................................................................................................ D-9 

D.3.1 Solar Optical Efficiency................................................................................................................ D-13 

D.3.2 Receiver Thermal Efficiency ........................................................................................................ D-14 

D.3.3 Steam Cycle Efficiency................................................................................................................. D-15 

D.3.4 Thermal to Power Plant Efficiency — Parasitics.......................................................................... D-16 

D.3.5 Efficiency Improvements Summary.............................................................................................. D-17 

D.4 Solar Field — Support Structure........................................................................................................... D-19 

D.4.1 Direct Capital Cost........................................................................................................................ D-19 

D.4.2 Technology Improvements............................................................................................................ D-20 

D.4.3 Scale-Up........................................................................................................................................ D-21 

D.4.4 Production Volume ....................................................................................................................... D-21 

D.4.5 Cost Comparison........................................................................................................................... D-23 

D.5 Solar Field – Heat Collection Element (HCE) ...................................................................................... D-24 

D.5.1 Direct Capital Cost........................................................................................................................ D-24 

D.5.2 Technology Improvements............................................................................................................ D-25 

D.5.3 Scale-Up........................................................................................................................................ D-26 

D.5.4 Production Volume ....................................................................................................................... D-26 

D.5.5 Cost Comparison........................................................................................................................... D-27 

D.6 Solar Field – Mirrors............................................................................................................................. D-27 

D.6.1 Direct Capital Cost........................................................................................................................ D-27 
 

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D.6.2 Technology Improvements............................................................................................................ D-27 

D.6.3 Scale-Up........................................................................................................................................ D-29 

D.6.4 Production Volume ....................................................................................................................... D-29 

D.6.5 Cost Comparison........................................................................................................................... D-29 

D.7 Power Block.......................................................................................................................................... D-30 

D.7.1 Direct Capital Cost........................................................................................................................ D-30 

D.7.2 Technology Improvements............................................................................................................ D-30 

D.7.3 Scale-Up........................................................................................................................................ D-30 

D.7.4 Production Volume ....................................................................................................................... D-32 

D.7.5 Cost Comparison........................................................................................................................... D-32 

D.8 Thermal Storage.................................................................................................................................... D-32 

D.8.1 Direct Capital Cost........................................................................................................................ D-32 

D.8.2 Technology Improvements............................................................................................................ D-34 

D.8.3 Scale-Up........................................................................................................................................ D-36 

D.8.4 Production Volume ....................................................................................................................... D-36 

D.8.5 Cost Comparison........................................................................................................................... D-37 

D.9 Capital Cost Comparison ...................................................................................................................... D-37 

D.10 Operations and Maintenance................................................................................................................. D-39 

D.11 Levelized Energy Costs......................................................................................................................... D-42 
 

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D. EVALUATION OF TECHNOLOGY IMPROVEMENTS AND 

CAPITAL COST PROJECTIONS FOR 

PARABOLIC TROUGH SOLAR PLANTS 

D.1 COST DRIVERS 

The direct costs of a parabolic solar plant can be summarized into the following five major categories: 

• Siteworks and Infrastructure 

• Solar Field 

 Heat Collection Element (HCE) 

 Mirror 

 Support Structure 

 Drive 

 Piping 

 Civil Work 

• Power Block 

 Steam Turbine and Generator 

 Electric Auxiliaries 

 Thermal Storage/Heat Transfer Fluid System 

 Balance of Plant (BOP) 

• Cooling System 

• Water treatment 

• Electrical 

• Instrumentation & control 

• Miscellaneous Civil Work 

The Solar Field, Thermal Storage and Power Block costs encompass approximately 95% of the total direct costs, 

as illustrated in Figure D-1. Of these three highest cost categories, the Solar Field cost comprises 58% of the 

total direct cost. Figure D-2 shows the solar field component cost breakdown. The component cost breakdown 

of the Solar Field reveals the Support Structures are 29%, the Heat Collection Elements (HCE) 19%, and the 

Mirrors 18% of the Solar Field direct costs, for a total of 68% of the Solar Field direct costs. 
 

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Figure D-1 — Major Cost Categories for Parabolic Trough Plant 

2004 Near-Term Case: 100 MWe, 12 hrs TES, 2.5 Solar Multiple 

58%

23%

3%

14% 2%

Structures and Improvements

(2%)

Solar Collection System

(58%)

Thermal Storage System

(23%)

Steam Gen or HX System

(3%)

Power Block (EPGS, BOP)

(14%)

Figure D-2 — Solar Field Component Cost Breakdown for Parabolic Trough Plant 

2004 Near-Term Case: 100 MWe, 12 hrs TES, 2.5 Solar Multiple 

20%

19%

29%

6%

5%

7%

3%

4%

4% 3%

Receiver (HCE) (20%)

Mirror (19%)

Metal support structure (29%)

Drive (6%)

Interconnection Piping (5%)

Electronics & control (7%)

Header piping (3%)

Pylon Foundations (4%)

Other Civil Works (4%)

Heat Transfer Fluid (3%)

The evaluation of cost reductions for a parabolic trough plant focuses on the solar field, power block, and 

thermal storage since these three areas account for approximately 90% of the total direct costs (based on 

12 hours of thermal storage). As pointed out previously and illustrated in Figure D-2, the support structures are 

29%, the HCE 19%, and the mirrors 18% of the solar field direct costs; 68% of the total solar field direct cost. 

As such, the following main items were focused on for evaluation of cost reductions: 

• Net annual solar-to-electric efficiency 

• Solar field 

 Support structure 
 

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 HCE 

 Mirrors 

• Power block 

• Thermal storage 

The following major potential cost reductions were considered: 

• Technology improvements 

• Scale-up (economy of scale) 

• Production volume 

Table D-1 provides a summary of SunLab’s design, deployment, and cost projections for trough plants with the 

SEGS VI plant as the base case. 

Table D-1 — SunLab Cost Projections 

SEGS VI

Trough 

100

Trough 

100

Trough 

150

Trough 

200

Trough 

400

 1999 2004 2007 2010 2015 2020

Plant size, net electric, MWe 30 100 100 150 200 400 

Plant size, gross thermal input, 

MWt 

88 294 279 408 544 1,087 

Thermal Storage, hr 0 12 12 12 12 12 

Annual Plant Capacity Factor 22.2% 53.5% 56.2% 56.2% 56.2% 56.5% 

Annual Solar-to-Electric 

Efficiency 

10.6% 14.2% 16.1% 17.0% 17.1% 17.2% 

 

Solar Field Design: 

 Number of Collectors 800 4,768 1,269 1,808 2,392 4,783 

 Receivers per SCA 12 12 36 36 36 36 

 Number HCE 9,600 57,216 45,700 65,072 86,101 172,201 

 Number HCE Accumulative 9,600 66,816 112,516 177,588 263,688 435,889 

 Collector Size, m2 235 235 817.5 817.5 817.5 817.5 

 Field Aperture Area, m2 188,000 1,120,480 1,037,760 1,477,680 1,955,200 3,910,400 

 
 

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SEGS VI

Trough 

100

Trough 

100

Trough 

150

Trough 

200

Trough 

400

 1999 2004 2007 2010 2015 2020

Heat Transfer Fluid System 

 HTF Type VP-1 VP-1 Hitec XL Hitec XL Hitec XL Hitec XL 

 Fluid Volume, gallons 115,500 688,380 637,560 907,830 1,201,200 2,402,400 

 

Direct Capital Cost: 

 Structures & Improvements 2,526 7,279 6,538 8,097 9,596 16,284 

 Collector System 44,793 249,654 181,533 226,753 259,852 452,825 

 Thermal Storage System 0 95,807 42,475 57,426 76,567 153,135 

 Steam Gen or HX System 4,304 9,964 9,227 11,161 12,772 19,394 

 EPGS 15,805 36,713 34,877 44,008 51,134 78,915 

 Balance of Plant 9,190 21,346 20,279 25,588 29,732 45,884 

 Total Direct Costs 76,619 420,763 294,929 373,033 439,654 766,438 

 

Solar Collection System, $/m2 

field 

250 234 184 161 140 122 

Receivers, $/m2 field 43 43 34 28 22 18 

 $/unit 847 847 762 635 508 400 

Mirrors, $/m2 field 40 40 36 28 20 16 

Concentrator Structure, $/m2 

field 

50 47 44 42 39 36 

Concentrator Erection, $/m2 

field 

17 14 13 12 11 10 

Drive, $/m2 field 14 13 6 6 6 5 

Interconnection Piping, $/m2 

field 

11 10 3 3 3 2 

Electronics & control, $/m2 field 16 14 4 4 4 3 

Header piping, $/m2 field 8 7 7 6 6 5 

Foundations/Other Civil, $/m2 

field 

21 18 17 15 14 12 
 

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SEGS VI

Trough 

100

Trough 

100

Trough 

150

Trough 

200

Trough 

400

 1999 2004 2007 2010 2015 2020

Other (Spares, HTF, freight), 

$/m2 field 

17 17 11 10 9 8 

Contingency, $/m2 field 12 11 9 8 7 6 

 

Direct Capital Cost, $/kWe 

Structures and Improvements, 

$/kWe 

84 73 65 54 48 41 

Solar Collection System, $/kWe 1,493 2,497 1,815 1,512 1,299 1,132 

Thermal Storage System, 

$/kWe 

0 958 425 383 383 383 

Steam Generator or HX 

System, $/kWe 

143 100 92 74 64 48 

EPGS, $/kWe 527 367 349 293 256 197 

Balance of Plant, $/kWe 306 213 203 171 149 115 

Total Direct Cost, $/kWe 2,554 4,208 2,949 2,487 2,198 1,916 

In a series of evolutionary design improvements, the following major advancements formed the basis of the 

SunLab estimates: 

• Collector 

 A comprehensive series of wind tunnel tests on parabolic trough collector models was 

carried out in 2001–2002, establishing design pressure force coefficients for various wind 

approach angles and collector orientations, with and without a wind fence. 

 Using these coefficients, finite element methods stress analyses were used to optimize the 

collector structure for wind survival conditions, minimizing collector weight and defining 

design parameters for mirror strength, pylons, and foundations. With more tightly known 

design parameters, collector weight, and thus costs, can be lowered. 

 High efficiency and durable receivers are assumed to be developed, with selective surfaces 

(consisting of special selective coatings on the metal tube receivers) to maximize the 

absorption of incident solar radiation and minimize radiation losses from the receiver. High 

efficiencies result in smaller solar fields for a given thermal energy delivery, and longer 

lifetimes to reduce operation and maintenance costs. 

 Advanced receivers are assumed utilizing selective surfaces that can operate efficiently at 

temperatures of 500°C or higher, paving the way for major advancements in thermal 

storage and power block operation for trough plants. 
 

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 Alternative mirror design development using thin-glass with non-metallic structural 

elements, or using thin silverized films is assumed. Both approaches reduce weight and 

offer less expensive reflector options. 

• Heat transfer fluid (HTF) 

 Alternate HTFs, such as inorganic molten salts and ionic fluids, are being investigated that 

will permit operation at higher temperatures (at or above 500°C), leading to lower thermal 

storage costs and higher power block efficiencies. 

• Thermal Storage System 

 The Solar Two two-tank molten salt storage system is designed for commercial operation 

in a trough plant for the case of the conventional synthetic oil HTF. Termed an indirect 

storage system, this also requires an oil-to-salt heat exchanger in the system. 

 This same two-tank molten salt storage system is designed for direct operation with a 

molten salt HTF. 

 A single-tank direct molten salt thermocline system is designed to reduce thermal storage 

costs. 

• Electric Power Block 

 The efficiency of a SEGS-type plant is improved by refining the integration of the solar 

field with the power block. 

 Turbine efficiencies are improved through use of the higher temperature heat transfer fluids 

in the solar field. 

D.2 DEPLOYMENT 

The inherent capital-intensive nature of the technology and the current high costs and early mass-production 

hurdles are disadvantages for the trough technology. While the trough technology was commercialized for a 

brief period, no trough plants have been built in nearly a decade. Trough solar plants are a proven technology 

and 354 MW of trough technology generation at the SEGS plants have and are still being operated 

commercially. 

Deployment is a key element in the cost reductions as it impacts the component production volume. Table D-2 

below shows a case of two scenarios set forth by SunLab that could be realistically representative of how 

systems would be deployed commercially if a market existed considering the potential trough deployment 

presented in Table D-3. The first assumes one plant built per year. The second assumes a doubling of cumulative 

installed capacity with each new technology case introduced. This second case is an aggressive development 

scenario; however, if the projects were financially competitive, this represents a plausible development scenario. 

The second case is the type of scale-up that Luz envisioned and actually achieved with the SEGS plants to some 
 

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degree, building multiple plants in the same year. The SunLab projections are based on the Case 2 deployment 

scenario. S&L estimates are based on the Case 1 deployment scenario. 

Table D-2 — Trough Deployment Scenarios 

Year 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

Technology 

Cases X X X X X 

Case 1 Deployment Scenario: One Plant per Year Deployment 

2004 

Technology 

100 

MW 1 1 1 300 650 

2007 

Technology 

100 

MW 1 1 1 300 950 

2010 

Technology 

150 

MW 1 1 1 1 1 750 1,700 

2015 

Technology 

200 

MW 1 1 1 1 1 1,000 2,700 

2020 

Technology 

400 

MW 1 400 3,100 

Total 2,750 

 

Case 2 Deployment Scenario: Cumulative Capacity Doubled with Each New Technology Case 

2004 

Technology 

100 

MW 1 1 1 300 650 

2007 

Technology 

100 

MW 1 2 2 1 600 1,250 

2010 

Technology 

150 

MW 1 1 2 2 2 1,200 2,450 

2015 

Technology 

200 

MW 1 2 2 3 3 1 2,400 4,850 

2020 

Technology 

400 

MW 1 400 5,250 

Total 4,900 

Approximate estimates of CSP deployment have been identified in several reports (Morse 2000). Based on the 

projections presented in those reports, a potential trough deployment is presented in Table D-3. The potential 
 

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trough deployment estimates are significantly greater than the two deployment scenarios investigated; thus, cost 

reductions would be greater if the potential deployment estimate proves to be accurate. 

Table D-3 — Potential Trough Deployment 

2010 2020

 International U.S. International U.S.

Total Deployment 8,300 MW 1,800 MW 30,000 MW (min.) 2,900 MW (min.) 

Estimated Trough Deployment 4,980 MW 1,080 MW 18,000 MW (min.) 1,740 MW (min.) 

Total Estimated Trough Deployment 6,060 MW 19,740 MW (min.) 

The actual strategy employed by the plant suppliers can be significantly diverse, with more emphasis on nearterm cost reduction with a minimum of risk. The suppliers may opt to provide multiple plants in the 50-MWe to 

100-MWe size range with no thermal storage but with a supplemental steam generator, replicating the proven 

technology of the existing SEGS plants. The suppliers can rely more on initial production volume to reduce 

costs as opposed to efficiency and technology improvements and scale-up factors. Minimizing or eliminating 

thermal storage, with its current elevated cost, appreciably reduces the total direct cost of the plant as discussed 

later in this section of the report. The suppliers’ strategy will depend on the deployment of trough plants. 

Figure D-3 below illustrates the SunLab projected range in cost of power from various near-term trough plant 

configurations. The first three plants are all 50 MWe in size. The first is a solar-only plant with no hybrid 

backup or thermal energy storage. This plant has the lowest capital cost but the highest levelized energy cost 

(LEC) expressed as $/kWhe. The next plant is the 50-MWe hybrid plant that is assumed to produce 25% of its 

electricity from natural gas, similar to the existing SEGS plants. This plant has the lowest LEC of the 50-MWe 

plants. This is the type of plant that Duke Solar is proposing for development in the U.S. Southwest, where 

lowest cost and on-peak capacity is required. The third configuration is a 50-MWe plant with 9 hours of thermal 

storage and an oversized solar field. Note that the LEC is lower than the solar-only plant without thermal 

storage. This is the configuration of the proposed 40-MWe trough project in Spain. Note that this plant is 

preferred in Spain because of the requirements of the solar tariff. The fourth plant configuration is a trough 

hybrid that is integrated with a combined-cycle plant. This configuration, referred to as an integrated solar 

combined-cycle system (ISCCS), is what is proposed for several of the GEF projects in India, Mexico, Egypt, 

and Morocco. This configuration has the lowest LEC, but it must be integrated into a much larger combinedcycle plant. Depending on the specific market, different configurations of plants are typically proposed. The 
 

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fifth plant is the near-term SunLab 100-MW configuration with 12 hours of thermal storage. With the exception 

of the ISCCS, this plant provides the lowest cost of power. This plant represents a low-cost technically feasible 

design, but is not necessarily the configuration that will be built. 

Figure D-3 — Cost of Near-Term Trough Technology Configurations 

0.00

0.02

0.04

0.06

0.08

0.10

0.12

Levelized Energy Cost ($/kWh)

50 MW Solar Only

50 MW Hybrid

50 MW 9 hrs TES

40 MW ISCCS

100 MW 12 hrs TES

D.3 EFFICIENCY 

The Solar Field is defined by the collector area in square meters (m2), which can be estimated by the following 

simplified equation: 

 C = (kW d x CF x h) 

 η x I 

 Where: 

 C = Collector area square meters (m2

) 

 kW d = electric generation design capacity, kilowatts 

 CF = Capacity Factor = kWh actual / (kWd x 8,760) 

 h = hours per year (8,760) 

 η = net annual solar-to-electric efficiency 

 I = annual insolation (kWht/m2 ) 

 kWe = kilowatts electric 

 kWht =kilowatts thermal 

For a given plant size and capacity factor the net annual efficiency is the determining factor in the collector area; 

as the efficiency increases the collector area decreases on the same percentage basis. 
 

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The annual net solar-to-electric efficiency determination and the current efficiency of the 1989 era 33-MW 

SEGS parabolic trough plant are shown in Table D-4. 

Table D-4 — Annual Solar-to-Electric Efficiency 

Solar Field 

 Incidence Angle 87.3% 

 Solar Field Availability 99.0% 

 Solar Field Optical Efficiency 61.7% 

 Receiver Thermal Efficiency 72.9% 

 Piping Thermal Losses 96.1% 

 No Op Low Insolation 99.6% 

 Solar Field Thermal Delivered Efficiency (SFE) 37.2% 

Thermal to Power Plant Efficiency (TPPE) 

(Start-up/shutdown losses) 

 93.4% 

Gross Steam Cycle Efficiency (ST) 37.5% 

Parasitics (P) 

(1 - % auxiliary power consumed by plant) 

 82.7% 

Plant-Wide Availability (A) 98.0% 

Annual Solar-to-Electric Efficiency (Enet) 

Enet = SFE x TPPE x ST x P x A 

 10.6% 

The net annual solar-to-electric efficiency has a significant impact on the cost of a trough plant. An example of 

the difference in solar field cost for a 100-MWe plant is illustrated in Table D-5. 

Table D-5 — Annual Solar-to-Electric Impact on Cost 

Plant Size net electric, MWe 100 100 100 100 100 100 

Annual Plant Capacity Factor 25% 25% 25% 25% 25% 25% 

Annual Solar-to-Electric Efficiency 10.6% 14.2% 16.1% 17.0% 17.1% 17.2%

Field Aperture Area, m2 709,248 527,138 464,854 440,880 437,692 435,079 

Solar Collection System $/m2 * Thousands $

Receivers 43 30,680 22,802 20,108 19,071 18,933 18,820 

Mirrors 40 28,507 21,187 18,684 17,720 17,592 17,487 
 

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Solar Collection System $/m2 Thousands $

Concentrator Structure 47 32,981 24,513 21,616 20,501 20,353 20,232 

Concentrator Erection 14 9,777 7,267 6,408 6,077 6,033 5,997 

Drive 13 9,484 7,049 6,216 5,895 5,852 5,817 

Interconnection Piping 10 7,172 5,331 4,701 4,458 4,426 4,400 

Electronics & control 14 10,276 7,638 6,735 6,388 6,341 6,304 

Header piping 7 4,875 3,623 3,195 3,030 3,008 2,990 

Foundations/Other Civil 18 12,429 9,237 8,146 7,726 7,670 7,624 

Other (Spares, HTF, freight) 17 11,841 8,801 7,761 7,360 7,307 7,264 

Contingency 11 7,901 5,872 5,178 4,911 4,876 4,846

Total, $/m2 234 165,928 123,323 108,752 103,143 102,397 101,786 

 

Total, $/kWe 1,659 1,233 1,088 1,031 1,024 1,018 

Relative Cost 1.00 0.74 0.66 0.62 0.62 0.61 

$/m2 costs based on SunLab values for 2004 case. 

Table D-5 shows that the solar field cost for a 100-MWe plant can be reduced by approximately 40% by 

improving the net annual solar-to-electric efficiency from the current 10.6% to 17.2%. 

The collector area is directly proportional to the plant megawatt size and the capacity factor, as evident in the 

preceding equation. There are economies of scale associated with increasing the plant megawatt size. 

Without thermal storage, the annual capacity factor of the solar plant is limited to approximately 20% to 25%. 

To provide generation during non-solar periods and thereby increase the plant capacity factor, thermal storage is 

required. Thermal storage can reduce plant thermal losses by reducing the number of steam turbine start-stop 

cycles and decreasing the heat transfer fluid heating during no-load periods. The plant megawatt size and 

thermal storage will be discussed in further detail later in the report. 

The major efficiency improvements projected by SunLab and the approximate corresponding contribution to the 

annual net solar-to-electric efficiency improvement are indicated in Table D-6. 
 

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Table D-6 — Projected Efficiency Improvements 

Annual Values (not Design Point) 

referenced to 1999 SEGS VI Current 

SunLab 

Short-Term

2007 

SunLab 

Long-Term 

2020 

Solar Field Optical Efficiency 61.7% 70.4% 73.0% 

 Percentage Point Improvement** — +1.5 +2.0 

Receiver Thermal Efficiency 72.9% 86.2% 85.3% 

 Percentage Point Improvement** — +2.0 +1.8 

Steam Cycle Efficiency 37.5% 39.3% 40.3% 

 Percentage Point Improvement** — +1.0 +1.4 

Thermal to Power Plant Efficiency * 

(Start-up/shutdown losses) 

93.4% 99.2% 99.2% 

 Percentage Point Improvement** — +0.7 +0.7 

Parasitics * 82.7% 88.3% 92.8% 

 Percentage Point Improvement** — +0.4 +0.8%

Total Percentage Point Improvement** — +5.6 +6.7 

* Improvements based on 12 hours thermal storage 

** Relative to net annual efficiency 

The technological advances and research, upon which the SunLab efficiency improvement estimates are based, 

include the following: 

• The development of the new Solel UVAC receiver. The UVAC has improved thermal and optic 

properties. Field tests of the new receiver at SEGS VI shows a 20% increase in thermal 

performance compared to original receiver tubes. 

• The development of ball joint assembly replacements for flexhoses. A demonstration of new 

ball joint assemblies has shown that they can reduce the hydraulic pressure drop in the solar 

field by approximately 50%. This results in lower solar field heat transfer fluid pumping electric 

parasitics. 

• Improvements in mirror washing techniques have resulted in increased solar field average 

mirror reflectance. 

• Investigation of higher temperature heat transfer fluids. 

• Research of direct thermal energy storage. 

• Research of higher temperature receiver selective coatings. 
 

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D.3.1 Solar Optical Efficiency 

The near-term projected optical efficiency improvement from 61.7% to 70.4% optical efficiency is based on the 

following considerations: 

• Increase in mirror cleanliness from 93.1% in 1999 to 95% in 2005. The standard mirror 

cleanliness assumption is 95%, and this is considered achievable with a normal, reasonably 

aggressive mirror wash program. 

• Increase in receiver envelope glass transmissivity from 92.5% to 97%. Solel has developed 

improved anti-reflective coatings for the glass envelope. 

• Increase in receiver absorption from 92% to 96%. The new Solel cermet coating has 

demonstrated solar absorption of 96%. Additional optimization of the coating is needed to 

maintain this level and achieve the desired low emittance. 

• The concentrator is increased in length from 50 meters to 150 meters. This longer length 

reduces end losses, light that reflects off the end of the collector, by 2.2%. 

The projected near-term efficiency improvement is summarized in the following equation: 

ηOpt, near-term = ηp * (Cn/Cp) * (Tn/Tp) * (An/Ap) * (1 + EL) 

 where: 

 η = efficiency 

 C = mirror cleanliness 

 T = transmissivity 

 A = absorption 

 EL = end loss reduction 

 n = new 

 p = present 

η Opt, near-term = 0.617 * (0.95/0.931) * (0.97/0.925) * (0.96/0.92) * 1.022 = 0.704 

The long-term projected optical efficiency improvement from 70.4% to 73% optical efficiency is based on the 

following considerations: 

• The Solar weighted mirror reflectivity is assumed to increase from 93.5% for current back 

silvered 4 mm thick glass to 95% for next generation reflectors that are front surface reflectors 

with a hard coat for protection. 

• Mirror cleanliness of new reflectors is projected to be maintained at higher levels of cleanliness 

due to new glass anti-soiling coatings that are now being sold on building window glass. Mirror 

cleanliness is projected to increase from 95% to 96% in future plants. 
 

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• Anti-soiling coatings will also be added to the receiver glazing. The coatings are expected to 

have a bigger impact due to the receiver glazing orientation. The important side of the receiver 

to keep clean is normally facing in a downward direction, where as the mirror normally face up. 

Receiver soiling factor improves from 0.98 to 0.99. 

The projected long-term efficiency improvement is summarized in the following equation: 

η Opt, long-term = 0.704 * (0.95/0.935) * (0.96/0.95) * (0.99/0.98) = 0.730 

D.3.2 Receiver Thermal Efficiency 

The projected receiver thermal efficiency improvement from 72.9% to 86.2% receiver thermal efficiency is 

based on the following considerations: 

• The primary factor in reducing solar field thermal losses is through reduction in the emittance of 

the receiver selective coating. The selective coating on the receivers in the SEGS VI solar field 

is half cermet and half black chrome. These receivers had fairly high emittance in comparison to 

the latest Solel UVAC selective coating. Solel testing at SPF showed an emittance of 0.091. 

Solel believes that with further optimization, an emittance of 0.07 at 400°C is possible while 

maintaining high solar absorptance 98%. Some R&D and testing are required to achieve the 

near-term receiver assumptions. SunLab believes these projections are aggressive and have set 

the receiver absorptance and emittance goals at 0.96 and 0.07 (at 400°C), respectively. 

• A secondary factor in reducing solar field thermal losses is through increasing receiver 

reliability, which results in fewer receiver tubes in the solar field with lost vacuum, broken 

glass, or coating defects. Field test results on the Solel UVAC receiver indicate failure rates 

below historic levels. In addition, the new UVAC selective coating will not fail even when 

exposed to air at temperature. Thus no coating failures are assumed in future plants. 

• The near-term plant is assumed to operate at 450°C outlet temperature. This results in a slight 

decrease in solar field thermal efficiency. Piping heat losses are actually reduced because the 

plant is assumed to use HitecXL, and a three component inorganic molten salt, that has a higher 

heat capacity/density product than Therminol VP-1 that allows substantially smaller piping to 

be used in the solar field. This results in lower solar field piping heat losses overall. 

There is some uncertainty in the current properties of the Solel UVAC receiver. The tubes tested at Kramer 

Junction had their properties measured by Sandia. These had a solar absorptance of 96% and a thermal 

emittance of 13.5% at 400°C. These tubes showed a 20% thermal performance increase on the test loop at 

SEGS VI. Solel had the properties measured from a later batch of tubes that indicated an absorptance of 94.4% 

and an emittance of 9.1% at 400o

C. There is significant uncertainty in the property measurements but better 

properties are expected by SunLab. The following table lists the receiver tube property assumptions used in the 

SunLab cases. 
 

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Table D-7 — Receiver Tube Property Assumptions 

Luz 

(original)

Current 

(SEGS 1999)

SunLab 

Near-Term

SunLab 

Long-Term

SEGS VI UVAC 1/2 Assumption Assumption

Absorptance 0.92 0.96/0.944 0.96 0.96 

Envelope Glass Transmissivity 0.92 0.965/0.965 0.97 0.97 

Emittance at 400°C >0.18 0.135/0.091 0.07 0.07 

Operating Temperature 392°C >450°C 450°C 500°C 

D.3.3 Steam Cycle Efficiency 

The steam cycle foundation is the Rankine cycle. As the inlet steam conditions (pressure and temperature) 

increase, the Rankine cycle efficiency increases. The near-term steam cycle gross efficiency from 37.5% to 

39.3% is predicated on increasing the inlet steam temperature from 390°C to 450°C. The long-term increase to 

40.3% is based on 500°C steam inlet temperature. The net steam turbine efficiency (gross efficiency minus the 

percentage of parasitic power consumption required for plant operation) is accounted for by calculation of the 

parasitic consumption separately, as shown on Table D-6, “Projected Efficiency Improvements,” and discussed 

in the following section. 

The near-term turbine efficiency is verified based on the ABB-Brown Boveri heat balances (HTGD 582395, 

Sheets 1-7) for SEGS IX, which show an efficiency of 37.7% (in LUZ International Limited 1990). The Rankine 

cycle efficiency gains for increasing the inlet steam temperature from 390°C to 500°C were verified by S&L by 

using General Electric STGPER software program (Version 4.08.00, January 2002). The turbine efficiencies are 

summarized in Table D-8. 

Table D-8 — Steam Turbine Efficiencies 

Turbine Inlet 

Temperature 

ABB-Brown Boveri

(SEGS IX) SunLab Projection S&L Estimate (GE STGPER basis) 

390°C 37.7% 37.5% 37.5% 

450°C — 39.3% 39.5% 

500°C — 40.3% 40.6% 
 

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There are no steam turbine technological risks in achieving the SunLab projected efficiencies. There are 

currently numerous steam turbines operating with steam inlet conditions over 250 bar pressure and 590°C 

temperature, with gross efficiencies over 44%.*

However, the type of heat transfer fluid (HTF) used determines the operational temperature range of the solar 

field and thus the maximum power cycle efficiency that can be obtained. Currently, synthetic oil (Therminol 

VP-1) is used in the trough technology as the HTF with an operating temperature of approximately 390°C. 

To achieve the near-term increased Rankine cycle efficiency the HTF will have to be changed to obtain the 

450°C inlet steam temperature. The SunLab projections assume a nitrate salt HTF with an upper operating range 

of 500°C, such as HitecXL, similar to the HTF used for the power tower technology. Use of nitrate salt has not 

been demonstrated for the trough technology. 

For the near-term, additional development and field testing is required on alternate HTFs for higher temperature 

applications. For the long-term, not only is alternate HTF development required but the current HCE absorber 

coating upper temperature limit is approximately 450°C, which will necessitate an advanced HCE coating for 

the projected 500°C operating temperature. 

D.3.4 Thermal to Power Plant Efficiency — Parasitics 

The parasitic electric consumption is reduced from 17.3% at SEGS VI to 8.4% in the near-term case and to 7.2% 

in the long-term case. The major reasons for the reductions are the following: 

• SEGS VI uses flex hoses for interconnection of collectors. Future plants will use ball joint 

assemblies. Ball joints reduce pressure drop in the collector loop by about 50%. Increasing from 

a 50-meter to a 150-meter collector length reduces the number of collector interconnections by 

3, thereby reducing the pressure drop. The HTF pumping parasitics is reduced from 5.9% of 

gross generation to 3.8%. 

• Changing the HTF from VP-1 to HitecXL reduces HTF pumping parasitics from 3.8% to 1.7%. 

This is based on a new solar field piping model developed by Nexant. 

• Additional plant parasitic reduction is assumed through further optimization of power plant 

motors and other electrical equipment through the use of more energy efficient components and 

control systems. Current parasitic models are based on the parasitics at the SEGS plants. 

Significant improvement in motors and other parasitic equipment have occurred in the last 

15 years. 

 

*

 Plant (commercial operation date): Nanaoota 1 (1995), Noshiro 2 (1995), Haramachi 1 (1997), Haramachi 2 (1998), 

Millmerran (2002), Matauura 2 (1997), Misumi 1 (1998), Tachibana Bay (2000), Bexback (2002), Lubeck (1995), Aledore 

1 (2000), Nordjylland (1998). From Power (Swanekamp 2002). 
 

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The efficiency improvements are based on 12 hours of thermal storage. The storage allows the plant to operate 

during non-insolation periods, thereby reducing thermal losses by minimizing the energy loss during plant 

start/stop cycles (thermal to plant power efficiency) and HTF heating during off-line periods. Even though 

efficiency improvements can be gained by thermal storage, additional direct costs will be incurred. First, the 

cost of the storage system is estimated to be between $20/kWht and $31/kWht (Price et al. 2002), and second, 

the collector area required will be approximately doubled for 12 hours storage capability. For a 33-MWe plant, 

approximately 1,060-MWht storage will be required for 12 hours storage at an estimated cost between 

$21,000,000 and $33,000,000 ($640/kWe and $1,000/kWe) and an increased collector cost of approximately 

$37,000,000 ($1,100/kWe). Offsetting the additional capital expenditures is the additional revenues for the extra 

electrical generation (approximately double for 12 hours of storage). 

D.3.5 Efficiency Improvements Summary 

The S&L evaluation is based on a less aggressive technology development approach, basing the maximum 

optical efficiency on the tested receiver tubes weighted absorptance of 94.4%, receiver coatings solar 

transmittances of 96.5%, mirror reflectivity of 93.5%, and mirror cleanliness factor of 95%. A comparison of 

SunLab and S&L efficiencies is illustrated in Table D-9. 

Table D-9 — Comparison of SunLab and S&L Efficiencies 

 SEGS 

VI 

Trough 

100 

Trough 

100 

Trough 

150 

Trough 

200 

Trough 

400 

 1999 2004 2007 2010 2015 2020 

Solar Field Efficiency SunLab 0.533 0.567 0.582 0.598 0.602 0.602 

 S&L 0.533 0.567 0.570 0.570 0.570 0.570 

Incidence Angle 0.873 0.873 0.873 0.873 0.873 0.873 

Solar Field Availability 0.990 0.990 0.990 0.990 0.990 0.990 

Other (IAM, row to row 

shadowing, end loss) 

 0.899 0.910 0.918 0.918 0.918 0.918 

Tracking Error and Twist 0.994 0.994 0.994 0.994 0.994 0.994 

Geometric Accuracy 0.980 0.980 0.980 0.980 0.980 0.980 

Mirror Reflectivity SunLab 0.935 0.935 0.935 0.950 0.950 0.950 

 S&L 0.935 0.935 0.935 0.935 0.935 0.935 
 

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 SEGS 

VI 

Trough 

100 

Trough 

100 

Trough 

150 

Trough 

200 

Trough 

400 

 1999 2004 2007 2010 2015 2020 

Mirror Cleanliness Factor SunLab 0.931 0.950 0.950 0.960 0.960 0.960 

 S&L 0.931 0.950 0.950 0.950 0.950 0.950 

Concentrator Factor 1.000 1.000 1.000 1.000 1.000 1.000 

Bellows Shadowing 0.971 0.971 0.971 0.971 0.971 0.971 

Dust on Envelope 0.980 0.985 0.985 0.985 0.985 0.985 

Envelope Transmissivity SunLab 0.925 0.965 0.970 0.970 0.970 0.970 

 S&L 0.925 0.965 0.965 0.965 0.965 0.965 

Receiver Solar Absorption SunLab 0.920 0.944 0.960 0.960 0.960 0.960 

 S&L 0.920 0.944 0.944 0.944 0.944 0.944 

Receiver Thermal Efficiency SunLab 0.729 0.859 0.862 0.852 0.853 0.853 

 S&L 0.729 0.843 0.823 0.810 0.810 0.810 

Piping Thermal Losses 0.961 0.965 0.967 0.967 0.968 0.968 

Storage Thermal Losses 1.000 0.991 0.997 0.996 0.996 0.996 

EPGS Efficiency 0.351 0.370 0.390 0.400 0.400 0.400 

Electric Parasitics 0.827 0.883 0.916 0.922 0.922 0.928 

Power Plant Availability 0.980 0.940 0.940 0.940 0.940 0.940 

Annual Solar-to-Electric SunLab 0.106 0.143 0.162 0.170 0.171 0.172 

Efficiency S&L 0.106 0.140 0.151 0.154 0.155 0.155 

While the SunLab efficiency improvements are theoretically reasonable, the 12 hours of thermal storage is 

problematic since it has not been commercially demonstrated for the higher solar field operating temperatures 

(approximately 390°C) of the later SEGS plants. Thermal storage is discussed in greater detail later in this 

report. 

The near-term (2007) efficiency improvement from 10.6% to 16.2%, based on available information, appears to 

be optimistic. A more conservative efficiency improvement, based on maximum optical efficiency on the tested 

receiver tubes weighted absorptance of 94.4%, receiver coatings solar transmittances of 96.5%, mirror 

reflectivity of 93.5%, and mirror cleanliness factor of 95%, is 15.1%. If an HCE performance improvements, 
 

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higher temperature HTF, and compatible thermal storage system can be developed and implemented in the nearterm, a 16.2% annual net solar-to-electric efficiency is feasible. Additional investigation and development of 

HCE, storage systems, including the optimum HTF for steam cycle efficiency and storage compatibility, is 

required to achieve the near-term efficiency projection. 

D.4 SOLAR FIELD — SUPPORT STRUCTURE 

D.4.1 Direct Capital Cost 

The SunLab projections for the structure material and erection are shown in the Table D-10. 

Table D-10 — SunLab Cost Projections 

 Reduction from

 SEGS VI $/kWe

SEGS VI $67/m2 — 420 

2004 $61/m2 9% 683 

2007 $57/m2 15% 591 

2010 $54/m2 19% 531 

2015 $50/m2 25% 489 

2020 $46/m2 31% 450 

The baseline cost of $67/m2

 is consistent with estimates prepared by Pilkington International (1999) indicating 

$63/m2

. Using $1,500 per ton for erected structural steel (National Construction Estimator 49th edition) results 

in a total direct cost of $12,400,000 for the SEGS VI 188,000-m2

 collector area, which is also consistent with 

the Pilkington estimate of $13,252,000 for a 209,280-m2

 collector area (209,280 m2/188,000 m2 x $12,400,000 = 

$13,785,000). 

Cost comparisons based on weight, as discussed in the following section, for the various structures are 

illustrated in Table D-11. 
 

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Table D-11 — Costs of Various Structures 

LS-2 $58/m2

LS-3 $66/m2

EuroTrough $58/m2

Duke Solar $48/m2

IST $48/m2

Additional cost reductions will be realized by minimization of the number of required parts, simplification of 

fabrication and field erection reducing labor costs for on-site assembly and erection. This cost reduction 

potential has not been quantified since there has not been an actual erection of a new collector structure. While 

the trough technology was commercialized for a brief period, no trough plants have been built in nearly a 

decade. There are active solar field suppliers, which will reduce costs through competition; however, structure 

cost reductions due to commercialization was not considered in this evaluation. 

D.4.2 Technology Improvements 

The Luz LS-3 collector was the final concentrator design used at the newest SEGS plants (SEGS VII–IX). The 

thermal performance and alignment maintainability of the LS-3 collector has not proved to be equal to the 

earlier LS-2 design used on the SEGS II–IX plants. There are at least three new parabolic trough collector 

structure designs under various stages of development: 

• EuroTrough (ASME 2001) 

• Duke Solar (Duke Solar 2000) 

• Industrial Solar Technology (IST 2001)) 

The new collectors concentrate on weight reduction and emphasize simplicity of fabrication and a minimum 

number of required parts. A weight comparison of the LS-2, LS-3, and the aforementioned new design 

structures is provided in Table D-12. 
 

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Table D-12 — Structure Weight Comparison 

Structure Weight 

(kg/m2

) Reduction 

LS-2 29 12% 

LS-3 33 Base 

IST 24 27% 

Eurotrough 29 12% 

Duke Solar 24 27% 

D.4.3 Scale-Up 

Structure cost reductions due to scale-up were not considered since the collector area for the same net annual 

solar-to-electric efficiency, and thus the structure, is directly proportional to the plant size. The collector area is 

inversely proportional to the efficiency and will influence the structure cost by reducing the collector area with 

the improvement of the efficiency. 

D.4.4 Production Volume 

The experience curve (Neij 1997) is related to the commercialization of the solar plants. The experience curve 

describes how unit costs decline with cumulative production, with a specific characteristic that cost declines by 

a constant percentage with each doubling of the total number of units produced. 

The formula is as follows: 

 CCUM = C0 x CUMb 

 Where: 

 CCUM = the cost per unit as a function of output 

 C0 = the cost of the first unit produced 

 CUM = the cumulative production over time 

 b = the experience index 

The cost reduction is (1-2b

) for each doubling of cumulative production, where the value (2b) is called the 

progress ratio (PR). PR is used to express the progress of cost reductions for different technologies. The lower 

the PR value the higher the cost reduction realized. The cost reductions refer to the total costs (labor, capital, 
 

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administration, research, etc.). Experience curves is not an established method, but a correlation that has been 

observed for several different technologies. Cost reductions were projected based on evaluation of technology 

improvements and experience curves. 

The SEGS solar field areas are shown below. The cumulative area indicates approximately five doublings were 

experienced for the SEGS plants. One of the criteria for the applicability of experience curves, according to the 

Neij literature (1997), is at least three doublings of production volume. 

Table D-13 — SEGS Solar Field Area 

SEGS Plant 

Number MW Solar Field Area, m2

Solar Field Area, 

m2 - Cumulative 

I 13.8 82,960 82,960 

II 30 190,338 273,298 

III 37 230,300 503,598 

IV 37 230,300 733,898 

V 39 250,500 984,398 

VI 35.5 188,000 1,172,398 

VII 35.5 194,280 1,366,678 

VIII 80 464,340 1,831,018 

IX 80 483,960 2,314,978 

There are recognized scale-up cost reductions for increasing the plant size: 

 $B = $A x (BMW/AMW)

Sf 

 Where: 

 Plant B is larger than Plant A 

 $B = cost of Plant B 

 $A = cost of Plant A 

 BMW = MW size of Plant B 

 AMW = MW size of Plant A 

 Sf = scale-up factor 
 

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Based on the cost data provided by the SEGS Plant (SEGS Data Package obtained during plant visit), an average 

scale-up factor of 0.7 was attained: SEGS I to SEGS II had a 0.6 scale-up factor; SEGS II to SEGS III, a 

0.8 scale-up factor; and SEGS V to SEGS VII, a 0.7 scale-up factor. The SEGS Cost Data in 2001 dollars from 

“Advances in Parabolic Trough Technology” (Price et al. 2002) show a savings of $1,643/kWe from SEGS VI 

to SEGS IX. Three doublings of the solar field area had occurred before SEGS VI. Using the average scale-up 

factor of 0.7, $1,447/kWe cost reduction was realized by plant scale-up. The majority of the remaining 

$196/kWe savings ($1,643/kWe – $1,447/ kWe = $196/ kWe) was assumed to be attributable to production 

volume cost reduction since there were no significant technological advances from SEGS VI to SEGS IX. 

Applying the SEGS VI solar field cost ($/m2

) to the SEGS IX plant and then reducing that cost by the $196/ 

kWe savings yielded a progress ratio (PR) value of 0.92. The Enermodal Study (undated) shows a PR range 

between 0.85 and 0.92 for the installed capital cost of a trough power plant. Arguably, for the highly automated 

manufactured components, such as the support structure, receiver tubes, and mirrors, a PR of 0.80, as used in the 

Neij literature (1997), may be more representative based on manufacturing experience. The S&L cost estimates 

for comparison to the SunLab model are based on a progress ratio (PR) value of 0.92 based on the estimated PR 

value from the SEGS cost data and since establishing an experience curve for a given component is somewhat 

speculative. A PR value of 0.92 will be more conservative, and if the actual PR value is less than 0.92 used in 

this evaluation, then the cost reductions will be greater than the estimated values. 

The initial starting point for estimating the cumulative production is the 2004 Technology Trough Plant. The 

cumulative production does not include the nine original SEGS plants because 10 years have elapsed since 

commercial production occurred for these plants. 

D.4.5 Cost Comparison 

A comparison of the SunLab projected costs are compared to the estimated cost based on a progress ratio of 0.92 

in Table D-14. 

Table D-14 — Support Structure Cost Comparison ($/m2) 

Year SunLab S&L 

SEGS VI 67 67 

2004 61 61 

2007 57 58 

2010 54 56 
 

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Year SunLab S&L 

2015 50 54 

2020 46 52 

The baseline cost of $67/m2 (SEGS VI) is consistent with estimates prepared by Pilkington International (1999) 

indicating $63/m2

. Cost comparisons based on weight for the various structures are illustrated below. Recent 

wind tunnel testing has provided improved data for use in optimizing the structural design, and reducing the 

weight, necessary for long-term reliability. Future designs may include more efficient integration of the 

reflectors into the overall structure, thus sharing the loads and reducing material requirements. Non-metallic 

materials are being considered, but may not be cost-effective. Additional cost reductions can be realized by 

minimization of the number of required parts and simplification of fabrication and field erection reducing labor 

costs for on-site assembly and erection. This cost reduction potential has not been quantified in this evaluation 

since there has not been an actual erection of a new collector structure. The individual metal parts of the 

structure can readily be manufactured by suppliers worldwide, leading to potential cost reductions through 

competition. However, structure cost reductions due to commercialization were not specifically considered in 

this evaluation. 

The estimated cost reductions are a result of the experience curve and indicate that the SunLab projected costs 

are reasonable. Even lower costs can be expected if lower structure weights, such as shown in Table D-12, are 

employed. Other potential cost reductions are simplification of fabrication and decreasing the number of 

required parts. 

D.5 SOLAR FIELD – HEAT COLLECTION ELEMENT (HCE) 

D.5.1 Direct Capital Cost 

The SunLab projected HCE deployment and costs are shown in Table D-15. 
 

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Table D-15 — SunLab Projected HCE Deployment and Costs 

SEGS VI Trough 

100

Trough 

100

Trough 

150

Trough 

200

Trough 

400

1999 2004 2007 2010 2015 2020

Number HCE 9,600 57,216 45,700 65,072 86,101 172,201 

Number HCE 

Accumulative 

9,600 66,816 112,516 177,588 263,688 435,889 

Cost, $/m2 field 43 43 34 28 22 18 

Cost, $/unit 847 847 762 635 508 400 

D.5.2 Technology Improvements 

The Solel UVAC HCE is considered the current state-of-the-art receiver and will be used in the new near-term 

trough plants. 

Sandia National Laboratories (SNL) is investigating new concepts in receiver design that could result in 

substantially lower-cost receivers with nearly the same high performance as the Solel receivers (Price and 

Kearney 1999). One of the SNL designs uses a high-temperature gasketing approach for connecting the glass 

envelope to the metal absorber, in place of the glass-to-metal seal. To reduce convective heat losses, the receiver 

annulus between the glass and metal tube would be pressurized with an inert gas. Although preliminary testing 

shows potential, extensive long-term field-testing is required on any new receiver design to evaluate and 

validate the reliability and also to assess whether the receiver’s life-cycle costs have been lowered. In the last 

couple of years, the focus of the research has returned to evacuated receiver designs. The focus now is on 

developing a more robust and lower-cost glass-to-metal seal design and on identifying higher temperature 

selective coatings with better thermo/optic properties. Sandia has identified new materials that could be used in 

the glass-to-metal seal to reduce the potential stress in the seal. In general, however, the current Housekeeper 

seal used in the HCE is very expensive and a significant part of the total receiver cost. Sandia has also identified 

some new glass-to-metal seal options that have the potential to be much lower in cost to manufacture and be 

more robust at the same time. NREL has been evaluating new selective coatings. Several new cermet coatings 

have been identified that may be easier to manufacture and have better thermo/optic properties. These are multilayer cermets as opposed to the graded cermet used by Solel. The graded cermets require a sputtered 

manufacturing process, whereas the multilayer coating can probably be deposited with simpler coating processes 

that facilitate better quality control of the final properties. NREL is also investigating changing the materials 
 

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used in the cermet to give better high temperature performance and stability. Both the design work and the 

coating development are being funded in the current DOE budget and will be continued next year. 

Alternate HCE designs (Zhang et al. 1998; Morales and Ajona 1998; San Vicent, Morales, and Gutiérrez 2001) 

are under various stages of development that indicate lower cost than the Solel UVAC HCE, although at reduced 

efficiency levels. Reduced HCE efficiency will result in a lower net annual solar-to-electric efficiency and 

require a larger collector area. Schott Glass, a large international supplier of specialty glass and related products, 

has recently announced its entry into the HCE supply market. However, start-up of HCE production is a 

significant cost, and a viable market growth is imperative to justify market entry for a new supplier. 

D.5.3 Scale-Up 

Cost reductions due to scale-up is not considered applicable since the collector area for the same net annual 

solar-to-electric efficiency, and thus the number of HCE, is directly proportional to the plant size. The collector 

area is inversely proportional to the efficiency and will influence the HCE cost by reducing the collector area 

with the improvement of the efficiency. 

D.5.4 Production Volume 

Cost reductions were projected based on evaluation of technology improvements and a progress ratio of 0.92. 

The Case 1 deployment values are used in the S&L evaluation. The Case 2 deployment values, used in the 

SunLab projections, are provided for comparison of the production volume between the two cases in Table 

D-16. 

Table D-16 — Number of HCE 

Number HCE, Cumulative 2004 2007 2010 2015 2020 

Case 1 Deployment 57,545 219,535 380,117 735,606 1,265,782 

Case 2 Deployment 57,545 219,535 520,817 1,076,652 2,225,366 
 

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D.5.5 Cost Comparison 

A comparison of the SunLab projected costs to the SunLab estimated costs are shown in Table D-17. 

Table D-17 — HCE Cost Comparison ($/unit) 

Year SunLab S&L 

2004 847 847 

2007 762 762 

2010 635 675 

2015 508 625 

2020 400 525 

D.6 SOLAR FIELD – MIRRORS 

D.6.1 Direct Capital Cost 

The SunLab projected mirror costs are shown in Table D-18. 

Table D-18 — SunLab Projected Mirrors Costs 

SEGS 

VI

Trough

100

Trough

100

Trough 

150

Trough 

200

Trough 

400

 1999 2004 2007 2010 2015 2020

Mirrors, $/m2 field 40 40 36 28 20 16 

D.6.2 Technology Improvements 

Alternatives to glass mirror reflectors have been in service and under development for more than 15 years. It is 

noted that all the identified alternatives are in various stages of initial development or testing. The major current 

developments are listed below. 

• Thin glass mirrors are as durable as a glass reflector and relatively lightweight in comparison to 

thick glass. However, the mirrors are more fragile, which increases handling costs and breakage 

losses. To address corrosion problems, new thin glass experimental samples were recently 

developed and are being tested under controlled conditions. 

• 3M is developing a nonmetallic, thin-film reflector that uses a multi-layer Radiant Film 

technology. The technology employs alternating co-extruded polymer layers of differing 

refractive indices to create a reflector without the need for a metal reflective layer. 3M plans to 
 

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develop an improved solar reflector with improved UV screening layers and a top layer 

hardcoat to improve outdoor durability. 

• ReflecTech and NREL are jointly developing a laminate reflector material that uses a 

commercial silvered-polymer reflector base material with a UV-screening film laminated to it to 

result in outdoor durability. Initial prototype accelerated-exposure test results have been 

promising, although additional work on material production is needed. The material would also 

benefit from a hardcoat for improved washability. 

• Luz Industries Israel created a front surface mirror that consists of a polymeric substrate with a 

metal or dielectric adhesion layer; a silver reflective layer; and a proprietary, dense, protective 

top hardcoat. 

• SAIC of McLean, Virginia, and NREL have been developing a material called Super Thin 

Glass. This is also a front-surface mirror concept with a hard coat protective layer. 

• Alanod of Germany has developed a front-surface aluminized reflector that uses a polished 

aluminum substrate, an enhanced aluminum reflective layer, and a protective oxidized alumina 

topcoat. These reflectors have inadequate durability in industrial environments. A product with 

a polymeric overcoat to protect the alumina layer has improved durability. 

Table D-19 summarizes the characteristics of the reflector technology alternatives. At this point, thick glass will 

likely remain the preferred approach for large-scale parabolic trough plants, although alternative reflector 

technologies may be more important in the future as more advanced trough concentrator designs are developed. 

Table D-19 — Alternate Mirror Technologies 

Weighted 

Reflectivity (%) Cost ($/m2

) Issues

Flabeg Thick Glass 94 40 Cost, breakage 

Thin Glass 93 – 96 15 – 40 Handling, breakage 

All-Polymeric 99 10 UV protective coating needed with hard coat 

ReflecTech Laminate >93 10 – 15 Hard coat and improved production 

Solel FSM >95 — Solel product durability currently unknown 

SAIC Super Thin Glass >95 10 Manufacturing scale-up 

Alanod ~90 <20 Reflectivity 

There are active mirror suppliers, which will reduce costs through competition, however mirror cost reductions 

due to commercialization was not considered in this evaluation. 
 

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D.6.3 Scale-Up 

Similar to the collectors, cost reductions due to scale-up are not considered applicable since the mirror area for 

the same net annual solar-to-electric efficiency, and thus the mirror area, is directly proportional to the plant 

size. The mirror area is inversely proportional to the efficiency and will influence the mirror cost by reducing 

the collector area with the improvement of the efficiency. 

D.6.4 Production Volume 

Cost reductions were projected based on evaluation of technology improvements and a progress ratio of 0.92. 

The Case 1 deployment values are used in the S&L evaluation. The Case 2 deployment values, used in the 

SunLab projections, are provided for comparison of the production volume between the two cases. These are 

shown in Table D-20. 

Table D-20 —Mirror Volume 

(Square Meters, Cumulative, Thousands)

2004 2007 2010 2015 2020

Case 1 Deployment 1,120 4,399 7,952 15,818 27,550 

Case 2 Deployment 1,120 4,399 11,066 23,365 48,782 

D.6.5 Cost Comparison 

A comparison of the SunLab projected costs are compared to the SunLab estimated costs in Table D-21. 

Table D-21 — Mirror Cost Comparison ($/m2) 

Year SunLab S&L 

2004 40 40 

2007 36 36 

2010 28 32 

2015 20 29 

2020 16 26 
 

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D.7 POWER BLOCK 

D.7.1 Direct Capital Cost 

The SunLab projected power block costs are shown in Table D-22. 

Table D-22 — SunLab Projected Power Block and Balance of Plant Costs 

SEGS VI 2004 2007 2010 2015 2020

Plant size, gross electric, MWe 33 110 110 165 220 440

Power Block, $/kWe 410 349 349 293 256 197 

Balance of Plant, $/kWe 248 203 203 171 149 115 

 Total, $/kWe 658 552 552 464 405 312 

There are multiple suppliers for the power block equipment, and costs will be market-driven. While a trough 

plant will benefit from competitive prices, power block cost reductions due to commercialization were not 

considered in this evaluation. 

D.7.2 Technology Improvements 

The power block is a conventional Rankine-cycle steam turbine. The Rankine-cycle steam turbine is an 

established technology with future major improvements focusing on increased inlet steam pressure and 

temperature conditions to increase the cycle efficiency. 

D.7.3 Scale-Up 

There are recognized scale-up cost reductions for the power block. Using the SOAPP software program, S&L 

estimated the scale-up factor for increasing the plant size from 100 MW to 400 MW, as depicted on Figure D-4. 

The projected SunLab values are included for comparative purposes. Power block costs (Figure D-4A) include 

the steam turbine and generator, steam turbine and generator auxiliaries, feedwater and condensate systems. 

Balance-of-plant costs (Figure D-4B) include general balance-of-plant equipment, condenser and cooling tower 

system, water treatment system, fire protection, piping, compressed air systems, closed cooling water system, 

plant control system, electrical equipment, and cranes and hoists. 
 

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Figure D-4A — Estimated Scale-Up Costs: Power Block ($/kW) 

y = 1275.8x-0.3145

150

200

250

300

350

400

100 150 200 250 300 350 400

Megawatts

$/kW

Power block costs include the steam turbine and generator, 

steam turbine and generator auxiliaries, feedwater and 

condensate systems

Figure D-4B — Estimated Scale-Up Costs: Balance-of-Plant ($/kW) 

y = 461.33x-0.1896

100

150

200

250

100 150 200 250 300 350 400

MW

$/kw

SunLab Projections Power (Calculated (SOAAP))

Balance of Plant costs include general balance of plant 

equipment, condenser and cooling tower system, water 

treatment system, fire protection, piping, compressed air 

systems,closed cooling water system, plant control 

system, electrical equipment, and cranes and hoists.
 

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The estimated costs based on the SOAPP program indicate that the SunLab projected costs for the power block 

are conservative (on the high side), approximately $50/kW higher than estimated by the SOAPP program. The 

SunLab power block cost estimates are based on a 1990 ABB quotation for a 100-MW steam turbine. The ABB 

quotation was escalated and scaled-up for the larger sizes. The SunLab power block cost estimates are based on 

dated information and the escalation and scale-up factors add to the uncertainty of the data with respect to 

current pricing. Equipment prices in the SOAPP program reflect 2001 actual costs. Since the SOAPP pricing is 

current, the SOAPP-generated costs were used in this evaluation. 

D.7.4 Production Volume 

Since a single steam turbine is supplied with each trough plant, production volume is not a consideration for cost 

reduction. 

D.7.5 Cost Comparison 

A comparison of the SunLab projected cost versus the SOAPP predicted $/kW for the power block plus the 

balance of plant is shown in Table D-23. 

Table D-23 — Power Block & BOP Cost Comparison 

Total Power Block + BOP 2004 – 2007 2010 2015 2020 

Plant size, MWe 100 150 200 400 

SunLab Projected, $/kWe 581 525 472 383 

SOAPP Estimate, $/kWe 499 450 399 346 

D.8 THERMAL STORAGE 

D.8.1 Direct Capital Cost 

The SunLab projected thermal storage costs are shown in Table D-24. Note that the SunLab projections are 

based on 12 hours of thermal storage for each case. 
 

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Table D-24 — SunLab Projected Thermal Storage Cost 

2004 2007 2010 2015 2020

Plant size, gross electric, MWe 110 110 165 220 440 

Storage, MWht 3,525 3,349 4,894 6,525 13,050 

Type Indirect 

Two-Tank 

Direct 

Two-Tank 

Direct 

Thermocline 

Direct 

Thermocline 

Direct 

Thermocline 

Heat Transfer Fluid VP-1/ Solar 

Salt 

HitecXL HitecXL HitecXL HitecXL 

HTF Temperature, °C 400 450 500 500 500 

SunLab Projected, $/kWh 27.18 12.68 11.73 11.73 11.73 t

 $/kWe 958 425 383 383 383 

Binary solar salt (sodium and potassium nitrate) is the same HTF as used for the power tower Solar Two project, 

whereas HitecXL is a ternary salt (sodium, potassium, and calcium nitrate). The main advantage of ternary salt 

is a lower freezing temperature (120°C) compared to 225°C for binary salt and a high HTF operating 

temperature of 500°C. Ternary salt costs approximately 2 times more than binary salt. 

The number of hours of storage impact on the total capital cost is illustrated below in Table D-25 for the year 

2004 case (100 MWe) with a two-tank indirect storage system. 

Table D-25 — Thermal Storage Impact on Cost 

Hours of Thermal Energy Storage

0 2 4 6 8 12 16

Annual Capacity Factor 32.0% 33.6% 37.8% 41.7% 46.7% 53.5% 54.1% 

Net Annual Generation, GWh 280.1 294.6 331.1 365.2 408.9 468.6 473.9 

Installed Capital Cost, $/kWe 2,816 3,074 3,471 3,867 4,280 4,859 5,190 

The impact of the type of storage system on the total capital cost is shown in Table D-26 for the year 2004 case 

(100 MWe) for 12 hours of storage. 
 

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Table D-26 —Type of Thermal Storage Impact on Cost 

Type of Thermal Storage System – 12 Hours 

Plant Capital Cost 

($/kWe) 

Two-Tank Indirect, VP-1 HTF, Solar Salt Storage 4,859 

Thermocline Indirect, VP-1 HTF, Solar Salt Storage 4,668 

Two-Tank Direct, Solar Salt (450°C) 4,427 

Direct Thermocline, Solar Salt (450°C) 4,115 

Direct Thermocline, HitecXL (500°C) 4,027 

As exemplified in Tables D-25 and D-26, the amount of storage and the type of storage have significant impacts 

on the total cost of the plant and are key considerations for cost reductions. 

D.8.2 Technology Improvements 

Thermal storage allows solar electricity to be dispatched to the times when it is needed most and allows solar 

plants to achieve higher annual capacity factors. Although the first commercial 14-MWe trough plant included 

thermal storage, a simple two-tank storage system that used the plant HTF for a storage media, later plants 

operated at higher temperatures that precluded the same method due to the higher vapor pressure and high cost 

of the HTF. No thermal storage technology has been commercially demonstrated for the higher solar field 

operating temperatures (approximately 400°C) required for more efficient steam cycles in the later SEGS plants. 

Various studies point to an indirect thermal storage system for near-term application where the heat from the 

collector field is transferred from the synthetic oil (VP-1) HTF to another thermal storage media, such as molten 

salt, which can be stored at atmospheric pressure (Kearney 2001a, 2001b; Sandia National Laboratories 2001; 

Nextant Inc. 2001). For the two-tank indirect system, heat from the collector field is transferred from the 

synthetic oil HTF to another thermal storage media, such as molten salt, which can be stored at atmospheric 

pressure. However, the molten salt storage temperature is limited by the synthetic oil HTF operating temperature 

of 390°C. The technological risk using the two-tank molten-salt storage system is low based on the successful 

utilization at the Solar Two plant but the cost of this system is high ($958/kWe for 2004 SunLab case). The 

thermocline system will also reduce the storage system costs with synthetic oil HTF and binary molten salt 

storage fluid by the elimination of one storage tank and the reduction in the fluid volume requirement compared 

to the indirect two-tank system. Estimates show a 35% reduction in the storage system cost ($31/kWht to 
 

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$20/kWht) using a thermocline system as opposed to a two-tank system (Sandia National Laboratories 2001; 

Kearney 2001a; Nextant Inc. 2001). 

The year 2007 projection for a direct two-tank storage will use HitecXL (ternary) HTF in both the solar field 

and the thermal storage system, eliminating the need for the heat exchangers between the solar field and storage 

system. In addition, the solar field can be operated to higher outlet temperatures (450°C), increasing the power 

cycle efficiency and further reducing the cost of thermal storage. The primary disadvantages are the high 

freezing temperature of the salt (120°C), higher heat losses from the solar field, concerns about the durability of 

the selective coating on the trough receivers, and the need for more expensive piping and materials to withstand 

the increased operating temperatures. 

Subsequent projections after the year 2007 use a direct thermocline system with HitecXL (ternary) solar salt as 

the storage media and HTF. The solar field can be operated to higher outlet temperatures (500°C), increasing the 

power cycle efficiency. The thermocline uses a single tank that is slightly larger than one of the tanks in the twotank system. A low-cost filler material, which is used to pack the single storage tank, acts as the primary thermal 

storage medium. The filler displaces the majority of the salt in the two-tank system. With the hot and cold fluid 

in a single tank, the thermocline storage system relies on thermal buoyancy to maintain thermal stratification. To 

date, a preliminary assessment was made on the potential impact that a thermocline storage system might have 

on the annual performance of the plant, and a more detailed analysis is in progress this year. However, this 

system will have similar concerns as the binary solar salt direct storage system. In addition to the development 

of a thermocline system, an advanced HCE will be required to obtain the 500°C HTF operating temperature. 

The use of HitecXL solar salt is a major factor in lowering costs for future trough plants in the SunLab 

projections. The benefits and risks of the use of HitecXL are summarized below. 

• Benefits: 

 Higher temperature – increases the power cycle efficiency 

 Single fluid in solar field and storage eliminates expensive heat exchanger required of 

earlier storage technology 

 Larger temperature difference across the solar field reduces the size of storage. 

 Molten-salt has better density and thermal capacity product reducing the amount of 

storage, shrinking flow rates and piping sizes, and heat losses. 
 

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• Risks: 

 Freeze protection in the solar field. The solar field must be maintained at temperatures 

higher than the freeze point. Impedance heating is envisioned for the HCEs. Nexant is 

currently working on a design for this. 

 Special O&M procedures are required to drain and refill loops for maintenance. 

 Solar salt corrodes graph-oil seals, and as such the current ball joints will not work with 

HitecXL. Sandia is working on flexhose and balljoint sealing options to resolve this issue. 

 The receiver selective coating needs to withstand higher temperatures. The Solel cermet 

coating will hold up to 500°C in vacuum. It is only when vacuum is lost that this is a 

problem. 

The SunLab technology forecasts assume future storage will be based on the using HitecXL directly in the solar 

field and thermal energy storage. A number of alternative storage technologies are currently under development. 

The Europeans have a thermal energy storage research and development focusing on the development of two 

thermal storage systems for troughs. The first is a system that uses concrete for the storage media. The second 

uses phase-change materials and could be applicable for use with direct steam in the solar field. SunLab has also 

been working on the development of a new class of organic salt HTFs. The organic fluids offer the potential 

advantage of a molten-salt that is liquid at room temperature, eliminating the major drawback of inorganic 

molten-salts like HitecXL. Cost and temperature stability appear to be the main hurdles for organic salt HTF. 

Although all of these storage options are in the early stages of development, they provide alternative paths to 

achieving cost targets in a range similar to HitecXL. 

D.8.3 Scale-Up 

Cost reductions due to scale-up are not considered applicable since the storage system size, for the same number 

of hours’ storage, is directly proportional to the plant size. The SunLab projections also change the type of 

storage system in the years 2004, 2007, and 2010, which will tend to negate near-term potential scale-up cost 

reduction. 

D.8.4 Production Volume 

The storage system is not a manufactured module but consists of individual single components combined to 

create a system. The SunLab projections show a constant $/kWht and $/kWhe for the direct thermocline system 

from the year 2010 and forward. 
 

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D.8.5 Cost Comparison 

Definitive cost estimates for an indirect two-tank storage system based on detailed design drawings and material 

takeoffs were developed by Nextant (2001). The unit costs were $36.40/kWht for 470 kWht system and 

$31/kWht for a 688-kWht system. The SunLab projection appears to be conservative (on the high side) based on 

the previous estimates. 

The direct two-tank storage value of $12.68/kWht in the SunLab projection also appears to be conservative (on 

the high side) based on the power tower estimated values of $8.65/kWht (Solar 50) and $8.25/kWht (Solar 100). 

The direct thermocline system value of $11.73/kWht also appears to be conservative (on the high side) based on 

the Nextant estimates, which indicate a 35% cost reduction ($8.37 kWht) going from a two-tank system to a 

thermocline system. 

Since the values used in the SunLab projections appear to be at least 25% higher than expected based on other 

thermal storage estimates, the SunLab values were used in the cost analysis. 

D.9 CAPITAL COST COMPARISON 

The SunLab model projects parabolic trough plant capital and O&M costs based on various technology 

advances and commercial deployment predictions. The SunLab projections are considered the best case analysis 

where the technology is optimized and a high deployment rate is achieved. S&L developed capital and O&M 

costs based on a more conservative approach whereby the technology improvements are limited to current 

demonstrated or tested improvements and with a lower rate of deployment than used in the SunLab model. The 

two sets of estimates, SunLab’s and S&L’s, provides a band in which the costs can be expected to be, assuming 

the parabolic trough technology reaches the projected levels of deployment. A comparison of key parameters 

used for the estimates is summarized on Table D-27. 

Table D-27 — Key Parameters Comparison 

2004 2007 2010 2015 2020

SunLab S&L SunLab S&L SunLab S&L SunLab S&L SunLab S&L

Deployment, MW 300 300 600 300 1,200 750 2,400 1,000 400 400 

Cumulative 

Deployment, MW 650 300 1,250 600 2,450 1,350 4,850 2,350 5,250 2,750 
 

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2004 2007 2010 2015 2020

SunLab S&L SunLab S&L SunLab S&L SunLab S&L SunLab S&L

Net Annual Solar 

Efficiency 14.2% 14.0% 16.1% 15.1% 17.0% 15.4% 17.1% 15.5% 17.2% 15.5%

HCE Cost, $/unit 847 847 762 762 635 675 508 625 400 525 

Mirror Cost, $/m2 40 40 36 36 28 32 20 29 16 26 

Table D-28 and Figure D-5 illustrates the SunLab projected total installed capital cost ($/kWe) compared to the 

more conservative S&L values. Figure D-5 also shows the total installed capital cost based on achieving the 

annual net efficiencies projected by SunLab, but not the projected cost reductions. The curves highlight the 

impact of the annual net efficiencies on the capital cost. The curves also indicate that additional cost reductions 

above and beyond the more conservative S&L values, due to technology improvements and increased 

deployment rates, will result in convergence of the capital costs toward the SunLab values. 

Table D-28 — Comparison of Total Investment Cost Estimates ($/kWe): 

SunLab vs. S&L 

 2004 2007 2010 2015 2020 

SunLab $ 4,859 $ 3,408 $ 2,876 $ 2,546 $ 2,221 

S&L – S&L Efficiencies 4,816 3,854 3,562 3,389 3,220 

S&L – SunLab Efficiencies 4,791 3,687 3,331 3,165 2,725 

S&L – No Storage 2,453 2,265 2,115 1,990 1,846 
 

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Figure D-5 — Capital Cost Comparison 

1,800

2,300

2,800

3,300

3,800

4,300

4,800

2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

Capital Cost, $/kWe

SunLab Values S&L Values with SunLab Efficiencies S&L Values with S&L efficiencies" No Storage

 

 Annual Net Solar to 

 Electric Efficiency

 SunLab S&L

2004 14.3% 14.0%

2007 16.2% 15.1%

2010 17.0% 15.4%

2015 17.1% 15.5%

12 hours thermal storage

No thermal storage

D.10 OPERATIONS AND MAINTENANCE 

Sargent & Lundy has reviewed the SunLab O&M cost model based on our experience with fossil and other 

power plant technologies and in the course of a site visit to KJC Operating Company, the operator of the five 

30-MWe trough projects located at Kramer Junction. KJC Operating Company provided proprietary information 

on the last five years of operation. The SunLab O&M estimate is based largely on the experience at the KJC 

Operating Company SEGS plants. The model assumes a stand-alone trough power plant (as opposed to the five 

co-located plants at Kramer Junction) and adjusts cost depending on the size of the solar field and total electric 

generation per year. It breaks out the specific staffing requirements for operations and maintenance crews for 

both the conventional power plant and for the solar field. Administrative staffing is also included. In addition to 

labor breakdown, the model breaks out service contracts, water treatment costs, spares and equipment costs, 

miscellaneous costs, and periodic capital equipment requirements. S&L conducted a detailed review of the 

SunLab model and compared it to general power industry experience. 
 

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The S&L O&M costs for comparison to the SunLab projections are based on the following: 

• Solar Field 

 The initial unit costs are based on the SunLab values, and cost reductions for years beyond 

2004 are based on a PR = 0.92 

 Replacement rate for the mirrors and HCE are based on the average actual replacement 

rates for SEGS III – VII for the period 1997–2001 

 The replacement rates for the balance of the solar field are based on the SunLab values 

• Power Block and Balance of Plant 

 Costs are based on S&L data for the respective MW size plant for the steam turbine 

systems and balance of plant 

• Water and Process 

 Costs are based on are based on the average actual costs for SEGS III – VII for the period 

1997–2001 

• Staffing, Services Contracts, Miscellaneous, and Capital Equipment 

 The costs are based on the SunLab values since the SunLab values were determined to be 

reasonable 

• Thermal Storage 

 The costs are based on 0.4% of the capital cost per annum 

Analyzing the two estimates revealed that the major component to account for the cost difference is the HCE 

replacement rate. Table D-29 shows a comparison of the SunLab and S&L projected replacement rates. 

Table D-29 — Projected Trough Receiver Replacement Rates 

Annual Failures 

(Percent of Field) Current 2004 2007 2010 2015 2020 

SunLab 3.5% 2.0% 1% 0.5% 0.5% 0.5% 

S&L 5.5% 5.5% 2.5% 1.5% 1.0% 0.5% 

The SunLab near-term values are not consistent with the average actual HCE replacement rate of 5.5% reported 

for SEGS III – VII for the period 1997–2001. 

Sargent & Lundy reviewed the actual receiver (HCE) replacement rate reported by KJC Operating Company 

over the last five years. The S&L evaluation is based on total HCE replacement reported for the SEGS III – VII 
 

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for the period 1997–2001. S&L’s evaluation is based on the current replacement rate experienced at all the 

SEGS plants, with step reductions in the replacement rate based on the following considerations: 

• The average actual HCE replacement rate of 5.5% was reported for SEGS III – VII for the 

period 1997–2001. The total HCE replacement includes breakage and fluorescence. 

Fluorescence is due to cermet coating failures. This failure is due to the existence of 

molybdenum in the original Luz cermet coating. Solel no longer uses molybdenum in the 

UVAC cermet coating, so this type of failure will presumably no longer occur. Eliminating 

replacements due to these failures reduces the site failure/replacement rate. 

• SunLab has used the SEGS VI plant as the baseline reference plant. The SEGS III – V plants 

had problems during initial startup and the early years of operation that caused bowing of the 

HCEs, which increased breakage at those plants. SEGS VII has had higher breakage on the LS3 half of the field, although the LS-2 failures are similar to SEGS VI. SEGS VI was the last full 

plant constructed with LS-2 collectors and represents the most mature version of this generation 

of collector technology. The HCE total replacement rate at SEGS VI during the 5 years is in the 

5.5% range. Discounting the fluorescence failures, the replacement rate was 4.2% over the 

5-year period. 

• The high HCE failure rate at the existing plants is in part due to issues that would not be found 

at a future plant. A significant portion of the failures has been due to the hydrogen remover 

(HR) device installed in the HCEs at SEGS VI – X, operational problems that caused bowing, 

and HCE installation procedures. The HR is no longer part of the HCEs provided by Solel. 

Based on these factors, it is very possible that future plants will have substantially lower HCE failure rates than 

currently found at the SEGS plants. The SunLab assumption of a 2% failure rate assumes that current 

approaches for reducing failures are successful. S&L believes this is an aggressive assumption that cannot be 

assured for future plants without the field data to verify the failure rate reduction. Using the current replacement 

rate at all the SEGS plants, with step reductions in the replacement rate, reflects the current conditions and 

allows for the aforementioned improvements to reduce the replacement rate. 

Additional development of the HCE will likely be necessary to achieve the future receiver reliability goals. The 

current glass-to-metal seal is one of the more expensive elements and the key failure point of the current 

receiver design. The current design, known as a Housekeeper seal, relies on a sharp metal point being inserted 

into a glass bead. Failures occur when concentrated light focuses on the seal and the differential expansion 

between the glass and metal causes the failure of the seal. New designs are currently under investigation that 

attempt to improve the match between the coefficient of thermal expansion of the metal and glass. Kramer 

Junction is currently testing a new design UVAC2 with a revised internal shield. 
 

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To achieve the SunLab projected replacement rates the reliability of the HCE will have to significantly improve. 

Figure D-6 compares the O&M costs and illustrates the impact of the HCE replacement rate. The O&M costs 

without thermal storage is included for informational purposes. 

Figure D-6 — Levelized O&M Cost Comparison 

0.008

0.013

0.018

0.023

0.028

0.033

0.038

2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

O&M Cost, $/kWe

SunLab Projection S&L - Based on S&L HCE Replacement S&L - Based on SunLab HCE Replacement No Storage

 

 

 HCE Replacement Rate

 SunLab S&L

2004 2.0% 5.5%

2007 1.0% 4.0%

2010 0.5% 2.5%

2015 0.5% 1.0%

12 hours thermal storage

No thermal storage

The reduction in O&M cost is primarily a result of the increase in plant size and the increase in annual plant 

capacity factor. The plant capacity increases directly as a result of the increases in thermal storage. Increasing 

the size (MWe) and capacity factor of the power plant incurs minimal increase in the fixed O&M expenses 

($/year). 

D.11 LEVELIZED ENERGY COSTS 

Figure D-7 illustrates the SunLab projected levelized energy cost ($/kWhe) compared to the S&L values. The 

figure also shows the levelized energy cost based on achieving the annual net efficiencies projected by SunLab. 
 

 D-43 

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For comparison, the estimated levelized energy cost for the trough plants without thermal storage is included to 

underscore the importance of thermal storage in the reduction of the levelized energy cost. 

Figure D-7 — Levelized Energy Costs 

0.04

0.05

0.06

0.07

0.08

0.09

0.1

0.11

0.12

0.13

2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

Levelized Energy Cost, $/kWhe

SunLab S&L - S&L Efficiencies S&L -SunLab Efficiencies S&L - Without Storage

 

 Annual Net Solar to 

 Electric Efficiency

 SunLab S&L

2004 14.3% 14.0%

2007 16.2% 15.1%

2010 17.0% 15.4%

2015 17.1% 15.5%

2020 17.2% 15.5%

12 hours thermal storage

No thermal storage

The curves highlight the impact of the annual net efficiencies on the levelized energy costs. The curves also 

indicate that additional cost reductions above and beyond the more conservative S&L values, due to technology 

improvements, reduced HCE replacement rates, and increased deployment rates, will result in further 

convergence of the levelized energy costs toward the projected SunLab values. 

Figure D-8 shows the levelized energy cost for the SunLab technology forecasts with a breakdown that shows 

the source of the cost reduction from plant scale-up, technology R&D, and cost reduction through learning. Of 

the projected cost reduction in 2020, plant scale-up is projected to provide 20% of the total cost reduction, 

technology development will provide over half of the cost reduction at 54%, and production volume and 

competition will provide approximately 26% of the cost reduction. 
 

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Figure D-8 — Breakdown of LEC Cost Reduction 

(Scale-Up, R&D, Volume Production) 

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

1989 2004 2007 2010 2015 2020

SEGS VI Near-Term

Scale-up R&D

Volume Production

20%

54%

26%

Figure D-9 below shows the importance of the five major cost components in reducing the LEC. 

Figure D-9 — Breakdown of LEC Cost Reduction 

(by Major Cost Component) 

19%

13%

26% 16%

20%

6%

Concentrator (19%)

Mirror (13%)

HCE (16%)

Storage (26%)

Power Block (20%)

Other (6%)
Appendix E 

Evaluation of Technology Improvements and 

Capital Cost Projections – Tower 
 

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E. EVALUATION OF TECHNOLOGY IMPROVEMENTS AND 

CAPITAL COST PROJECTIONS – TOWER 

CONTENTS 

Section Page

E.1 Cost Drivers .............................................................................................................................................E-1 

E.2 Deployment ..............................................................................................................................................E-5 

E.3 Efficiency .................................................................................................................................................E-8 

E.3.1 Efficiency Calculation......................................................................................................................E-8 

E.3.2 Net Annual Solar-to-Electric Efficiency Impact on Cost.................................................................E-9 

E.3.3 Steam Cycle (Electric Power Block) Efficiency ............................................................................E-12 

E.3.4 Collector and Receiver Efficiency .................................................................................................E-12 

E.3.5 Thermal to Power Plant Efficiency — Parasitics...........................................................................E-13 

E.3.6 Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab Model) ...................................E-13 

E.4 Collectors ...............................................................................................................................................E-16 

E.4.1 Direct Capital Cost.........................................................................................................................E-16 

E.4.2 Technology Improvements.............................................................................................................E-19 

E.4.3 Economy of Scale...........................................................................................................................E-20 

E.4.4 Estimate of Cost Reductions Due to Volume Production ..............................................................E-21 

E.4.5 Cost Comparisons ..........................................................................................................................E-24 

E.4.6 Cost Improvements ........................................................................................................................E-27 

E.4.7 Heliostat Cost Improvement Breakout by Category ......................................................................E-28

E.5 Power Tower Heliostat Cost Evaluation ................................................................................................E-34 

E.5.1 Mirrors............................................................................................................................................E-34 

E.5.2 Mirror Assembly ............................................................................................................................E-35 

E.5.3 Drives .............................................................................................................................................E-35 

E.5.4 Control and Communications.........................................................................................................E-38 

E.5.5 Production (Shop) Fabrication .......................................................................................................E-38 

E.5.6 Installation......................................................................................................................................E-40 
 

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E.5.7 Structural Steel, Pedestal and Other...............................................................................................E-41 

E.5.8 Overhead and Profit .......................................................................................................................E-42 

E.5.9 Capital Equipment and Tooling .....................................................................................................E-43 

E.6 Electrical Power Block...........................................................................................................................E-44 

E.6.1 Capital Cost....................................................................................................................................E-44 

E.6.2 Technology Improvements.............................................................................................................E-45 

E.6.3 Economy of Scale...........................................................................................................................E-47 

E.6.4 Cost Improvements ........................................................................................................................E-48 

E.7 Receiver..................................................................................................................................................E-49 

E.7.1 Capital Cost....................................................................................................................................E-49 

E.7.2 Technology Improvement ..............................................................................................................E-50 

E.7.3 Economy of Scale...........................................................................................................................E-52 

E.7.4 Production Volume ........................................................................................................................E-52 

E.7.5 Cost Comparison............................................................................................................................E-53 

E.7.6 Cost Improvements ........................................................................................................................E-53 

E.7.7 Receiver Efficiency Improvements................................................................................................E-54 

E.8 Thermal Storage.....................................................................................................................................E-55 

E.8.1 Capital Cost....................................................................................................................................E-55 

E.8.2 Technology Improvement ..............................................................................................................E-56 

E.8.3 Economy of Scale...........................................................................................................................E-57 

E.8.4 Production Volume ........................................................................................................................E-57 

E.8.5 Cost Improvements—Thermal Storage and Parasitic ....................................................................E-58 

E.8.6 Cost Improvements ........................................................................................................................E-58 

E.9 Steam Generator.....................................................................................................................................E-58 

E.9.1 Capital Cost....................................................................................................................................E-58 

E.9.2 Technology Improvement ..............................................................................................................E-59 

E.9.3 Economy of Scale...........................................................................................................................E-60 

E.9.4 Production Volume ........................................................................................................................E-61 

E.9.5 Cost Improvements ........................................................................................................................E-61 

E.10 Balance of Plant .....................................................................................................................................E-61 

E.10.1 Capital Cost....................................................................................................................................E-61 
 

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E.10.2 Technology Improvements.............................................................................................................E-62 

E.10.3 Economy of Scale...........................................................................................................................E-63 

E.10.4 Production Volume ........................................................................................................................E-63 

E.10.5 Cost Improvements ........................................................................................................................E-63 

E.11 Capital Cost Comparison .......................................................................................................................E-63 

E.12 Levelized Energy Cost ...........................................................................................................................E-64 
 

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E. EVALUATION OF TECHNOLOGY IMPROVEMENTS AND 

CAPITAL COST PROJECTIONS – TOWER 

E.1 COST DRIVERS 

The direct cost of a solar power tower is divided into the following major categories: 

• Structures and Improvements 

• Heliostat Field 

• Receiver System 

• Tower + piping system 

• Thermal Storage System 

• Steam Generator System 

• Electric Power Generation System 

• Master Control System 

• Balance-of-plant 

The solar field, electric power block, receiver, and thermal storage encompass approximately 80% of the total 

direct costs as shown in Figures E-1 and E-2. The major cost component is the heliostat field, which 

encompasses 43% of total costs for Solar Tres and 47% of total cost for Solar 220. The next two categories are 

electric power block (13% for Solar Tres and 20% for Solar 220) and receiver (18% for Solar Tres and 8% for 

Solar 220). Our review is to determine if the capital cost estimates prepared by SunLab were within a reasonable 

range based on our review of available studies and reports, the SunLab cost estimate and our due diligence 

experience. The focus was primarily on the major cost categories: heliostats, electric power block, and receiver. 

The cost estimate reductions projected by SunLab from 2004 to 2020 are shown in Figure E-3. 
 

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Figure E-1 — Capital Cost Categories for Solar Tres 

Figure E-2 — Capital Cost Categories for Solar 220 

Structures and Improvements

2%

Heliostat Field

47%

Receiver System

8%

Tower + piping system

6%

Thermal Storage System

13%

Steam Generator System

2%

Electric Power Generation

System

20%

Master Control System

0%

Balance of Plant

2%
 

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Figure E-3 — Direct Capital Cost Power Tower Solar Plant (Projected Years 2004 and 2020) 

The total installed cost estimate by SunLab is shown in Table E-1. The values presented for Solar Tres 

throughout the report assume that the plant is located in the United States and not in Spain to provide more 

consistent comparison. The cost estimate by S&L based on our review of the major cost drivers is shown in 

Table E-2. Shaded areas indicate differences between the S&L and SunLab estimates. 

Table E-1 — SunLab Capital Cost Estimate (Deployment of 8.7 GWe) 

Case Solar 

Tres USA Solar 50 Solar 100 Solar 200 Solar 220 

Year 2004 2006 2008 2012 2018 

Description Contingency 

Land Area, km2 1.1 3.4 6.6 13.7 13.9 

Field Area, m2 231,000 709,000 1,311,000 2,600,000 2,642,000 

Structures & Improvements, $M 20% $2.8 $4.1 $5.3 $7.2 $7.2 

Heliostat Field, $M 5% $33.5 $89.8 $139.8 $249.6 $198.8 
 

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Case Solar 

Tres USA Solar 50 Solar 100 Solar 200 Solar 220 

Year 2004 2006 2008 2012 2018 

Description Contingency 

Receiver, $M 10% $14.0 $19.8 $25.0 $36.9 $34.4 

Tower & Piping, $M 10% $2.8 $7.0 $11.9 $24.3 $24.3 

Thermal Storage, $M 10% $5.9 $18.7 $28.9 $56.3 $57.2 

Steam Generator, $M 10% $1.6 $3.7 $5.8 $9.4 $9.3 

Electric Power Block, $M 10% $10.0 $24.5 $40.0 $64.0 $83.6 

Master Control System, $M 10% $1.8 $1.8 $1.6 $1.6 $1.6 

Balance-of-plant, $M 10% $4.8 $6.5 $7.8 $9.6 $9.9 

Direct Costs, $M $77.3 $175.9 $266.1 $458.8 $426.3 

Engineering, Management & 

Development (7.8%), $M 

 $6.6 $13.7 $20.8 $35.8 $33.3 

Land (no cost for Solar Tres and 

Solar 50) ($5,000 per hectare), $M 

 $0 $0 $3.3 $6.9 $7.0 

Contingency, $M 7.7% $6.3 $13.5 $20.2 $34.1 $34.3 

Risk Pool (Only for Solar Tres) – 

(10%), $M 

 $7.7 $0 $0 $0 $0 

 

Total Cost – SunLab, $M $97.4 $203.1 $310.3 $535.6 $599.9 

Total Cost – SunLab, $/kWe $7,135 $4,063 $3,103 $2,678 $2,272 

Table E-2 — S&L Capital Cost Estimate (Deployment of 2.6 GWe) 

Case Solar 

Tres USA Solar 50 Solar 100 Solar 200 Solar 200 Solar 220 

 Year 2004 2007 2010 2015 2020 2020 

Description Contingency 

Land Area, km2 1.1 3.4 6.6 13.7 13.7 13.9 

Field Area, m2 244,966 742,703 1,366,100 2,667,099 2,667,099 2,789,322 

Structures & 

Improvements, $M 

20% $2.8 $4.1 $5.3 $7.2 $7.2 $7.2 

Heliostat Field, $M 10% $39.1 $111.7 $182.7 $330.0 $312.1 $263.0 

Receiver ( Boeing), $M 10% $16.0 $26.0 $34.0 $46.0 $46.0 $48.0 
 

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Case Solar 

Tres USA Solar 50 Solar 100 Solar 200 Solar 200 Solar 220 

 Year 2004 2007 2010 2015 2020 2020 

Description Contingency 

Tower & Piping, $M 10% $2.8 $7.0 $11.9 $24.3 $24.3 $24.3 

Thermal Storage, $M 10% $5.9 $18.7 $28.9 $56.3 $56.3 $57.2 

Steam Generator, $M 10% $1.6 $3.7 $5.8 $9.4 $9.4 $9.3 

Electric Power Block, $M 10% $7.6 $18.6 $30.8 $46.2 $46.2 $61.8 

Master Control System, $M 10% $1.8 $1.8 $1.6 $1.6 $1.6 $1.6 

Balance-of-plant, $M 10% $10.0 $24.5 $36.7 $33.8 $33.8 $36.5 

Direct Cost, $M $87.7 $216.1 $337.5 $554.7 $536.8 $508.9 

Engineering, Management 

& Development – 

(15%),$M 

20% $15.5 $38.1 $59.6 $97.9 $97.9 $89.9 

Land (no cost for Solar 

Tres and Solar 50) ($5,000 

per hectare), $M 

 $0.0 $0.0 $3.3 $6.9 $6.9 $7.1 

Contingency, $M 10% $12.1 $29.6 $46.2 $75.8 $74.0 $69.6 

Cost Reduction 

Contingency, $M 

15% $15.6 $14.2 $18.1 $2.7 $15.2 

Risk Pool – Upper (10% for 

Solar Tres /5% for Solar 

50), $M 

 $8.8 $10.8 $0.0 $0.0 $0.0 $0.0 

 

Total Cost – S&L, $M $124.1 $310.3 $460.8 $753.3 $718.2 $690.5 

Total Cost – S&L, $kWe $9,090 $6,205 $4,608 $3,766 $3,591 $3,139 

E.2 DEPLOYMENT 

The deployment projections used by SunLab to develop their cost estimate is based on deployment (commercial 

operation) of Solar Tres in 2004 with successive initial deployments in 2006 for Solar 50, 2008 for Solar 100, 

2012 for Solar 100 and 2018 for Solar 220 (see Table E-3). Deployment is dependent on Solar Tres being 

successful and on incorporating lessons learned into Solar 50 design. The duration between initial deployments 

from Solar Tres to Solar 50 and from Solar 50 to Solar 100 in the SunLab model allows only one year of 

operation. The duration between initial deployments should be at least two years to allow time to resolve 

operational issues, achieve dependable steady-state operation, and operate for a reasonable amount of time. The 
 

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S&L deployment projection taking these issues into consideration is shown in Table E-4. S&L’s projection is 

more conservative than the SunLab projection of 8.7 GWe. The S&L projected range is from a maximum 

deployment of 4.7 GWe to a minimum deployment of 1.2 GWe. The S&L base case is a deployment of 

2.6 GWe. 

Table E-3 — Power Tower Deployment Projection – SunLab 

MWe\ Year 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 2 3 300 314 

Solar 100 100 1 2 3 4 4 4 4 2 2 1 2,700 3,014 

Solar 200 200 1 1 1 3 3 4 4 5 4,400 7,414 

Solar 220 220 1 5 1,320 8,734 

 Total 13.5 0 50 100 250 200 300 400 600 600 600 800 800 900 1,020 1,000 1,100 8,734 
 

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Table E-4 — Power Tower Deployment Projection –S&L 

MWe\ Year 

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Installed (MWe) Cumulative (MWe) 

4.7 GWe 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 1 2 2 300 314 

Solar 100 100 1 1 2 2 3 4 1,300 1,614 

Solar 200 200 1 1 2 3 3 3 2,600 4,214 

Solar 220 220 1 1 440 4,654 

 Total 13.5 0 0 50 0 50 200 100 100 200 400 300 600 400 820 600 820 4,654 

 

2.6 GWe 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 1 1 1 2 2 400 414 

Solar 100 100 1 1 1 1 2 2 2 1,000 1,414 

Solar 200 200 1 1 1 1 2 1,200 2,614 

Solar 220 220 

 Total 13.5 0 0 50 0 50 150 50 200 200 100 300 200 300 200 200 400 2,614 

 

1.2 GW 

Solar Tres 13.5 1 13.5 14 

Solar 50 50 1 1 1 1 200 214 

Solar 100 100 1 1 1 1 400 614 

Solar 200 200 1 1 1 600 1,214 

Solar 220 220 0 0 

 Total 0 0 13.5 0 0 50 0 50 50 150 0 100 100 300 0 200 200 1,214 
 

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E.3 EFFICIENCY 

E.3.1 Efficiency Calculation 

The Solar Field is defined by the collector area in square meters (m2), which can be estimated by the simplified 

equation: 

 C = (kW d x CF x h) 

 eff x I 

 Where: 

 C = Collector area square meters (m2

) 

 kW d = electric generation design capacity, kilowatts 

 CF = Capacity Factor = kWeh actual /(kWd x 8,760) 

 h = hours per year (8,760) 

 eff = net annual efficiency, Solar to Electric 

 I = annual insolation (kWht/m2 ) 

 kWe = kilowatts electric 

 kWht = kilowatts thermal 

For a given plant size and capacity factor, the net annual efficiency is the determining factor in the collector 

area; as the efficiency increases, the collector area decreases on the same percentage basis. 

The annual net solar-to-electric efficiency determination and the efficiency of Solar Tres are shown in Table 

E-5. 

Table E-5 — Annual Solar-to-Electric Efficiency 

Solar Field 

 Mirror Reflectivity 93.5% 

 Field Optical Efficiency 64.6% 

 Field Availability 98.5% 

 Mirror Corrosion Avoidance 100% 

 Mirror Cleanliness 95% 

 Field High Wind Outage 99% 

Annual Heliostat Field Efficiency (HFE) 56.0% 
 

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Annual Receiver Efficiency (RE) 78.3% 

Annual Piping Efficiency (PE) 99.5% 

Annual Thermal Storage Efficiency (TSE) 98.3% 

Annual Electrical Steam Turbine Efficiency (ST) 40.3% 

Startup Efficiency (SE) 99.5% 

Parasitics ( P ) (1 - % auxiliary power consumed by plant) 86.4% 

Plant-wide Availability ( A ) 92.0% 

Annual solar-to-electric efficiency ( Enet ) 

( Enet ) = ( HFE ) x ( RE ) x ( PE) x (TSE) x ( ST ) x (SE) x ( P ) x ( A ) 

 13.7% 

The collector area is directly proportional to the plant megawatt size and the capacity factor, as evident in the 

preceding equation. There are economies of scale associated with increasing the plant megawatt size. To provide 

generation during non-solar periods and thereby increase the plant capacity factor, thermal storage is required. 

Thermal storage can reduce plant thermal losses by reducing the number of steam turbine start-stop cycles and 

decreasing the use of electrical heat tracing during no-load periods. 

E.3.2 Net Annual Solar-to-Electric Efficiency Impact on Cost 

The net annual solar-to-electric efficiency has a significant impact on the size of the collector field and hence the 

cost. The largest increase in efficiency is the step change from Solar Two to Solar Tres as shown in Figure E-4 

(7.9% to 13.1 %). The comparison of the SunLab and S&L projections for efficiency improvements is shown in 

Tables E-6 and E-7. In addition, S&L considered a worst case with limited improvements in efficiencies, which 

are given in Table E-8. The cost reduction based on S&L’s evaluation of the SunLab reference case is shown in 

Section E.3.6. The net annual solar-to-electric efficiency impact on collector field cost for each change in size 

plant is shown in Section E.3.6. 

Table E-6 – SunLab Net Solar-to-Electric Efficiency 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220 

Heliostat Field Efficiency 50.3% 56.0% 56.5% 56.3% 56.1% 57% 

 Mirror Reflectivity 90.7% 93.5% 94.0% 94.0% 95.0% 95.0% 

Field Efficiency 62.0% 64.6% 64.6% 63.7% 62.8% 62.8% 

Field Availability 98.0% 99.5% 99.0% 99.5% 99.5% 99.5% 
 

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Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220 

Mirror Corrosion 97.0% 100% 100% 100% 100% 100% 

 Mirror Cleanliness 95.0% 95.0% 95.0% 96.0% 96.0% 97.0% 

Field High Wind Outage 99.0% 99.0% 99.0% 99.0% 99.0% 99.0% 

Receiver Efficiency 76% 78.3% 80.9% 83.1% 83.5% 82.0% 

Piping Efficiency 99.0% 99.5% 99.5% 99.9% 99.9% 99.9% 

Thermal Storage Efficiency 97.0% 98.3% 99.5% 99.5% 99.5% 99.5% 

EPGS Efficiency 32.6% 40.3% 41.8% 42.3% 42.8% 46.1% 

Parasitic (Auxiliary Power) Efficiency 73.0% 86.4% 90.0% 90.0% 90.0% 90.0% 

Plant Wide Availability 90.0% 92.0% 94.0% 94.0% 94.0% 94.0% 

 

Net Annual Solar-to-Electric Efficiency 7.9% 13.7% 16.1% 16.6% 16.9% 18.1% 

Table E-7 — Sargent & Lundy Net Solar-to-Electric Efficiency — 

with Anticipated Improvements 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220 

Heliostat Field Efficiency 50.3% 56.0% 56.5% 56.0% 55.2% 55.2% 

 Mirror Reflectivity 90.7% 93.5% 94.0% 94.0% 94.0% 94.0% 

Field Efficiency 62.0% 64.6% 64.6% 63.7% 62.8% 62.8% 

Field Availability 98.0% 99.5% 99.0% 99.5% 99.5% 99.5% 

Mirror Corrosion 97.0% 100% 100% 100% 100% 100% 

 Mirror Cleanliness 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 

Field High Wind Outage 99.0% 99.0% 99.0% 99.0% 99.0% 99.0% 

Receiver Efficiency 76.0% 78.3% 80.9% 83.1% 83.5% 82.0% 

Piping Efficiency 99.0% 99.5% 99.5% 99.9% 99.9% 99.9% 

Thermal Storage Efficiency 97.0% 98.3% 99.5% 99.5% 99.5% 99.5% 

EPGS Efficiency 32.6% 38.0% 40.4% 41.2% 42.6% 45.4% 

Parasitic (Auxiliary Power) Efficiency 73.0% 86.4% 90.0% 90.0% 90.0% 90.0% 

Plant Wide Availability 90.0% 92.0% 94.0% 94.0% 94.0% 94.0% 

 

Net Annual Solar-to-Electric Efficiency 7.9% 13.0% 15.5% 16.1% 16.5% 17.3% 
 

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Table E-8 – Sargent & Lundy Net Solar-to-Electric Efficiency — 

with Limited Improvements 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220 

Heliostat Field Efficiency 50.3% 54.3% 54.6% 54.1% 53.3% 53.3% 

 Mirror Reflectivity 90.7% 90.7% 90.7% 90.7% 90.7% 90.7% 

Field Efficiency 62.0% 64.6% 64.6% 63.7% 62.8% 62.8% 

Field Availability 98.0% 98.5% 99.0% 99.5% 99.5% 99.5% 

Mirror Corrosion 97.0% 100% 100% 100% 100% 100% 

 Mirror Cleanliness 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 

Field High Wind Outage 99.0% 99.0% 99.0% 99.0% 99.0% 99.0% 

Receiver Efficiency 76.0% 78.3% 78.3% 78.3% 78.3% 78.3% 

Piping Efficiency 99.0% 99.5% 99.5% 99.9% 99.9% 99.9% 

Thermal Storage Efficiency 97.0% 98.3% 98.3% 99.5% 99.5% 99.5% 

EPGS Efficiency 32.6% 38.0% 40.4% 41.2% 42.6% 42.6% 

Parasitic (Auxiliary Power) Efficiency 73.0% 86.4% 90.0% 90.0% 90.0% 90.0% 

Plant Wide Availability 90.0% 92.0% 92.0% 92.0% 92.0% 92.0% 

 

Net Annual Solar-to-Electric Efficiency 7.9% 12.6% 14.0% 14.4% 14.6% 14.6% 
 

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Figure E-4 — Comparison of Annual Solar-to-Electrical Efficiency Technology Step Changes: 

SunLab vs. S&L 

7.9%

13.7%

16.1%

16.6%

16.9%

18.1%

13.0%

15.5%

16.1%

16.5%

17.3%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

18.0%

20.0%

Solar Two Solar Tres

USA

Solar 50 Solar 100 Solar 200 Solar 220

Sunlab

S&L

Parasitics - 30%

EPGS - 37%

Heliostat - 20%

Other - 14%

E.3.3 Steam Cycle (Electric Power Block) Efficiency 

Increases in the steam cycle efficiency provide the largest cost reduction to the collector field cost. Discussion of 

the efficiency improvements is provided in Section E.6.2. 

E.3.4 Collector and Receiver Efficiency 

Increases in collector and receiver efficiency provide the next largest cost reduction to the collector field cost. 

Discussion of the efficiency improvements for the collector system is provided in Section E.4.2 and for the 

receiver system in Section E.7.2. 
 

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E.3.5 Thermal to Power Plant Efficiency — Parasitics 

The efficiency improvements are based on 16 hours of thermal storage for Solar Tres and Solar 50 and 13 hours 

for Solar 100 and Solar 200. The storage allows the plant to operate during non-insolation periods, thereby 

reducing thermal losses by minimizing the energy loss during plant start/stop cycles (thermal to plant power 

efficiency) and HTF heating (parasitics) during off-line periods. Even though efficiency improvements can be 

gained by thermal storage, additional direct costs will be incurred. First, the cost of the storage system is 

estimated by SunLab to be $4,940/kWe for Solar Tres, and second, the collector area required will be more than 

doubled for 16 hours storage capability. The 16 hours of thermal storage is reasonable since Solar Two 

successfully demonstrated operation with 3 hours of thermal storage. Thermal storage is discussed in greater 

detail later in this report. 

E.3.6 Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab Model) 

Table E-9 — Solar Two to Solar Tres: 

Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab) 

 Solar 2 Solar Tres

Plant Size – Electrical, MWe 10 13.7 

Plant Size – Thermal, MWt 42 120 

Heliostat Capital Cost, $M — 33.5 

Field Area, m2 81,400 231,000 

Heliostat Cost per m2 — $145 

Net Solar-to-Electric Efficiency 7.9% 13.7% 

 

The efficiency improvement is a cost savings of $19.3 M (reduction of the field by 133,204 m2). 

The improvement is based on the following system improvements: 

Heliostat – 1.4% Receiver - 0.4% EPGS – 2.6% 

Parasitics – 2.1% Thermal Storage – 0.2% Piping – 0.1% Availability – 0.3% 
 

 E-14 

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Table E-10 — Solar Tres to Solar 50: 

Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab) 

 Solar Tres Solar 50

Plant Size – Electrical, MWe 13.7 50 

Plant Size – Thermal, MWt 120 380 

Heliostat Capital Cost, $M 33.5 89.8 

Field Area, m2 231,000 709,000 

Heliostat Cost per m2 $145 $127 

Net Solar-to-Electric Efficiency 13.7% 16.1% 

The efficiency improvement is a cost savings of $13.4 M (reduction of the field by 105,689 m2) 

The improvement is based on the following system improvements: 

Heliostat – 0.2% Receiver - 0.5% EPGS – 0.6% 

Parasitics – 0.6% Thermal Storage – 0.2% Piping – 0.1% Availability – 0.3% 

Table E-11 — Solar 50 to Solar 100: 

Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab) 

 Solar 50 Solar 100

Plant Size – Electrical, MWe 50 100 

Plant Size – Thermal, MWt 380 700 

Heliostat Capital Cost, $M 89.8 139.8 

Field Area, m2 709,000 1,311,000 

Heliostat Cost per m2 $127 $107 

Net Solar-to-Electric Efficiency 16.1% 16.6% 

The efficiency improvement is a cost savings of $4.2 M (reduction of the field by 39,488 m2) 

The improvement is based on the following system improvements: 

Heliostat – minus 0.1% (decrease in performance) Receiver - 0.6% EPGS – 0.2% 

Parasitics – 0% Thermal Storage – 0% Piping – 0% Availability – 0% 
 

 E-15 

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Table E-12 — Solar 100 to Solar 200: 

Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab) 

 Solar 100 Solar 200

Plant Size – Electrical, MWe 100 200 

Plant Size – Thermal, MWt 700 1,400 

Heliostat Capital Cost, $M 139.8 249.6 

Field Area, m2 1,311,000 2,606,000 

Heliostat Cost per m2 $107 $96 

Net Solar-to-Electric Efficiency 16.6% 16.9% 

The efficiency improvement is a cost savings of $4.4 M (reduction of the field by 46,260 m2) 

The improvement is based on the following system improvements: 

Heliostat – minus 0.1% (decrease in performance) Receiver - 0.1% EPGS – 0.2% 

Parasitics – 0% Thermal Storage – 0% Piping – 0% Availability – 0% 

Table E-13 — Solar 200 to Solar 220: 

Net Annual Solar-to-Electric Efficiency Impact on Cost (SunLab) 

 Solar 200 Solar 220

Plant Size – Electrical, MWe 200 220 

Plant Size – Thermal, MWt 1,400 1,400 

Heliostat Capital Cost, $M 249.6 198.8 

Field Area, m2 2,606,000 2,642,000 

Heliostat Cost per m2 $96 $75 

Net Solar-to-Electric Efficiency 16.9% 18.1% 

The efficiency improvement is a cost savings of $13.1 M (reduction of the field by 175,160 m2). 

The improvement is based on the following system improvements: 

Heliostat – 0.3% Receiver – minus 0.4% EPGS – 1.3% 

Parasitics – 0% Thermal Storage – 0% Piping – 0% Availability – 0% 
 

 E-16 

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E.4 COLLECTORS 

The first plants (Solar Tres and Solar 50) will use the 95-m2 heliostats. The heliostat size will be increased to 

148 m2

 for Solar 100. S&L’s evaluation focused on the capital costs and cost improvement for the 148-m2 

heliostat. The S&L review is primarily based on the SunLab model, the detailed cost models developed by AD 

Little (Arthur D. Little, 2001), Advanced Thermal Systems (1996), Solar Kinetics (1996), and the PeerlessWinsmith drive cost and technology improvement studies (Peerless-Winsmith 1996, 1999). The 150-m2

heliostat was then compared against the 95-m2

 heliostat. We reviewed the major cost components and provided 

a discussion of the assumptions and reasonableness of the cost estimate in Section E.5. 

AD Little (ADL) was contracted by the DOE to prepare a detailed cost estimate for the current 150-m2

 heliostat 

design from Advanced Thermal Systems (ATS). The study was based on detailed design drawings, material 

takeoff, and proven assembly techniques (Advanced Thermal Systems 1996). Manufacturers and vendors were 

contacted to develop and validate material costs. ADL used the detailed design information from ATS*

 (1996) to 

estimate the costs. This bottoms-up cost estimate is fairly rigorous and provides a fairly accurate cost estimate. 

S&L compared and evaluated the detailed cost models and developed a cost estimate. 

E.4.1 Direct Capital Cost 

The cost summary of material, labor, overhead, and profit for the SunLab cost estimate is compared to the ADL 

cost estimate in the Table E-14. A composite cost estimate was developed by S&L based on evaluation of the 

differences between the cost estimates. 

 

*

 The heliostat was developed by ATS under contract with the DOE. DOE funded the development of the ‘secondgeneration’ 53-m2

 heliostat. ARCO funded the design, development, and first prototype 95- and 148-m2 trackers for use as 

heliostats or PV trackers. Advanced Thermal Systems is a small company formed in 1985 by former ARCO engineers with 

licensing rights for the tracker technology. The early design was optimized to use the maximum number of commodity 

parts and provide the lowest possible cost for near-term deployment. Approximately 1000 solar trackers of this basic design 

have been built. Most were the 95-m2

 units. One hundred eight of the heliostats used at Solar Two were second-hand ATSbuilt trackers. 
 

 E-17 

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Figure E-5 — Heliostat Cost Drivers 

Mirrors

9%

Drives

25%

Structure

26%

Communications

4%

Production (Capital and 

Labor)

10%

Installation

11%

Corporate Overhead

15%

Table E-14 — 148 m2 Heliostat Direct Capital Cost: Comparison of SunLab and ADL 

Summary of Cost 

Comparison SunLab ADL S&L Discussion 

Collector Area (m2) 227,000 444,000 444,000 

Quantity (units) 1,534 3,000 3,000 

Mirrors $1,924 $1,976 $1,976 Mirror costs are based on vendor quotes and are the 

same as ADL 

Drive (azimuth) $4,035 $4,000 $4,035 Drive costs are based on vendor quotes. 

Drive (elevation) $1,250 $1,250 ADL cost estimate included a dual drive (azimuth 

and elevation). 

Structural Steel, 

Pedestal, & Other 

$5,887 $5,598 $5,887 The composite of structural steel, pedestal and other 

costs are about the same 

Communications $875 $875 The ADL estimate did not include communications. 

Labor $800 $1,552 $800 ADL included indirect costs whereas SunLab only 

includes direct costs. We used SunLab direct costs 

and increased Overhead & Profit to 20% to cover 

indirect costs. 
 

 E-18 

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Summary of Cost 

Comparison SunLab ADL S&L Discussion 

Capital Equipment 

and Tooling 

$863 $301 $912 The difference is attributed to ADL basing their cost 

on a supplier setting up a manufacturing facility 

whereas SunLab’s estimate is based on a local 

assembly shop associated with the construction 

project. (See Appendix E.5.9) 

Other Production 

Costs 

$419 $172 $419 SunLab other includes 3% for shipping, whereas 

ADL did not define other. 

Total Fabrication 

Costs 

$16,053 $13,599 $16,102 

Corporate 

Overhead 

$2,408 $3,334 3,211 SunLab is based on 15%, whereas ADL uses 25%. 

The S&L estimate is based on 20% since a local 

production shop will be set up as part of construction 

until the market for heliostats opens up. This will 

reduce corporate overhead costs. 

System Cost $18,461 $16,933 $19,322 

Installation $950 $2,036 $1,426 ADL estimate is more reasonable and higher than 

the SunLab estimate. 

Field Wiring $877 $877 The ADL estimate did not include field wiring; 

therefore, the SunLab cost estimate for field wiring 

was added for comparison 

Total Installed Cost $20,288 $18,969 $21,688 

Total Installed Cost 

per m2

 for 148-m2

heliostat 

$137 $128 $146 The estimated cost range is between $137 (SunLab 

estimate) and $146 (S&L estimate) for initial 

deployment of 148-m2

 heliostats. The difference 

between S&L and ADL is 7%. 

The cost estimates for both SunLab and ADL are based on the ATS detailed design drawings and material 

quantities. The material costs are essentially the same. The differences are labor, overhead, and capital for 

equipment and tooling. The S&L estimate is based on a local production facility being developed at or near the 

construction site. This assumption is reasonable for the first several deployments since it will be difficult to 

entice a reputable manufacturer to establish a production facility without firm commitments and significant 

quantities. SunLab used a contingency of +5%. S&L used a contingency of +10% based on the uncertainties 

associated with estimating costs. 

Therefore, S&L estimates that the direct cost estimate for initial deployment of a 148-m2

 heliostat is $146 per 

m2

, plus a contingency of 10% ($161 per m2). 
 

 E-19 

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The main difference between the 95-m2 and 148-m2 heliostat is size, therefore it is reasonable to estimate the 

95 m2

 cost by extrapolating the 148 m2 cost using a scaling factor. SunLab used a scaling factor of 0.8 as shown 

in Table E-9. As a component, structure, or plant increases in size the increase in cost is not linear. Typical 

scaling factors, based on industry experience, are about 0.7 (S&L uses 0.67 to 0.72 based on our experience with 

scaling of power generating plants, Boeing uses 0.7 to 0.8 based on their industrial experience). 

The direct cost estimate for initial deployment of a 95-m2

 heliostat is $160 per m2, plus a 10% contingency 

($176 per m2

). 

Table E-15 — Heliostat Cost Estimate Comparison: 

Direct Capital Cost – Initial Deployment Scale from 148 to 95 m2

SunLab Sargent & Lundy

Heliostat Size Heliostat 

Cost $/m2 Heliostat Cost $/m2

95 m2 (scaled from 148 m2 at 

a scaling factor of 0.8 

$14,214 $150 $15,168 $160 

148 m2 (from Table E-14) $20,288 $137 $21,688 $146 

The major cost categories of the SunLab cost estimate for heliostats as compared to ADL are evaluated and 

discussed in Section E.5. 

E.4.2 Technology Improvements 

The annual heliostat field efficiency projections based on the SunLab model for each new deployment is shown 

in Table E-16. The annual heliostat field efficiency is the product of all the factors beneath it. 

Table E-16 — Annual Heliostat Efficiency (SunLab vs. S&L) 

Solar 

One

Solar 

Two

Solar 

Tres USA

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Annual Heliostat Field 

Efficiency SunLab 58.1% 50.3% 56.0% 56.5% 56.3% 56.1% 57.0% 

 S&L — — 56.0% 56.5% 56.0% 55.2% 55.2% 
 

 E-20 

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Solar 

One

Solar 

Two

Solar 

Tres USA

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Mirror Reflectivity 

 SunLab 90.5% 90.7% 93.5% 94.0% 94.0% 94.5% 95.0% 

 S&L — — 93.5% 94.0% 94.0% 94.0% 94.0% 

Field Optical Efficiency

 SunLab 69.0% 62.0% 64.6% 64.6% 63.7% 62.8% 62.8% 

 S&L — — 64.6% 64.6% 63.7% 62.8% 62.8% 

Field Availability 

 SunLab 99.0% 98.0% 98.5% 99.0% 99.5% 99.5% 99.5% 

 S&L — — 98.5% 99.0% 99.5% 99.5% 99.5% 

Mirror Corrosion Avoidance

 SunLab 100.0% 97.0% 100.0% 100.0% 100.0% 100.0% 100.0% 

 S&L — — 100.0% 100.0% 100.0% 100.0% 100.0% 

Mirror Cleanliness 

 SunLab 95.0% 95.0% 95.0% 95.0% 95.5% 96.0% 97.0% 

 S&L — — 95.0% 95.0% 95.0 95.0% 95.0% 

Field High Wind Outage

 SunLab 99.0% 99.0% 99.0% 99.0% 99.0% 99.0% 99.0% 

 S&L — — 99.0% 99.0% 99.0% 99.0% 99.0% 

The increase in heliostat field efficiency is primarily based on increases in mirror reflectivity, field availability, 

and mirror cleanliness. The heliostat field efficiency at Solar Two was lower than at Solar One due to the re-use 

of equipment that had been abandoned for approximately 7 years, the use of second-hand PV trackers and 

uncurved mirrors, and a general lack of emphasis on the field because it had already been proven at Solar One 

(Reilly and Kolb 2001; Pacheco et al. 2002). The S&L evaluation of the efficiency for each deployment is 

shown in Section 5.6. 

E.4.3 Economy of Scale 

Cost improvements due to increasing the heliostat size goes from 95 m2 to 148 m2 (Solar 50 to Solar 100) are 

classed as scale improvements even though research, design, testing and manufacturing issues are associated 

with this change. The methodology to analyze this change is based on proven component scale-up techniques. 
 

 E-21 

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The scaling factor for going from the 95-m2 heliostat to the 148-m2 heliostat is shown in Table E-17. The cost 

projection for cost reduction due to scaling factor is reasonable since the scaling factor of 0.8 is more 

conservative than the industry standard of 0.7. 

Table E-17 — Heliostat Scaling Factors - Direct Capital Cost 

Economy of Scale Change from 95 to 148 m2

 (Solar 100) 

SunLab Sargent & Lundy

Heliostat Size Heliostat Cost $/m2 Size Heliostat Cost $/m2 Size

95 m2 $11,070 $117 95 $13,654 $144 ** 95 

148 m2 $15,783 $107 * 148 $19,466 $132 *** 148 

Scaling Factor 0.80 0.80 

* From Table E-11; SunLab cost estimate for Solar 100, 148-m2 heliostat 

** Estimated cost of 95-m2 heliostat based on progress ratio of 0.971 (see Table E-19) with deployment of 4.7 GWe 

*** Calculated based on scale-up from 95 m2 at $144 per m2 to $132 per m2

E.4.4 Estimate of Cost Reductions Due to Volume Production 

This section explores cost reduction for heliostats, which is based on the number of heliostats being 

manufactured. As the number of heliostats increases, the cost will be reduced. The quantity of heliostats being 

manufactured is dependent on the deployment of plants. Deployment projections are discussed in Section 3. 

Heliostat production (m2

) based on a range of deployments (2.2 GW to 7.1 GW) is shown in Figure E-6. 
 

 E-22 

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Figure E-6 — Cumulative Heliostat Production (m2) vs. Deployment Projections (installed GWe) 

0

20,000

40,000

60,000

80,000

100,000

120,000

2004

Solar Tres

2006

Solar 50

2008

Solar 100

2010 2012

Solar 200

2014 2016 2018

Solar 220

2020

Total Production Area (x 1000 m2)

1.2 GWe

2.6 GWe

4.7 GWe

8.7 GWe

E.4.4.1 Progress Ratio and Determination of Heliostat Costs 

Sargent & Lundy calculated the progress ratio for heliostats. Each cost component was evaluated and based on 

our detailed review of the SunLab and ADL detailed cost estimates (see Appendix E.5). The progress ratio ratios 

changes from the SunLab model are highlighted in Table E-18. For example, we did not concur with SunLab’s 

cost improvement for installation costs as discussed in Section E.5; therefore, we adjusted the progress ratio to 

1.0. The differences identified by S&L are as follows: 

• Drives (azimuth) - Adjusted based on Section E.5.3. 

• Structural Steel & Pedestal - SunLab projected a 5% weight improvement. There was no 

objective evidence; therefore, we projected a slight improvement for material quantity discounts 

(see Section E.5.7). 

• Insulation and Field Wiring - SunLab projects a cost reduction for installation. Based on our 

experience, cost reductions are not as easily achieved for construction activities as 

manufacturing process. 
 

 E-23 

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The progress ratio for each heliostat cost activity was calculated based on the SunLab cost estimate. S&L 

estimated the final cost based on our evaluation and industry experience. The progress ratio was then calculated. 

Table E-18 — Cost Improvements Due to Volume Production (148 m2) 

Initial 

Production 

Volume

Final 

Production 

Volume

 

Annual Production, m2 227,000 100,000,000 

Doubling Factor — 8.78 

SunLab Model S&L Evaluation

Initial Cost Final Cost PR* PR* Cost

Mirrors $1,924 $1,470 0.97 0.97 $1,472 

Drive (azimuth) $4,035 $1,670 0.90 0.94 $2,343 

Drive (elevation) $1,250 $990 0.97 0.97 $990 

Structural Steel $3,412 $2,930 0.98 0.99 $3,124 

Pedestal $1,705 $1,530 0.99 0.99 $1,561 

Other $770 $700 0.99 0.99 $700 

Communications $875 $630 0.96 0.96 $630 

Labor $800 $660 0.98 0.98 $660 

Capital Equipment & Tooling $863 $237 0.86 0.86 $237 

Other Production Costs $419 $298 0.96 0.96 $298 

Total Fabrication Costs $16,053 $11,114 0.96 — $12,015 

Corporate Overhead $2,408 $1,667 0.96 — $1,802 

System Cost $18,461 $12,782 0.96 0.96 $13,817 

Installation $950 $836 0.99 1.0 $950 

Field Wiring $877 $671 0.97 1.0 $877 

Total Installed Cost $20,288 $14,288 0.961 0.971 $16,739 ** 
 

 E-24 

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SunLab Model S&L Evaluation

Initial Cost Final Cost PR* PR* Cost

Total Installed Cost per m2 $137 $97 — — $113 

* Calculated based on the initial and final cost estimate 

** Includes adjustment is the difference between SunLab cost estimate and S&L: 7% as shown in Table E-14 

The SunLab cost estimate of cost improvement was based on a final production of 100,000,000 m2. The first 

deployment with 148-m2

 heliostats is Solar 100, which requires a collector field of 5,239,500 m2 for each plant. 

The cost projection for going from 227,000 m2

 to 5,239,000 m2 is shown in Table E-19. 

Table E-19 — Final Cost for First Deployment of 148-m2 Heliostats 

148 m2 – S&L Initial Final Doubling 

Factor PR

Volume, m2 227,000 100,000,000 8.78 0.971 

 Total Cost, $/m2 $146* $113 — — 

Volume, m2 227,000 5,239,500 4.53 0.971 

 Total Cost, $/m2 $146* $128 — — 

* From Table E-18 calculated based on progress ratio of 0.971 for volume of 5,239,500 m2 

E.4.5 Cost Comparisons 

The comparison of heliostat cost improvements from 2004 to 2020 for a cumulative deployment of 8.7 GWe is 

shown in Figure E-7. The range of progress ratios used for the comparison by S&L is between 0.85 and 0.96. 

Various studies on learning curves from actual data suggest that a progress ratio of 0.82 has been observed for 

photovoltaics (PV) and 0.82 for development of wind energy during early deployment (1980 to 1995). The 

higher end of the range is from the Enermodal study for the World Bank, which identified a PV of 0.96 and the 

Wind Learning Rates compiled by Kobos for development of wind plants. (See Section B.6 for additional 

discussion.) 

The progress ratio calculated for the S&L base case is 0.97 and 0.96 for 95-m2

 heliostats and 0.93 for 148-m2

heliostats. The average progress ratio calculated for SunLab is 0.93. These values fall within the range of 0.85 to 

0.96, as shown in Figure E-7. 
 

 E-25 

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Figure E-7 — Heliostat Cost Improvements (8.7 GWe) 

$145

$127

$96 $107

$75

$150

$108

$115

$129

$87

$160

$40

$60

$80

$100

$120

$140

$160

$180

2004

Solar Tres

2006

Solar 50

2008

Solar 100

2010 2012

Solar 200

2014 2016 2018

Solar 220

2020

Heliostat Cost ($/m2

)

Lower Range [PR-0.85]

Upper Range [PR-0.96]

S&L: 95 m2 

S&L: 148 m2

S&L 

Sunlab [PR-0.96]

95 m2

 heliostat 148 m2 heliostat

enhanced 148 m2 

heliostat

S&L [PR-0.97]

Sargent & Lundy estimated heliostat costs based on a detailed review of the SunLab and ADL cost estimates. 

Cost reductions were then calculated as shown in Figure E-8. 
 

 E-26 

 SL-5641 

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Figure E-8 — S&L Cost Estimate of Heliostats (Solar Tres to Solar 200) 

$/m2

Cummulative Production of 

Heliostats (m2

) Description

$146 227,000

Detailed Cost Estimate for 148-m2 

Heliostat (without contigency)

Solar Tres $160 227,000

Cost Estimate for 95-m2

 Heliosat 

(scaled at factor of 0.8)

95 m2

Solar 50

$144 2,712,000

Cost Estimate for 95-m2

 heliostat 

with cost reduction for increased 

production

Solar 100 $132 4,023,000

Cost Estimate for 148-m2

 Heliostat 

(scaled at 0.8)

148 m2

Solar 200

$113 44,450,000

Cost Estimate for 148-m2

 heliostat 

with cost reduction for increased 

production

The comparison between S&L and SunLab collector field costs is based on a maximum deployment: SunLab at 

8.7 GWe and S&L at 2.6 GWe. Heliostat costs for a range of deployment were calculated by S&L as shown in 

Figure E-9. The impact on the heliostat cost between 1.4 GWe and 4.7 GWe is about 6% for Solar 100 (2008), 

and 8.5% for Solar 220 (2018). 
 

 E-27 

 SL-5641 

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Figure E-9 — Heliostat Cost per m2 versus Deployment 

$60

$80

$100

$120

$140

$160

$180

2004

Solar Tres

2006

Solar 50

2008

Solar 100

2010 2012

Solar 200

2014 2016 2018

Solar 220

2020

$ per m2

1.4 GWe

2.6 GWe

4.7 GWe

8.7 GWe

8.7 GWe

Sargent & Lundy

Sunlab

diff. 8.5%

E.4.6 Cost Improvements 

Cost improvements for heliostats are evaluated against three categories: technical (efficiency and design 

optimization), economy of scale and volume production. The cost reductions determined by S&L for the 

heliostat are an average of 30% due to technical improvements, 19% for scale-up, and 51% for volume 

production. The cost improvements for heliostats based on each change in plant size are shown in Section E.4.7. 

The methodology of determining the cost breakout for heliostats is shown in Section E.4.7. The three categories 

were reviewed, and S&L assigned a percentage for each cost component. The total cost breakdown for the 

heliostat was then calculated based on the weighted average of the cost contribution of each component to the 

total cost. 
 

 E-28 

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E.4.7 Heliostat Cost Improvement Breakout by Category 

The heliostat cost improvement is summarized in the following table. 

Cost Improvement Summary 

Solar Two to 

Solar Tres 

Solar Tres to 

Solar 50 

Solar 50 to 

Solar 100 

Solar 100 to 

Solar 200 

Solar 200 to 

Solar 220 Average 

Technical 26% 11% 35% 5% 72% 29.8% 

Scaling 37% 0% 57% 0% 0% 18.6% 

Volume 37% 89% 8% 95% 28% 51.4% 

Table E-20 — Solar Two to Solar Tres: 

Heliostat Cost Improvement Breakout by Category 

Component Percent of 

Total Cost Technical Scaling Volume 

Production Basis

Mirrors 8.6% 100% The cost improvements are due to volume 

productions 

Drive (azimuth) 45.0% 50% 50% 0% The design is based on enhancement of a 

proven design. There will be technical 

improvements. The scaling factor is based 

on increasing the drive (48 m2

 to 95 m2) 

Drive (elevation) 4.9% 50% 50% 0% The design is based on enhancement of a 

proven design. There will be technical 

improvements. The scaling factor is based 

on increasing the drive (48 m2

 to 95 m2) 

Structural Steel 9.2% 0% 50% 50% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes and the scaling factor for a 

larger structure (48 m2

 to 95 m2) 

Pedestal 3.3% 0% 50% 50% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes and the scaling factor for a 

larger structure (48 m2

 to 95 m2) 

Other 1.3% 0% 50% 50% Cost improvement based on scaling factor 

(48 m2 to 95 m2) and volume production. 

Communications 4.7% 20% 0% 80% There will be technical improvements from 

operating experience and better 

production based on learning curve but 

the majority of the cost improvement will 

come from volume production. 
 

 E-29 

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Component Percent of 

Total Cost Technical Scaling Volume Production Basis

Labor 2.7% 0% 50% 50% Cost improvement is based on scaling 

factor (48 m2

 to 95 m2) and volume 

production. 

Capital Equipment 

& Tooling 

11.9% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Other Production 

Costs 

2.3% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Installation 2.2% 0% 50% 50% Cost improvement is based on scaling 

factor (48 m2

 to 95 m2) and volume 

production. 

Field Wiring 3.9% 0% 50% 50% Cost improvement is based on scaling 

factor (48 m2 to 95 m2) and volume 

production. 

Total (Weighted 

Average) 

— 26% 37% 37% 
 

 E-30 

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Table E-21 — Solar Tres to Solar 50: 

Heliostat Cost Improvement Breakout by Category 

Component Percent of 

Total Cost Technical Scaling Volume Production Basis 

Mirrors 8.6% 0% 0% 100% The cost improvements are due to volume 

productions 

Drive (azimuth) 45.0% 20% 0% 80% The design is based on enhancement of a 

proven design. There will be technical 

improvements but the majority of 

improvements will come from volume 

production. 

Drive (elevation) 4.9% 20% 0% 80% The design is based on enhancement of a 

proven design. There will be technical 

improvements but the majority of the cost 

improvements will come from volume 

production. 

Structural Steel 9.2% 0% 0% 100% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes. 

Pedestal 3.3% 0% 0% 100% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes 

Other 1.3% 0% 0% 100% Cost improvement based on volume 

production. 

Communications 4.7% 20% 0% 80% There will be technical improvements from 

operating experience and better 

production based on learning curve but 

the majority of the cost improvement will 

come from volume production. 

Labor 2.7% 0% 0% 100% All cost improvement is based on volume 

production. 

Capital Equipment 

& Tooling 

11.9% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Other Production 

Costs 

2.3% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Installation 2.2% 0% 0% 100% All cost improvement is based on volume 

production 

Field Wiring 3.9% 0% 0% 100% All cost improvement is based on volume 

production 

Total (Weighted 

Average) 

— 11% 0% 89% 
 

 E-31 

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Table E-22 — Solar 50 to Solar 100: 

Heliostat Cost Improvement Breakout by Category 

Component Percent of 

Total Cost Technical Scaling Volume Production Basis 

Mirrors 8.6% 100% 0% 0% The cost improvements are due to 

installation of thin mirrors to increase 

reflectivity 

Drive (azimuth) 45.0% 50% 50% 0% The design is based on enhancement of a 

proven design. There will be technical 

improvements. The scaling factor is based 

on increasing the drive (95 m2

 to 148 m2) 

Drive (elevation) 4.9% 50% 50% 0% The design is based on enhancement of a 

proven design. There will be technical 

improvements. The scaling factor is based 

on increasing the drive (95 m2

 to 148 m2) 

Structural Steel 9.2% 20% 80% 0% Cost improvement is based on design 

changes to accommodate the thin mirrors 

and the scaling factor for a larger structure 

(95 m2

 to 148 m2) 

Pedestal 3.3% 20% 80% 0% Cost improvement is based on design 

changes to accommodate the thin mirrors 

and the scaling factor for a larger structure 

(95 m2

 to 148 m2) 

Other 1.3% 0% 100% 0% Cost improvement based on scaling factor 

(95 m2

 to 148 m2) and volume production. 

Communications 4.7% 20% 0% 80% There will be technical improvements from 

operating experience and better 

production based on learning curve but 

the majority of the cost improvement will 

come from volume production. 

Labor 2.7% 0% 100% 0% Cost improvement is based on scaling 

factor (95 m2

 to 148 m2) 

Capital Equipment 

& Tooling 

11.9% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Other Production 

Costs 

2.3% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Installation 2.2% 0% 100% 0% Cost improvement is based on scaling 

factor (95 m2

 to 148 m2) 

Field Wiring 3.9% 0% 100% 0% Cost improvement is based on scaling 

factor (95 m2 to 148 m2) 

Total (Weighted 

Average) 

— 35% 57% 8% 
 

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Table E-23 — Solar 100 to Solar 200: 

Heliostat Cost Improvement Breakout by Category 

Component Percent of 

Total Cost Technical Scaling Volume Production Basis 

Mirrors 8.6% 0% 0% 100% The cost improvements are due to volume 

productions 

Drive (azimuth) 45.0% 10% 0% 90% The design is based on enhancement of a 

proven design. There will be technical 

improvements but the majority of 

improvements will come from volume 

production. 

Drive (elevation) 4.9% 10% 0% 90% The design is based on enhancement of a 

proven design. There will be technical 

improvements but the majority of the cost 

improvements will come from volume 

production. 

Structural Steel 9.2% 0% 0% 100% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes. 

Pedestal 3.3% 0% 0% 100% Cost improvement is based on purchasing 

large quantities of commercially available 

steel shapes 

Other 1.3% 0% 0% 100% Cost improvement based on volume 

production. 

Communications 4.7% 10% 0% 90% There will be technical improvements from 

operating experience and better 

production based on learning curve but 

the majority of the cost improvement will 

come from volume production. 

Labor 2.7% 0% 0% 100% All cost improvement is based on volume 

production. 

Capital Equipment 

& Tooling 

11.9% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Other Production 

Costs 

2.3% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Installation 2.2% 0% 0% 100% All cost improvement is based on volume 

production 

Field Wiring 3.9% 0% 0% 100% All cost improvement is based on volume 

production 

Total (Weighted 

Average) 

— 5% 0% 95% 
 

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Table E-24 — Solar 200 to Solar 220: 

Heliostat Cost Improvement Breakout by Category 

Component Percent of 

Total Cost Technical Scaling Volume Production Basis 

Mirrors 8.6% 100% 0% 0% The cost improvements are technical 

advances in developing an enhanced 

heliostat 

Drive (azimuth) 45.0% 100% 0% 0% The cost improvements are technical 

advances in developing an enhanced 

heliostat 

Drive (elevation) 4.9% 100% 0% 0% The cost improvements are technical 

advances in developing an enhanced 

heliostat 

Structural Steel 9.2% 100% 0% 0% The cost improvements are technical 

advances in developing an enhanced 

heliostat 

Pedestal 3.3% 100% 0% 0% The cost improvements are technical 

advances in developing an enhanced 

heliostat 

Other 1.3% 0% 0% 100% Cost improvement based on volume 

production. 

Communications 4.7% 10% 0% 90% There will be technical improvements from 

operating experience and better 

production based on learning curve but 

the majority of the cost improvement will 

come from volume production. 

Labor 2.7% 0% 0% 100% All cost improvement is based on volume 

production. 

Capital Equipment 

& Tooling 

11.9% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Other Production 

Costs 

2.3% 0% 0% 100% Cost improvement is based on better 

production techniques and the majority on 

volume production 

Installation 2.2% 0% 0% 100% All cost improvement is based on volume 

production 

Field Wiring 3.9% 0% 0% 100% All cost improvement is based on volume 

production 

Total (Weighted 

Average) 

— 72% 0% 28% 
 

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E.5 POWER TOWER HELIOSTAT COST EVALUATION 

E.5.1 Mirrors 

Mirror costs in the SunLab model are essentially the same as ADL for one plant deployment as shown in 

Table E-25. The mirror cost estimate has a medium to high degree of accuracy based on vendor supplied pricing 

quotes. The mid point of the range of quotes $1.00 to $1.50 per ft2

 was used by ADL. The cost improvement 

estimate based on quantity purchasing is a reasonable. The key difference between normal glass and that used 

for heliostats is that normal glass has iron whereas solar glass uses low iron. The manufacturers have the 

capability to manufacturer the glass, but the higher cost is due to a premium for shutting down production of 

normal glass and resetting for a production run of solar glass. Higher quantity of demand will increase the 

production run time for solar applications and reduce the premium cost. The SunLab estimate for cost 

improvement is $0.95 per ft2

 which is conservative since it is about twice the cost of normal glass of $0.47 

per ft2

 estimated by Head West Inc. (Arthur D. Little 2001), which still allows for $0.48 per ft2 premium for 

manufacturing production runs (see Table E-25). 

Glass mirrors are expensive and heavy. Research in alternate mirrors is required to reduce costs. The new 

mirrors must have the same or better optical quality and have the same durability as glass mirrors. Glass mirrors 

have proven at SEGS and the Solar demonstration plants have shown that with proper design there has been no 

long-term degradation of the reflective quality. The alternate glass must be able to withstand continuous 

washing without damaging the reflective surface. The SunLab model does not assume a technology change to 

lighter glass until Solar 200. 

Table E-25 — Mirrors: Cost Comparison between SunLab and ADL 

SunLab AD Little

Mirrors 

Cost

Production 

Volume 

(cumulative)

Cost

Production 

Volume 

(annual)

Base Plant $1.21 per ft2 

($13.02 per m2) 

227,000 m2

(1,534 units) 

$1.24 per ft2 

($13.35 per m2) 

440,000 m2

(3,000 units) 

Production Cost 

Improvement 

$0.95 per ft2

($10.20 per m2

) 

100,000,000 m2

(675,676 units) 

Not Studied 4,440,000 m2

(30,000 units) 

Description Single sheet mirror construction. There are four mirror assemblies with 25 

4’ x 4’ (1.49 m2

) mirrors for a total of 100 mirrors. 
 

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E.5.2 Mirror Assembly 

The mirror assembly is not a complex structure. The cross members and hat sections are commercially available 

and are assembled by welding. There are four mirror assemblies with 25 4’ x 4’ (1.49 m2

) mirrors for a total of 

100 mirrors. The mirrors, which are commercially available low lead reflective glass, are attached with RTV. 

The only risk is the integrity of the bond between the mirrors and metal. This risk is low; these are the same 

mirrors as SEGS and the RTV is upgraded based on improvements developed to solve wind damage. 

The carousel assembly system for mirrors has been used in the construction of about 13,000 mirror modules for 

95 m2

 trackers. The assembly of mirror will take place in a 10,000-ft2 building at or near the plant site. The 

details of the facility, equipment, process sequence, man-loading and time sequence is provided the SolMaT 

study done by Solar Kinetics, Inc. (1996) for 148 m2

. Solar Kinetics has independently documented their 

approach in the “Mirror Module Assembly Plan.” The results of the study are summarized below: 

• A list of major equipment required to build mirror modules is provided but there is no cost 

estimate. ATS stated that the $1 million estimate used by SunLab was reasonable. 

• Mirror module assembly estimate is 17 man-hours, which includes 10% fringe time and 20% 

down time. The estimate is based on 1,000 heliostats per year with two 6-day shifts working for 

32 weeks (5.5 per shift: 3.5 workers, 1 supervisor, and 1 QA inspector. The SunLab estimate is 

24 man-hours. 

• The rack assemble consists of the pedestal, torque tube assembly and rack. The ‘rack’ is 

everything above the pedestal. The materials are commercially available and assembled by 

welding. 

E.5.3 Drives 

The estimated cost of the drive and cost improvement from production volume are essentially the same as the 

ADL study as shown in Table E-26. ADL’s conclusion is based on discussions with vendors, specifically 

Peerless Winsmith and Hub City. ADL identified in their report that improvement in drive costs “are possible at 

higher volumes because this amount of business can justify a dedicated production facility.” ADL assumptions 

were $6,000 per unit for 1,000 annual production $4,000 per unit for 3,000 annual production, and $3,000 per 

unit for 30,000 annual production. The difference between the costs is that the SunLab cost estimate included a 

rotary azimuth drive and elevation drive whereas the ADL cost estimate included a dual axis drive. 
 

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Table E-26 — Drives: Cost Comparison between SunLab and ADL 

SunLab AD Little

Drives 

Cost

Production 

Volume 

(cumulative)

Cost

Production 

Volume 

(annual)

Base Plant $5,885 227,000 m2

(1,534 units) 

$4,000 440,000 m2

(3,000 units) 

Production Cost 

Improvement 

$3,030 100,000,000 m2

(675,676 units) 

$3,000 4,440,000 m2

(30,000 units) 

Description The current technology solution of ball screw, worm gear, or hydraulic 

drives for the azimuth and elevation drives. SunLab drive consists of a 

lower cost azimuth drive developed by Peerless Winsmith and a separate 

elevation drive. The ADL cost study included a single axis drive. 

The next generation drive (Solar Tres) design is a planocentric azimuth drive coupled with a scissor joint and 

ball screw actuator. NREL contracted with Peerless-Winsmith in 1996 to define and develop the manufacturing 

procedures and costs for a dual axis drive system with focus on more accurate cost information (DFMA 

Workshop, contract ACG-5-15209-01). Peerless-Winsmith has designed this lower cost drive for Sandia, and 

therefore, DOE owns the rights to the drive. The drives are still in the development stage; about ten drives have 

been built. Peerless-Winsmith has a contract presently to provide detailed price projections for 1,500 units. 

Winsmith developed new cost data for the low cost azimuth solar drive in October 1999 “Enhanced Azimuth 

Solar Drive Project for Sandia National Laboratories,” Contract Number BF-0031. The azimuth solar drive 

reflects the latest changes and improvements of the azimuth drive design, including o-ring seals and replacing 

the power transfer chain with eccentric drive shafts. The cost data were based on a detailed material list of parts, 

labor, and cost for pattern & tooling and cost improvements up to 500 units (see Table E-27). These costs are 

provided by the manufacturer based on detailed design and therefore have a fairly high accuracy. Winsmith 

stated, “The project team feels that given even higher quantities, further cost improvements can be obtained with 

higher tooling and equipment outlays.” 
 

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Table E-27 — Peerless Cost Estimates for Drives 

Cost for Ten Units Cost for 500 Units

 

Unit Cost

Pattern & 

Tooling

Total Cost

Unit Cost

Pattern & 

Tooling Total Cost

Worm & 

planocentric 

$5,331 $14,595/10 = 

$1,460 

$6,791 $4,064 $44,385/500 

= $89 

$4,153 

Planetary & 

planocentric 

$5,377 $14,595/10 = 

$1,460 

$6,797 $4,035 $44,385/500 

= $89 

$4,124 

Peerless-Winsmith designed, developed, and tested an azimuth drive in 1987 to handle loads for the 148-m2

heliostat. The drive has been used for various applications, including a few prototype trackers, a prototype ATS 

heliostat located at Sandia, and a few units for testing. The estimated cost (see Table E-28) for the next 

generation heliostat drive (Solar Tres) is reasonable based on the following: 

• Peerless cost estimate for the 148-m2

 azimuth drive (500 units) is $4,150 per unit. This is for a 

two-stage azimuth drive only, not for elevation drive. 

• SunLab cost estimate for the 148-m2

 azimuth drive (1,534 units) is $4,035 per unit. 

• Comparison of the SunLab cost estimate for 95 m2

 and 148 m2 indicates a scaling factor of 0.62 

based on weight (see Table E-28). This is within the range of an acceptable assumption. 

• Nook industries quoted a cost of $805 for 500 ball screws (elevation drives) for the 95-m2

heliostats. 

Table E-28 — Economy of Scale between the 95-m2 and 148-m2 Heliostat Drives 

Heliostat Size (m2) 95 148 

Heliostat Weight 10,890 16,490 

Rotary azimuth drive $3,400 $4,035 

Elevation drive pivot structure $400 $600 

Elevation drive actuator $750 $1,250 

Total Drive Cost $4,550 $5,885 

Scaling factor based on weight — 0.62 
 

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E.5.4 Control and Communications 

The SunLab cost estimate for control and communications is shown in Table E-29. ADL did not include the cost 

of control & communication in their estimate. 

Table E-29 — Control & Communications Cost 

SunLab AD Little 

Control & 

Communication Cost Production 

Volume Cost Production 

Volume 

Base Plant $875 227,000 m2

(1,534 units) 

Not 

included 

— 

Production Cost 

Improvement 

$640 100,000,000 m2

(675,676 units) 

— — 

The SunLab estimate is based on the following: 

• Logic Board & Controller: base is $300/production improvement is $130. 

• Encoders, wiring & enclosure – base is $305 / production is $260. 

• Two DC motors – base is $270 / production is $250. 

The cost improvements projected by SunLab are reasonable. The largest contributor to the cost improvement is 

the logic board & controller. The electronics business has shown significant cost improvements with increases in 

production (computer technology is an excellent example). The cost improvement has a progress ratio of 0.88, 

which is a conservative assumption. Average module technologies based on electronics are 0.80 (Neij 1997). 

The other cost improvements are within the range of expected cost improvements: encoders, wiring & enclosure 

– progress ratio of 0.98 and DC motors – progress ratio of 0.99. 

E.5.5 Production (Shop) Fabrication 

The cost comparison for production fabrication costs is shown in Table E-30. 
 

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Table E-30 — Production Fabrication Cost Comparison between SunLab and ADL 

SunLab AD Little 

Shop Fabrication 

Cost Production 

Volume Cost Production 

Volume 

Base Plant $800 227,000 m2

(1,534 units) 

$1,552 — 

Production Cost 

Improvement 

$345 100,000,000 m2

(675,676 units) 

— — 

The SunLab cost estimate is based on the following assumptions shown in Table E-31: 

Table E-31 — SunLab Assumptions 

Activity Base Case Production Volume 

Mirror Support 8 mhrs 4.9 mhrs 

Mirror Modules 24 mhrs 8.9 mhrs 

Total Manufacturing 32 mhrs 14 mhrs 

Labor Rate (including benefits) $25 $25 

The ADL cost estimate is based on the following assumptions: 

• Labor cost (direct and indirect): $1,552 

• Labor Rate (including benefits): Assembly - $12 per hour; Skilled Labor - $18 per hour; 

Average $15 per hour. 

• Total manufacturing (direct and indirect): 103 mhrs ($1,552/$15) 

The Solar Kinetics, Inc. cost estimate is based on the following assumptions: 

• A list of major equipment required to build mirror modules is provided but there is no cost 

estimate. 

• Heliostat assembly estimate is 18 man-hours (not including painting, final assembly and 

checkout, which SKI estimates at 1+3.3+1=5.3 hours or 23 hours total), which includes 10% 

fringe time and 20% down time. The estimate is based on 1,000 heliostats per year with two 6-

day shifts working for 32 weeks (6 per shift: 5 workers and 1 supervisor). 
 

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SunLab projection for the base case is reasonable based on the following observations: 

• The estimate for assembly hours (18 hrs) studied by Solar Kinetics is less than SunLab. 

• The ADL study can not be used as a comparison since it includes direct and indirect costs. 

• SunLab model is based on setting up the production facility at the site. ADL study is based on 

setting up an independent production facility. 

SunLab projection for volume production cost improvements is optimistic based on the following observations: 

• The Solar Kinetic estimate of 18 mnhrs is based on 1,000 heliostats per year. It is not likely that 

there will be a significant improvement in manhours as a result of increasing production by a 

factor of 6. 

E.5.6 Installation 

The installation cost estimate and comparison between SunLab and ADL is shown in Table E-32. 

Table E-32 — Installation Costs Comparison between SunLab and ADL 

SunLab AD Little

Installation & 

Checkout Cost

Production 

Volume 

(cumulative)

Cost Production 

Volume

Base Plant $1,827 227,000 m2

(1,534 units) 

$1,427 — 

Production Cost 

Improvement 

$1,167 100,000,000 m2

(675,676 units) 

— — 

The SunLab cost estimate is based on the following assumptions shown in Table E-33: 

Table E-33 — SunLab Cost Assumptions 

Activity Base Case Production Volume 

Foundation $200 $153 

Installation 

Pedestal 3 mhrs 2.3 mhrs 

Paint 2 mhrs 1.5 mhrs 

Final Assembly 24 mhrs 8.9 mhrs 
 

 E-41 

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Activity Base Case Production Volume 

Checkout/Startup 1 mhr 1 mhr 

Total Installation 30 mhrs 15 mhrs 

Labor Rate (including benefits) $25 $25 

Field Wiring $877 $671 

The ADL study was based on discussions with construction companies and their 2001 CostWorks analysis. The 

assumptions are as follows: 

• Installation: 4 hours with 3 workers = 12 man-hours 

• Labor Rate (including benefits): $15 

• Vendor quote to drill hole, place pedestal and concrete: $800 

• Cost of aerial lift: $447 (based on about 4 lifts a day at 5 ton crane rental of $1,738 per day) 

Note that the ADL study for installation cost does not add up correctly: (12 mhrs x $15 = $180) plus ($800) plus 

($447) equals $1,427 not $2,072 

The SunLab cost projection for the base case is lower than expected based on the following observations: 

• Comparison of the ADL and the SunLab cost estimates corrected for labor rate and field wiring 

indicate that ADL is higher (ADL is $1,622 and SunLab is $950) 

• The ADL cost estimate is based on vendor quotes 

The SunLab cost projection for volume is optimistic based on the following observations. S&L adjusted their 

cost estimate to compensate for these. 

• The main cost improvement is the final assembly from 24 man-hours to 8.9 man-hours, which is 

not realistic. Cost improvements would only be expected with improvement in assembly 

techniques, equipment, and tools and there is really not much to improve for the installation 

process. 

• Man-hour improvements are not as easily achieved for a construction activity as for a 

manufacturing process. 

E.5.7 Structural Steel, Pedestal and Other 

The SunLab cost projection for the base case (see Table E-34) is reasonable based on the following 

observations: 
 

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• There is a difference of $289 per unit for material costs of the structural steel, pedestal and other 

(see Table E-34). The difference is a result of two different cost estimating methods and is not 

significant (1.8% of total fabrication cost). 

• The estimate is based on actual design drawings and material costs 

Table E-34 — Structural Steel and Pedestal Cost Comparison 

Structural Steel, 

Pedestal, & Other 

SunLab 

Base Plant 

AD Little 

Base Plant 

Structural Steel $3,412 $2,122 

Pedestal $1,705 $1,330 

Other $770 $2,146 

 Total $5,887 $5,598 

The SunLab cost projection for volume is optimistic based on the following observations. S&L adjusted their 

cost estimate to compensate for this. 

• SunLab projects a 5% weight improvement in the structural steel and pedestal based on a more 

rigorous design and analysis. The cost improvement is from $138 per m2

 to $127 per m2. There 

was no objective information to evaluate this cost improvement. 

E.5.8 Overhead and Profit 

Table E-35 — Overhead and Profit 

SunLab AD Little

Base Plant Production Cost 

Improvement Base Plant Production Cost Improvement

Overhead and Profit 15% 15% 25% N/A 

Fixed Costs $5.83 per unit $1.60 per unit Included in 

Overhead and 

Profit 

— 

The financial assumptions for ADL are shown below: 
 

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Table E-36 — Financial Assumptions for ADL 

Equipment Depreciation 7 years 

Cost of Capital 15% 

Sales & Distribution 4% of sales 

General & Administrative 8% of sales 

R&D 0% of sales 

Insurance 1% of sales 

Federal Taxes 3% of sales 

State Taxes 1% of sales 

Net Profit 8% of sales 

Corporate Overhead 25% of sales 

The SunLab cost estimate is low based on the ADL cost estimate. S&L adjusted their estimate to compensate for 

this. 

E.5.9 Capital Equipment and Tooling 

Table E-37 — Capital Equipment and Tooling 

Capital Equipment and 

Tooling 

SunLab Base 

Plant 

AD Little 

Base Plant 

Production 1,534 3,000 

Engineering Design $259,000 — 

Manufacturing Facilities and 

Tooling 

$800,000 — 

Equipment Lease $200,000 — 

Field Computer and BCS 

System 

$150,000 — 

Total $1,400,000 $903,000 

Cost per Heliostat $912.65 $301 

The SunLab cost estimate is slightly less than the value shown in Table E-37. S&L adjusted their cost estimate 

to compensate for this. 
 

 E-44 

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The difference is attributed to ADL basing their cost on a supplier setting up a manufacturing facility whereas 

SunLab’s estimate is based on a local assembly shop associated with the construction project. 

Cost improvements based on volume production are shown in Figure E-10. 

Figure E-10 —Heliostat Capital Cost and Equipment Cost Reductions 

0

1

2

3

4

5

6

7

No. of Heliostats

Year

3,000

1

6,000

2

9,000

3

12,000

4

15,000

5

Cost ($/m2)

Cost per m2 95m2

Cost per m2 148 m2

E.6 ELECTRICAL POWER BLOCK 

E.6.1 Capital Cost 

Sargent & Lundy estimated the cost for the power block based on the SOAPP model,* compared it to our 

internal database, and then adjusted the output for labor and productivity rates in the Southwest. The results of 

 

*

 EPRI SOAPP is a fully integrated program for technology evaluation, conceptual design, costing, and financial analysis of 

combustion-turbine-based power plants for project and proposal development. SOAPP-CT integrates process design, 

costing, and financial analysis of combustion turbine simple- and combined-cycle power plants, including cogeneration. 

Sargent & Lundy developed SOAPP under contract to EPRI. 
 

 E-45 

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our review are shown in Table E-38 and Figure E-11. The power block costs include the steam turbine and 

generator, steam turbine and generator auxiliaries, feedwater, and condensate systems. 

Table E-38 — Capital Cost of Electrical Power Block 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Power Block MWe — 13.5 50 100 200 220 

SunLab $M — $10.0 $24.5 $40.0 $64.0 $83.6 

 $/kWe — $730 $490 $400 $320 $380 

S&L $M — $7.6 $18.6 $30.6 $46.2 $61.8 

 $/kWe — $563 $373 $306 $231 $281 

E.6.2 Technology Improvements 

E.6.2.1 Efficiencies 

The power block is a conventional Rankine-cycle steam turbine. The Rankine-cycle steam turbine is an 

established technology with future major improvements focusing on increased inlet steam pressure and 

temperature conditions to increase the cycle efficiency. 

The steam cycle foundation is the Rankine cycle. As the inlet steam conditions (pressure and temperature) 

increase, the Rankine cycle efficiency increases. The near-term steam cycle efficiency from 34% to 40.3% is 

predicated on increasing the inlet steam temperature from 510°C to without reheat 540°C with reheat. The longterm increase to 42.8% for Solar 200 is based on 540°C steam inlet temperature. The net steam turbine 

efficiency. The increase from Solar 200 (42.8%) to Solar 220 (46.1%) is based on 640°C steam inlet 

temperature with an advanced double reheat turbine. The summary of steam turbine efficiency projections is 

shown in Table E-39. 
 

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Table E-39 – Turbine Projected Efficiencies 

Solar 

One 

Solar 

Two 

Solar 

Tres 

USA Solar 50 

Solar 

100 

Solar 

200 

Solar 

220 

Design Details 1988 1999 2004 2006 2008 2012 2018 

Plant output, net, MWe 10 10 13.7 50 100 200 220 

Rankine Cycle 

 Pressure, Bar 125 125 125 125 125 180 300 

 Live steam Temp, °C 510 510 540 540 540 540 640 

 Reheat #1 Temp, °C — — 540 540 540 540 640 

 Reheat #2 Temp, °C — — — — — 540 640 

Rankine Cycle Design 

Point Efficiency 

 SunLab, % 32.0% 34.0% 40.3% 41.8% 42.3% 42.8% 46.1% 

 S&L, % — — 38.0% 40.6% 41.4% 42.8% 45.6% 

The net steam turbine efficiency (gross efficiency minus the percentage of parasitic power consumption required 

for plant operation) is accounted for by calculation of the parasitic consumption separately. The near-term 

turbine efficiency was verified by S&L based on the ABB-Brown Boveri heat balances (HTGD 582395, Sheets 

1-7) for SEGS IX, which show an efficiency of 37.7% (in LUZ International Limited 1990). The Rankine cycle 

efficiency gains for increasing the inlet steam temperature from 540°C to 640°C were verified by S&L by using 

General Electric STGPER software program (Version 4.08.00, January 2002). The results from the STGPER 

software for Solar 200 and Solar 220 were extrapolated to account for dual reheat turbines. The turbine 

efficiencies are summarized in Table E-39. 

The type of heat transfer fluid (HTF) determines the operational temperature and thus the maximum power cycle 

efficiency that can be obtained. The HTF molten nitrate salt (60 wt % NaNO3 and 40 wt % KNO3) nitrate salt 

used in Solar Two demonstrated that steam temperatures of 540°C were achieved (Pacheco et al. 2002); for 

example, test no. 5 at full flow conditions measured actual HTF at 557°C and steam temperature at 542°C. 
 

 E-47 

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E.6.2.2 Discussion 

There are no steam turbine technological risks in achieving the SunLab projected efficiencies. There are 

currently numerous steam turbines operating with steam inlet conditions over 250 bar pressure and 590°C 

temperature, with gross efficiencies over 44%.*

 The advance from Solar 200 to Solar 220 is based on current 

research on increasing the inlet steam pressure and temperature conditions. This increase in efficiency for steam 

turbines is technically feasible and should be available by 2018. The major issue will be the higher temperatures 

and impact on materials. 

E.6.3 Economy of Scale 

There are recognized scale-up cost reductions for the power block. Using the SOAPP software program and 

S&L’s internal database, the scale-up factor was estimated for the increasing the power block from 13.5 MW to 

200 MW, as depicted on Figure E-11. The S&L trend curve is expressed as: 

 Y = (1,275.8) x – 0.3145 

 Where: 

 Y = $/kW 

 x = MWe 

 

*

 Plant (commercial operation date): Nanaoota 1 (1995), Noshiro 2 (1995), Haramachi 1 (1997), Haramachi 2 (1998), 

Millmerran (2002), Matauura 2 (1997), Misumi 1 (1998), Tachibana Bay (2000), Bexback (2002), Lubeck (1995), Aledore 

1 (2000), Nordjylland (1998). From Power (Swanekamp 2002). 
 

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Figure E-11 — Capital Cost of Electrical Power Block 

$0

$100

$200

$300

$400

$500

$600

$700

$800

0 50 100 150 200 250

Megawatts

$/kW

S&L 

SunLab

Power block costs include the steam turbine and generator, 

steam turbine and generator auxiliaries, feedwater and 

condensate systems

Advanced Turbine Generator for Solar 220

SunLab - $320 per kW

S&L - $281 per kW

However, since a single steam turbine is supplied with each tower plant, production volume is not a 

consideration for cost reduction. 

E.6.4 Cost Improvements 

Cost improvements were evaluated by S&L against three categories: technical (efficiency and design 

optimization), economy of scale, and volume production. The cost reductions determined by S&L for the 

electric power block is an average of 18% due to technical improvements, 82% for scale-up, and 0% for volume 

production. The cost improvements for the electric power block based on step changes in plant size and 

breakdown comparison is shown in Section 5.7. 
 

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E.7 RECEIVER 

E.7.1 Capital Cost 

Table E-40 — Capital Cost of Receiver 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Receiver System Capital Cost –SunLab, $M $39.2 $9.1 $14.7 $23 $29.1 $39.4 $43.3 

Receiver System Capital Cost –S&L (based 

on Boeing), $M 

— — $16 $26 $34 $46 — 

Receiver System Capital Cost, $/kWt — — $133 $68 $49 $33 — 

The SunLab cost estimate for the capital cost for receiver is lower than the latest Boeing cost estimate. The 

SunLab cost estimate should be adjusted to be in accordance with the latest detailed Boeing cost estimate. S&L 

determined that the Boeing cost estimate is reasonable based on the following: 

• The cost estimate is based on actual costs from Solar Two, which adjustments to compensate for 

design improvements, manufacturing improvements, construction labor rates and escalation. 

• The cost estimate is based on detailed design drawings and material take-offs (bottoms up cost 

estimate), which provides a higher degree of accuracy. 

• Estimates for Solar 50, 100, and 200 receivers were developed from Solar Two and Solar Tres 

with appropriate scale up and available industry data. 

• Boeing is a key player in developing tower technology with present focus on Solar Tres 

• The business group that addresses CSP technology has the resources of one of the largest, 

reputable companies in the United States. 

• Boeing is presently spending significant money (not disclosed due to confidentiality) on 

industry research and development. They spent $2 million of funds for research on Solar Two. 
 

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E.7.2 Technology Improvement 

E.7.2.1 Efficiency 

Table E-41 — Receiver Efficiency 

Solar 

Two

Solar 

Tres Solar 50 Solar 100

Solar 

200

Solar 

220

 — 2004 2006 2008 2012 2018

Receiver Efficiency 76.0% 78.3% 80.9% 83.1% 83.5% 82.0% 

 Defocus, Dump, Startup, Clouds 90.0% 92.7% 93.4% 93.4% 93.4% 93.4% 

 Absorbance 93.0% 93.0% 93.0% 94.0% 94.5% 94.5% 

 Receiver Thermal Losses 90.7% 90.9% 93.1% 94.7% 94.7% 92.9% 

Change in Receiver Efficiency — 2.39% 2.53% 2.23% 0.44% -1.59%

Percent Change in Field Area — 0.4% 0.51% 0.96% 1.06% 0.81%

The increased efficiency is from the following: 

• Reduction in heat loss, which is approximately proportional to reduction in receiver surface area 

per incident power 

• Increase of receiver absorbtivity through Industry Research & Development (IR&D) 

• Decrease of receiver emissivity from selected coatings achieved through IR&D 

• High nickel tubes allow higher solar flux and smaller tube surface for Solar 200. 

• Improved heliostat aiming allows higher average flux on receiver 

• Gradual increase in solar flux as operating experience is gained from the preceding plant 

• Improved insulation and receiver header oven covers further reduces heat loss. 

The efficiency changes and basis for each change in plant size is shown in Section E.3.6. 

E.7.2.2 Other 

Solar Two demonstrated manufacturing, construction and operation of the molten salt tower receiver. The 

receiver system efficiency and thermal storage efficiency exceeded or met expectations. The feasibility of 

dispatchable solar power was proven. There were several problems encountered that have been evaluated and 

have been resolved for Solar Tres and future plants. 
 

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• Downcomer piping failed near a horizontal pipe section below the receiver. Both the receiver 

and the down-comer piping grow considerably as they heat up to the 1,050°F (565°C) operating 

temperature. The piping design did not adequately cover the downcomers thermal growth 

during heat-up and cool down cycles. Larger expansion loops and a material change eliminated 

this concern. 

• Receiver fill operation was changed from a flood fill to a more rapid serpentine fill technique. 

• A number of receiver tubes developed slow leaks due to intergranular corrosion (IGC). The new 

tube material eliminated this problem. 

• However, this change did not solve all receiver startup problems. As reported in “An Evaluation 

of Molten-Salt Power Towers Including Results of the Solar Two Project”: 

An inability to heat receiver header ovens to 450°F (232°C) often delayed introduction of salt 

into the receiver. In addition, frozen tubes (as revealed by the infrared camera) often delayed 

the transition from receiver fill to normal operation. During the downcomer outage, project 

personnel implemented a number of modifications, including changing the oven-to-tube seal, 

adding heat trace behind the tubes at the oven-to-tube interface, and adding baffles between 

oven covers. Since these modifications were only implemented on several of the west 

(windward) lower oven covers, they did not eliminate all receiver startup delays. The 

modifications did, however, indicate that receiver startup delays could be minimized or 

eliminated with some simple design changes. One simple change would be to locate the tube 

clips away from the oven-to-tube interface area, since the tube clips represent a heat sink, 

which is hard to heat when located at this interface. Another modification would be to change 

the oven-to-tube sealing technique. 

Design improvements for Solar Tres include the following: 

• Change from 316SS to high nickel alloy tubes, which allows higher peak solar flux and is 

“essentially immune” to chloride stress corrosion cracking (Boeing undated). The new material 

was tested at Sandia and in Solar Two in a full size panel. 

• Redesign with inexpensive receiver cover ovens 

• Improved inlet vessel operational design (Boeing patent pending) 

• Simpler header design with fewer subcomponent parts (Boeing patent pending) 

• Reduction of piping and valves. 
 

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E.7.3 Economy of Scale 

Table E-42 — Economies of Scale (Boeing) 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Receiver Surface Area, m2 — 100 269 710 1,120 1,960 1,960 

Receiver System Capital Cost, $1,000/m2 — $91 $59 $37 $30 $23 $24 

Receiver System Capital Cost –Boeing, $M — $9.1 $16.0 $26.0 $34.0 $46.0 $48.3 

Receiver System Capital Cost with a Scaling 

Factor of 0.7 (calculated from Solar Two 

based on increase in surface area) 

— — $18.2 $31.6 $35.8 $50.3 $50.8 

Boeing, based on their experience in manufacturing receivers and similar components, used a scaling factor of 

0.7. The estimated capital cost for receivers was calculated based on a scaling factor of 0.7, as shown in Table 

E-42. The difference between the capital cost calculated with a scale-up of 0.7 and the projected capital cost is a 

cost reduction, which is attributed to technical and volume production; for example, the receiver cost for Solar 

50 is estimated to be $26 million. The cost projection based on a scaling factor of 0.7 would be $31.6 million 

[Receiver Cost for Solar 100 = $16 x (710/269) 0.7 = $31.6 million]. The difference is $5.6, which is attributed to 

technical improvements and production volume, as discussed in Section E.7.4. 

E.7.4 Production Volume 

Since only one receiver is manufactured for each plant, production volume is not a consideration for cost 

improvement when evaluating a single plant. However, fabrication learning curve from previous projects will 

provide cost improvements due to the repetitive assembly related with manufacturing receiver panels and their 

subcomponent parts. For example, in Solar Tres, 6,000 clips are welded onto 850 individual tubes that are then 

welded to 34 headers, which are part of 17 identical receiver panels. Boeing is expecting 85% to 90% learning 

curve based on previous experience. Boeing has also identified cost improvements due to improved 

manufacturing tooling and automation and quantity discount of material, which are reasonable assumptions. 

Material and components are about 35% of receiver costs. 
 

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Table E-43 — Effect of Production Volume (Percent of Total Savings) 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Fabrication Learning Curve, % — — 5% 9% 7% 3% — 

Improved Manufacturing Tools and 

Automation, % 

— — 2% 3% 3% 1% — 

Quantity discount of material, % — — 0% 2% 2% 1% — 

 Total, % — — 7% 14% 12% 5% — 

E.7.5 Cost Comparison 

Table E-44 — Total Installed Cost 

Case Solar 

Tres USA Solar 50 Solar 100 Solar 200 Solar 220 

Year 2004 2006 2008 2012 2018 

Receiver – Boeing, $M $16.0 $26.0 $34.0 $46.0 $48.3 

Receiver – SunLab, $M $14.0 $19.8 $25.0 $36.9 $34.4 

E.7.6 Cost Improvements 

Cost Improvements are evaluated against three categories: technical (efficiency and design optimization), 

economy of scale and volume production. The cost reduction determined by S&L for the receiver is an average 

of 46% due to technical, 40% due to scale-up and 14% due to volume production. The method used by S&L is 

shown below, and the detailed calculation is shown in Section E.7.7. 

 Cost Savings = Cost Savings from Technical + Cost Savings from Scale-up + Cost savings from 

 Volume Production 

 Where: 

 Cost savings from Technical = Cost savings due to receiver flux increase + Cost savings due 

 to receiver improved efficiency + Cost savings in heliostat field 

 size due to improvements in receiver efficiency. 

 Cost savings from Scale-up = Capital cost based on 0.7 scaling factor minus Capital cost 

 based on 1.0 scaling factor 
 

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 Cost savings from Volume Production = Cost savings from manufacturing receiver panels and 

 subcomponent parts. 

The cost improvements and basis for the improvements for each change in plant size are shown in Section 5.6. 

E.7.7 Receiver Efficiency Improvements 

Table E-45 — Sargent & Lundy Determination of Receiver Cost Reduction Breakout 

 Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 Abbr. 1988 1999 2004 2006 2008 2012 2018 

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Receiver Surface Area, m2 — 100 269 710 1,120 1,960 34.4 

Receiver Peak Incident Flux, MW/m2 0.45 0.8 0.95 1.2 1.4 1.6 1.6 

Ratio Average/Peak Incident Flux 43% 60% 51% 50% 50% 50% 50% 

Receiver Average Incident Flux, MW/m2 0.20 0.48 0.49 0.6 0.7 0.8 0.8 

Receiver Efficiency (annual) 64.8% 76% 78.2% 79.9% 82.3% 83.2% 81.3% 

 

Receiver System Capital Cost –Boeing, 

$M 

TC — $9.1 $16.0 $26.0 $34.0 $46.0 $48.3 

Receiver Capital Cost with a Scaling 

Factor of 0.7 (calculated from Solar Two 

based on increase in surface area), $M 

TCS — — $18.2 $31.6 $35.8 $50.3 $50.8 

Receiver Capital Cost without a scaling 

factor (e.g., scaling factor = 1), $M 

TCNS — — $24.5 $42.3 $41.0 $59.5 $60.4 

Cost Savings from scaling factor 

[CSs = TCs – TCNS] 

CSS — — $6.3 $10.7 $5.2 $9.2 $9.6 

 

Receiver Cost Savings from Smaller 

Receivers due to higher flux levels 

 

Area with Solar Two avg. flux, m2 — — 274 893 1,643 3,285 3,336 

Cost with Solar Two avg. flux and 

scaling factor, $M 

TCS+F — — $18.5 $37.0 $46.8 $72.2 $73.0 

Cost savings from flux increase 

[CSF = TCS –TCS+F], $M 

CSF — — 0.26 5.48 11.00 21.91 22.15 

 
 

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 Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 Abbr. 1988 1999 2004 2006 2008 2012 2018 

Receiver cost savings from increased 

efficiency due to higher flux levels 

 

Area with Solar Two avg. flux, m2 — — 277 747 1,213 2,148 2,129 

Cost with Solar Two avg. flux and 

scaling factor, $M 

TCS+RE — — 18.6 32.7 37.8 53.6 48.7 

Cost savings from flux increase 

[CSRE = TCS -TCS+RE], $M 

CSRE — — 0.38 1.14 2.06 3.33 -2.10 

 

Heliostat cost savings (collector area) 

from increased receiver efficiency – from 

Table E-8), $M 

CSHE — — $3.31 $2.21 $0.7 $0.042 $-0.958

Total Cost Savings from technology 

[CSRE = CSF +CSRE + CSHE] 

CST — — 3.95 8.83 13.76 25.29 19.09 

 

Cost Savings from Volume Production 

[CSv = TCs – TC – CSF – CSRE] 

CSV — — 1.56 5.56 1.77 4.30 2.54 

 

Cost Reduction from Scaling, $M CSs — — 6.3 10.7 5.2 9.2 9.6 

Cost Reduction from Technical, $M CSt — — 3.9 8.8 13.8 25.3 19.1 

Cost Reduction from Production Vol., $M CSV — — 2.2 5.6 1.8 4.3 2.5 

Total Cost Reduction, including receiver 

and heliostat field, $M 

CST — — 12.4 25.1 20.8 38.8 31.2 

 

Cost Reduction from Technical, % CSt — — 32% 35% 66% 65% 31% 

Cost Reduction from Scaling, % CSs — — 50% 43% 25% 24% 61% 

Cost Reduction from Production Vol., % CSV — — 18% 22% 9% 11% 8% 

E.8 THERMAL STORAGE 

E.8.1 Capital Cost 

The capital cost estimate for the thermal storage system is shown in Table E-46. 
 

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Table E-46 — Capital Cost for Thermal Storage – SunLab Reference Case 

Solar 

One

Solar 

Two

Solar 

Tres

Solar 

50

Solar 

100

Solar 

200

Solar 

220

 1988 1999 2004 2006 2008 2012 2018

Thermal Storage - Duration at 

peak output, hr 

N/A 3 16 16 13 13 12.7 

Net Plant Size – Thermal, MWt 46 42 120 380 700 1,400 1,400 

Thermal Storage System Direct 

Cost, $M 

$20.1 $3.7 $5.9 $18.7 $28.9 $56.3 $57.2 

Thermal Storage System Direct 

Cost, $/kWe 

— — $431 $374 $289 $281 $261 

The SunLab cost estimate for the capital cost for thermal storage is reasonable based on the following: 

• The cost estimate is a definitive cost estimate based on detailed design drawings and material 

takeoff. 

• The unit cost parameters are within typical industry values. 

• The contingency is 10%. 

• The binary nitrate salt cost is based on vendor quotes, which includes shipping. 

E.8.2 Technology Improvement 

E.8.2.1 Efficiency 

The storage design point efficiency is projected at 99.9% for all cases. The efficiency of Solar Two was 

demonstrated at 99.9%, and since there is no significant technology changes, it can be expected to remain 

constant. With larger plants, tank volume-to-surface-area ratio increases further, which increases storage 

efficiencies. 

E.8.2.2 Discussion 

Solar Two demonstrated molten salt as a viable, large-scale thermal energy storage medium. Energy storage 

efficiencies of 99% were achieved. The design, construction, and performance of large, field-erected, externally 

insulated tanks for storing molten salt were demonstrated. 
 

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There are several ongoing studies for improvement of the design and construction including the following: 

• Alternative valve designs for hot salt service. 

• Alternative salt downcomer designs. 

• Materials testing on stainless steels 347 and 321 are planned to demonstrate their resistance to 

IGC in salt service. 

E.8.3 Economy of Scale 

Table E-47— Economy of Scale for Thermal Storage 

Steam Generator Solar 

Two 

Solar 

Tres Solar 50 Solar 

100 

Solar 

200 

Solar 

220 

Direct Cost (SunLab) $3.70 $5.90 $18.70 $29.30 $56.30 $57.30 

Cost Reduction Due to Scaling based 

on Scaling Factor of 0.78 

— — $3.75 $5.81 $9.69 $9.40 

Cost Reduction Due to Scaling, $M — — $14.50 $30.12 $50.31 $56.30 

Cost Due to Technology 

Improvements, $M 

— — $4.20 ($0.82) $5.99 $1.00 

Cost Due to Technology 

Improvement, % 

— — 22.5% -2.8% 10.6% 1.7% 

The scale-up from Solar Two to Solar 220 thermal storage for the SunLab cost estimate is 0.78. This is 

reasonable based on the following: 

• The main components are the hot storage tank, cold storage tank and piping. 

• The scale-up was calculated based on the difference between the actual cost for Solar Two and 

vendor quotes for Solar100 (Central Receiver Utility Studies 1989) 

• The SunLab estimate is within the range of expected scale-up factors based on S&L’s 

experience with similar equipment in electric power plants. 

E.8.4 Production Volume 

Since the thermal storage system is comprised of single components, production volume is not a consideration 

for cost improvement. 
 

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E.8.5 Cost Improvements—Thermal Storage and Parasitic 

Cost improvements for thermal storage and parasitic were evaluated against technical efficiency improvements. 

Parasitic was included since thermal storage is the key contributor to minimizing parasitic losses. The cost 

improvements are shown in Table E-48. 

Table E-48 – Thermal Storage and Parasitic Cost Improvements Due to Technology (Efficiency) 

Improvements (Effect on Collector Field) 

Solar Two to 

Solar Tres

Solar Tres to 

Solar 50

Solar 50 to 

Solar 100

Solar 100 to 

Solar 200

Solar 200 to 

Solar 220

Thermal Storage 

 Percent Effect on Cost 

 Reduction, % 

-0.4% -0.1% -0.0% -0.0% -0.0% 

 Cost Reduction, $M -$0.41 -$0.17 -$0.02 -$0.01 -$0.05 

Parasitic 

 Percent Effect on Cost 

 Reduction, % 

-3.6% -0.7% -0.1% -0.1% -0.2% 

 Cost Reduction, $M -$3.72 -$1.39 -$0.36 -$0.25 -$1.08 

E.8.6 Cost Improvements 

Cost Improvements were evaluated by S&L against three categories: technical (efficiency and design 

optimization), economy of scale, and volume production. The cost reductions determined by S&L for the 

thermal storage system is an average of 7% due to technical improvements, 93% for scale-up, and 0% for 

volume production. 

E.9 STEAM GENERATOR 

E.9.1 Capital Cost 

The capital cost estimated by SunLab for the steam generator system is shown in Table E-49. 

Table E-49 — Steam Generator Capital Cost 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Direct Cost — $1.6 $3.7 $5.8 $9.4 $9.3 
 

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The SunLab cost estimate for the steam generator (superheater, evaporator, preheater, and reheater) is based on 

actual costs for Solar Two and vendor quotes for a 100-MWe plant (ref: ASND93-7084). 

E.9.2 Technology Improvement 

The Solar Two design of the steam generator consisted of a straight-shell, U -tube preheater (salt on the shell 

side); a kettle-boiler evaporator (salt in the U-tubes); and a straight-shell, U -tube superheater (salt on the shell 

side). Intergranular corrosion (IGC) was a problem in some areas where high- carbon stainless steel piping and 

fittings were used for containment of molten salt. Future molten-salt power tower designs will use the following: 

• Piping materials that are not susceptible to IGC. 

• Four tube-in-shell vessels (preheater, evaporator, superheater, reheater) with salt on the shell 

side. 

• Evaporator will be of a forced circulation design with separate steam drum. 

• Vessels stacked to provide simplified drain and maintenance procedures. 

The Solar Two demonstration project identified the following problems with the steam generator system: 

• A number of receiver tubes developed slow leaks due to intergranular corrosion (IGC). The new 

tube material eliminated this problem. 

• Poor water mixing in the evaporator shell which lead to salt freeze thaw cycles on the tubes 

resulting in a tube rupture and strained tubes. 

• The recirculation pump’s seals added considerable amount of cold water, which decreased the 

temperature of the recirculation flow. 

• The preheater was bypassed during startup to prevent salt from freezing, but it resulted in 

feedwater entering the evaporator below minimum design temperature. 

All problems were solved by the following means: 

• Repairing the evaporator tubes and modifications of evaporator spargers, 

• Adding a startup feedwater heater, adding a higher capacity canned-rotor recirculation pump, 

• Eliminating the preheater bypass line, 

• Adding a feedwater valve to the evaporator inlet piping, and 

• Modifying the startup procedure to reflect the new configuration and incorporate lessons 

learned from the tube rupture. 
 

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The modifications solved the problems as mentioned in the report: “No further tube ruptures occurred; 

temperature stratification in the evaporator was essentially eliminated; and the system performed more reliably 

for the remainder of the project. Operating experience also revealed that varying pump speed could reliably 

control salt flow to the SGS. This experience eliminated the need for flow control valves on the SGS salt supply 

piping.” 

The technology and lessons learned have been applied to the next generation design of Solar Tres. The 

successful operation of the system after repairs and modifications indicate that there is a low risk of significant 

problems occurring with the scale-up of the system. 

E.9.3 Economy of Scale 

Table E-50 — Economy of Scale for Steam Generator 

Steam Generator Solar 

Two 

Solar 

Tres Solar 50 Solar 100 

Solar 

200 

Solar 

220 

Direct Cost — $1.6 $3.7 $5.8 $9.4 $9.3 

Cost Reduction Attributed to Scaling 

based on Scaling Factor of 0.74 

— — $3.75 $5.81 $9.69 $9.69 

Note: The difference between cost reduction due to scaling and direct cost is attributed to technology improvements 

and calculates to an average of 3.7%. 

The cost estimates for the other size plants were calculated based on a scaling factor of 0.7, which was 

calculated from the steam generator size and cost of Solar Two to the quotes for Solar 100. The cost estimate is 

reasonable based on the following: 

• The cost for Solar Two is an actual cost. 

• The cost estimate for Solar 100 is based on vendor’s designs and quotes. 

• The SunLab estimate is within the range of expected scale-up factors based on S&L’s 

experience with similar equipment in electric power plants. 

• A comparison of Solar Two of the preheater, evaporator, and superheater area to Solar 100 

preheater, evaporator, and superheater results in a scaling factor of 0.69. Solar 100 has a 

reheater and the SunLab calculation included the reheater. 

• The steam generator design is based on known and proven heat exchanger technology. 

• A contingency of 10% is included in the cost estimate, which is reasonable. 
 

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The SunLab cost estimate for the pumps is based on Solar Two actual costs and Solar Tres detailed budgetary 

quotes from vendors. Motor costs are based on standard industry motor costs. The cost estimate is reasonable 

based on the following: 

• The cost for Solar Two is an actual cost 

• The cost estimate for Solar Tres in based on actual budgetary quotes 

• Motors are not a unique design but standard industry available models 

• The cost scaling factors calculated between Solar Two and Solar Tres are lower than industry 

standard based on MWt: 0.65 for cold pumps and 0.55 for hot pumps. The reason is based on 

material changes for hot components, which are more costly. 

E.9.4 Production Volume 

Since the steam generator system is comprised of single components, production volume is not a consideration 

for cost improvement. 

E.9.5 Cost Improvements 

Cost Improvements were evaluated by S&L against three categories: technical (efficiency and design 

optimization), economy of scale, and volume production. The cost reductions determined by S&L for the steam 

generator system is an average of 4% due to technical improvements, 96% for scale-up, and 0% for volume 

production. 

E.10 BALANCE OF PLANT 

E.10.1 Capital Cost 

Sargent & Lundy estimated the cost for the balance of plant based on the SOAPP model, compared it to our 

internal database, and then adjusted the output for labor and productivity rates in the Southwest. The results of 

our review are shown in Table E-51 and Figure E-12. The balance-of-plant costs include general balance-ofplant equipment, condenser and cooling tower system, water treatment system, fire protection, piping, 

compressed air systems, closed cooling water system, instrumentation, electrical equipment, and cranes and 

hoists. 
 

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Table E-51 — Capital Cost of Balance of Plant 

Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Power Block MWe — 13.5 50 100 200 220 

SunLab $M — $4.8 $6.5 $7.8 $9.6 $9.9 

 $/kWe — $356 $130 $78 $48 $45 

S&L $M — $10 $24.5 $36.7 $33.8 $35.5 

 $/kWe — $741 $490 $367 $169 $148 

Figure E-12 — Balance of Plant 

$0

$100

$200

$300

$400

$500

$600

$700

$800

0 50 100 150 200 250

Megawatts

$/kW

S&L

SunLab

Balance of Plant costs include general balance 

of plant equipment, condenser and cooling 

tower system, water treatment system, fire 

protection, piping, compressed air 

systems,closed cooling water system, plant 

control system, electrical equipment, and 

cranes and hoists.

E.10.2 Technology Improvements 

There are no efficiency improvements projected for balance of plant. 
 

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E.10.3 Economy of Scale 

There are recognized scale-up cost reductions for the balance of plant. Using the SOAPP software program 

(SOAPP undated) and S&L’s internal database, the scale-up factor was estimated for the increasing the balance 

of plant from 13.5 MW to 200 MW, as depicted on Figure E-12. The S&L trend curve is expressed as follows: 

 Y = (461.3) x – 0.1896 

 Where: 

 Y = $/kW 

 x = MWe 

E.10.4 Production Volume 

Production volume is not a consideration for cost reduction. 

E.10.5 Cost Improvements 

Cost Improvements were evaluated by S&L against three categories: technical (efficiency and design 

optimization), economy of scale, and volume production. The cost reductions determined by S&L for the 

balance of plant is an average of 0% due to technical improvements, 100% for scale-up, and 0% for volume 

production. 

E.11 CAPITAL COST COMPARISON 

The SunLab model projects tower plant capital and O&M costs based on various technology advances and 

commercial deployment predictions. The SunLab projections are considered the best-case analysis where the 

technology is optimized and a high deployment rate is achieved. S&L developed capital and O&M costs based 

on a more conservative approach whereby the technology improvements are limited to current demonstrated or 

tested improvements and with a lower rate of deployment than used in the SunLab model. The two sets of 

estimates, SunLab’s and S&L’s, provides a band in which the costs can be expected to be, assuming the 

parabolic trough technology reaches the projected levels of deployment. A comparison of key parameters used 

for the estimates is summarized on Table E-52. 
 

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Table E-52 — Key Parameters Comparison 

2004 2007 2010 2015 2020

SunLab S&L SunLab S&L SunLab S&L SunLab S&L SunLab S&L

Deployment, MW 13.5 13.5 50 50 100 100 200 200 220 200 

Cumulative 

Deployment, MW 13.5 13.5 164 64 914 264 3,914 814 8,734 2,614 

Net Annual Solar 

Efficiency 13.7% 13.0% 16.1% 15.5% 16.6% 16.1% 16.9% 16.5% 18.1% 16.5%

Heliostat, $/m2 $145 $160 $127 $150 $107 $134 $96 $124 $75 $117 

The significant differences between the SunLab Reference Case and the S&L estimate are the following: 

• Deployment. SunLab projected 8.7 GWe whereas S&L projected 2.6 GWe. 

• Net Annual Solar Efficiencies. S&L projected the net annual solar efficiency to be lower based 

on proven results and conservative design enhancements. S&L did not include the advanced 

eliostat design and advance higher temperature steam turbine in their base case estimate. 

• Heliostat Cost. S&L cost estimate is based on a detailed evaluation of existing cost estimates 

and independent projection. 

• Electric Power. S&L cost estimate is based on the latest industry information and is lower than 

the SunLab estimate. 

• Balance of Plant. S&L cost estimate is based on the latest industry information and is higher 

than the SunLab estimate. 

• O&M Costs. S&L estimate is based evaluation of the SunLab projection, visit to the SEGS site, 

and our review of conventional power plants. The main difference is scaled-up costs due to the 

increase in field size for grounds and vehicle maintenance, average burden rate and raw water 

cost. 

• Engineering, Management and Development. SunLab projected that the Engineering, 

Management and Development at 7.8% of cost. S&L projected the cost to be 15%, based on 

recent industry experience in developing independent power plants. 

• Contingency. SunLab projected the contingency at 7.7%. S&L projected the contingency to be 

11.8% for the cost estimate and 15% for cost reductions. 

E.12 LEVELIZED ENERGY COST 

The projections by SunLab and S&L for capital cost and operations & maintenance were used to estimate 

levelized energy costs (LEC). After completing the report, SunLab revised its reference case (from August 2002 

to October 2002) as shown below. The Sunlab LEC projections are based on the October 2002 reference case. 
 

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Revised SunLab Reference Case 

 Solar Two Solar 15 Solar 50 Solar 100 Solar 200 Solar 220 

 1999 2004 2006 2008 2014 2018 

Net Electrical (MWe) 10 13.7 50 100 200 220 

Plant Size Solar (MWt) 42 120 380 700 1400 1400 

Heliostat Size (m2) 39/95 95 95 148 148 148 

Heliostat Field (m2) 81,400 231,000 715,000 1,317,000 2,614,000 2,651,000 

Annual Solar-toElecticity Efficiency 7.6% 13.7% 15.7% 16.5% 16.8% 17.8% 

Capital Cost ($/kWe) — 7,180 4,160 3,160 2,700 2,340 

O&M Annual Cost ($k) — 2,489 3,166 4,005 5,893 6,006 

LEC ($/kWh) — $114.8 $61.5 $47.6 $39.6 $35.0 

The cost estimates were inputted to the financial model developed by S&L (see Appendix B for a description of 

the financial model). The results are shown in Table E-53. 

Table E-53 — Capital Cost, O&M Costs and Levelized Energy Cost Summary: 

SunLab and S&L 

 Near Term Mid Term Long Term 

 SunLab S&L SunLab S&L SunLab S&L 

 Solar Tres USA Solar 100 Solar 220 Solar 200 

 2004 2004 2008 2010 2018 2020 

Capital Cost, $/MWh $77.4 $97.1 $36.3 $52.9 $27.0 $41.8 

Fixed O&M Costs, $/MWh $37.4 $46.1 $11.3 $15.3 $8.0 $12.9 

Variable O&M Costs, $/MWh $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 

LEC, $/MWh $114.8 $143.1 $47.6 $68.2 $35.0 $54.7 

SunLab – Deployment of 8.7 GWe / S&L – Deployment of 2.6 GWe 

Sargent & Lundy’s estimate of the direct capital cost and operation & maintenance costs for the near-term 

deployment includes a contingency of about 10%. Based on our review of the SunLab cost estimate, which we 

determined was based on industry cost data and engineering judgment, the cost estimate for the near-term 

deployment (Solar Tres) is reasonable. The projection from near-term deployment (2003) to long-term 
 

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deployment (2020) includes cost reduction due to technology improvements, scaling, and volume production. 

S&L included a composite contingency of 15% for cost reductions (15% for technology, 10% for scaling, and 

20% for volume production). For comparison, the effect of deployment and annual net efficiencies are shown in 

Table E-54. 

Table E-54 — Impact of Deployment and Net Solar-to-Electric Efficiency on LEC 

LEC 

Year 2020 

Total 

Deployment 

(GWe) 

Net Solar-toElectric Efficiency

(%) ($/kWh) 

Percent change from 

S&L Base Case 

SunLab 8.7 18.1 0.0350 SunLab Base 

S&L 8.7 16.5* 0.0524 -4.2% 

S&L 4.7 16.5* 0.0538 -1.6% 

S&L 2.6 16.5* 0.0547 S&L Base 

S&L 1.2 16.5* 0.0559 2.2% 

S&L 2.6** 17.3 0.0476 -13.0% 

S&L 2.6** 16.5 0.0547 S&L Base 

S&L 2.6** 14.6 0.0590 7.9% 

* Fixed net solar-to-electric efficiency 

** Fixed total deployment. 

The range of LEC between the SunLab cost estimate and S&L’s estimate is about 56% as shown in Figure E-13. 
 

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Figure E-13 — Levelized Energy Cost Comparison: SunLab and S&L 

0

20

40

60

80

100

120

140

160

2004

Solar Tres USA

Near Term

2006

Solar 50

2010

Solar 100

Mid Term

2015

Solar 200

2020

Solar 220

Long Term

$/MWh

SunLab - 8.7 GWe

Sargent & Lundy - 2.6 GWe

56%

Cost improvements were evaluated by S&L against three categories: technical improvements, scale-up, and 

production volume. The contribution of these three categories against the S&L LEC projection is shown in 

Figure E-14. 
 

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Figure E-14 — Sargent & Lundy LEC Projection Breakout by Category 

$0.0000

$0.0200

$0.0400

$0.0600

$0.0800

$0.1000

$0.1200

$0.1400

2004

Solar Tres USA

Near Term

2006

Solar 50

2008

Solar 100

Mid Term

2016

Solar 200

2018

Solar 220

Long Term

Levelized Energy Cost, $/kWhe

Technical - 23%

Scaling - 49%

Volume Production - 28%

The major contributor to cost reduction from Solar Tres to Solar 50 is due to the increase in electrical generation 

(13.5 MWe to 50 MWe) as shown in Figure E-15. The annual net energy production increased from 

93.2 GWh/yr to 331 GWh/yr. 
 

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Figure E-15 — Comparison of SunLab and S&L LEC Estimates: 2004 to 2020 

0.0000

0.0200

0.0400

0.0600

0.0800

0.1000

0.1200

0.1400

2004

Solar Tres USA

Near Term

2006

Solar 50

2010

Solar 100

Mid Term

1015

Solar 200

2020

Solar 220

Long Term

Levelized Energy Cost, $/kWh

Sunlab - 8.7 GWe

S&L - 2.6 GWe

Technology - 11%

Scaling - 54%

Volume Production - 35%

Major Cost Reduction - 

Increase in Net Electrical 

Output

93.2 GWhe/yr to 331 GWhe/yr
Appendix F 

Evaluation of O&M Costs – Trough 
 

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F. EVALUATION OF O&M COSTS – TROUGH 

F.1 SUMMARY 

Table F-1 shows the SunLab projected O&M costs. 

Table F-1 – CSP Trough Technology O&M Costs — 

SunLab Projections 

Trough 

2004 

Trough 

2007 

Trough 

2010 

Trough 

2015 

Trough 

2020 

Annual Net Generation, MWhe 468,617 492,175 738,922 984,831 1,981,490 

Field Aperture Area, m2 1,120,480 1,037,760 1,477,680 1,955,200 3,910,400 

Staff 45 44 51 58 90 

Average Annual Cost (with burden), $1,000 58.8 62.0 60.8 59.9 57.7 

Staff Cost, $1,000 2,643 2,705 3,081 3,490 5,164 

Annual Material & Services Cost, $1,000 3,054 2,243 2,507 2,952 5,029 

Total O&M Cost, $1,000 5,697 4,948 5,588 6,442 10,193 

Total O&M Cost, $/kWhe 0.012 0.010 0.008 0.007 0.005 

F.2 O&M STAFF 

The staffing in the SunLab model was reviewed and is a reasonable estimate. The staffing compares with SEGS, 

power-generating facilities and the recent O&M Cost Reduction Study performed at Kramer Junction (KJCOC 

1999). The staffing for trough technology is shown in Table F-2. 

Table F-2 — Staffing for Trough Technology — 

SunLab Projections 

2004 2007 2010 2015 2020

Administrative 7 7 7 7 7 

Plant Operations 15.5 15.2 16.9 18.8 26.6 

Power Plant Maintenance 8 8 8 8 8 

Solar Field Maintenance 14.4 13.5 18.7 24.5 47.9 

 Total 44.9 43.6 50.6 58.3 89.6 
 

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The power plant staffing, exclusive of solar field maintenance, is comparable to the industry average for a 

120-MWe combined-cycle power plant. 

The estimated staff increases were determined to be reasonable based on the following evaluation. 

The SunLab model estimated a staff of approximately 45 for trough 2004 and 2007 (100-MW plant each). 

• The administrative staff would be the same for the increased plant sizes through 2020. 

• The increase in plant size from 100 MWe to 400 MWe will not require additional maintenance 

staff for maintenance of the power plant. The difference between 100 and 400 MWe does not 

increase the quantity or complexity of the equipment. 

• Each additional 50-MW plant size will require two additional mirror wash technicians in the 

operations staff to account for the increased field aperture area. 

• The increase in the solar field maintenance staff is required to support the increase in the solar 

field. For Kramer Junction, approximately 0.03 maintenance staff is required per 1,000 m2 of 

solar field aperture area. The larger solar plant is estimated to be approximately directly 

proportional to increase of the solar field. For example, the solar field maintenance staff for 

2020 is estimated to be (3,910,400 m2

 / 1,120,480 m2) = 3.49 x14 maintenance staff (in 2004) = 

49 maintenance staff (in 2020). 

F.3 O&M MATERIAL AND SERVICE COSTS 

F.3.1 Service Contract 

The service contracts include typical contracts and costs expected for this type of facility (control computers, 

office equipment, waste disposal, road maintenance, vehicle maintenance, etc.). 

F.3.2 Raw Water and Chemicals 

The SunLab estimate is based on water usage and chemical costs from SEGS VI/VII as shown below. The costs 

and estimated usage values are consistent with industry averages. 

Table F-3 — Water Usage and Chemical Costs — 

SunLab Projections 

Raw Water Costs $0.32 per m3

Cooling Water Chemical Cost $0.043 per m3 cooling tower make-up 

Demineralizer Chemical Cost $0.540 per m3 condensate make-up 

Cooling Tower Make-up 2.90 m3/MWhe 
 

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Power Cycle Condensate Make-up 0.17 m3/MWhe 

Demineralizer Blowdown 10% 

Mirror Wash Water Consumption 0.022 m3 (water)/ m2 (of collector) /year 

Raw Water (m3) Percentage

Cooling Tower Make-up 1,031,547 93.5% 

Power Cycle Demin. Make-up 67,189 6.1% 

Mirror Wash Demin Make-up 4,596 0.4% 

 Total 1,103,332 

F.3.3 Parts and Material 

The SunLab projections are based on the following unit costs and annual replacement rates. 

Table F-4 — Parts and Materials Cost Basis — 

SunLab Projections 

Unit Cost 

($)

Replacement 

Rate

Mirrors 80 0.005 

HCEs 847 0.02 

Sun Sensors 150 0.005 

LOCs 200 0.005 

Ball Joints 2,100 0.005 

Hdr. Drive 3,000 0.005 

Miscellaneous 5% of total equipment costs 

HTF Pump Seals 1,200 2 

HTF Makeup 9 0.01 

F.3.4 Miscellaneous 

Miscellaneous costs include administration costs (safety, training, travel, supplies, telephones, etc) and vehicle 

fuel and repair. The cost of $253,000 per year is reasonable for this size of power plant. 
 

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F.3.5 Capital Equipment 

Capital equipment covers the equipment required to operate and maintain the facility (dump truck, operator 

vehicles, mirror-washing equipment, mirror container carrier, lube trailer and tractor). The cost of the equipment 

is based on the recent O&M Cost Reduction Study performed at Kramer Junction (KJCOC 1999) and Kramer 

Junction’s latest information. The quantity of equipment is increased proportionally to the size of the solar field, 

which is a reasonable assumption. 

F.4 ESTIMATED O&M COSTS BASIS 

The O&M costs for comparison to the SunLab projections are based on the following: 

• Solar Field 

 The initial unit costs are based on the SunLab values 

 Replacement rate for the mirrors and HCE are based on the average actual replacement 

rates for SEGS III – VII for the period 1997–2001 

 The replacement rates for the balance of the solar field are based on the SunLab values 

• Power Block and Balance of Plant 

 Costs are based on S&L data for the respective MW size plant for the steam turbine 

systems and balance of plant 

• Water and Process 

 Costs are based on are based on the average actual costs for SEGS III – VII for the period 

1997–2001 

• Staffing, Services Contracts, Miscellaneous, and Capital Equipment 

 The costs are based on the SunLab values since the SunLab values were determined to be 

reasonable 

• Thermal Storage 

 The costs are based on 0.4% of the capital cost per annum 

F.5 O&M COST COMPARISON 

The SunLab and S&L estimated O&M costs are compared in Table F-5. 
 

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Table F-5 — O&M Cost Comparison 

2004 2007 2010 2015 2020

SunLab $(2002) 5,697,000 4,948,000 5,588,000 6,442,000 10,193,000 

 Levelized $/kWhe 0.012 0.010 0.008 0.007 0.005 

S&L $(2002) $8,114,516 $6,611,838 $7,553,692 $8,286,682 $13,731,497 

 Levelized $/kWhe $0.0173 $0.0134 $0.0102 $0.0084 $0.0069 

Analyzing the two estimates revealed the major component to account for the cost difference is the HCE 

replacement rate. The SunLab projections indicate the following replacement rates: 

• 2004 – 2% 

• 2007 – 1% 

• 2010 through 2020 – 0.5% 

compared to the following S&L values: 

• 2004 – 5.5% 

• 2007 – 4.0% 

• 2010 – 2.5% 

• 2015 – 1.0% 

• 2020 – 0.5% 

The SunLab near-term values are not consistent with the average actual HCE replacement rate of 5.5% reported 

for SEGS III – VII for the period 1997–2001. 

Sargent & Lundy reviewed the actual receiver (HCE) replacement rate reported by KJC Operating Company 

over the last five years. The S&L evaluation is based on total HCE replacement reported for the SEGS III – VII 

for the period 1997–2001. S&L’s evaluation is based on the current replacement rate at all the SEGS plants, 

with step reductions in the replacement rate based on the following: 

• The average actual HCE replacement rate of 5.5% was reported for SEGS III – VII for the 

period 1997–2001. The total HCE replacement includes breakage and fluorescence. 

Fluorescence is due to cermet coating failures. This failure is due to the existence of 

molybdenum in the original Luz cermet coating. Solel no longer uses molybdenum in the 

UVAC cermet coating, so this type of failure will presumably no longer occur. Eliminating 

replacements due to these failures reduces the site failure/replacement rate. 
 

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• SunLab has used the SEGS VI plant as the baseline reference plant. The SEGS III – V plants 

had problems during initial startup and the early years of operation that caused bowing of the 

HCEs, which increased breakage at those plants. SEGS VII has had higher breakage on the LS3 half of the field, although the LS-2 failures are similar to SEGS VI. SEGS VI was the last full 

plant constructed with LS-2 collectors and represents the most mature version of this generation 

of collector technology. The HCE total replacement rate at SEGS VI during the 5 years is in the 

5.5% range. Discounting the fluorescence failures, the replacement rate was 4.2% over the 

5-year period. 

• The high HCE failure rate at the existing plants is in part due to issues that would not be found 

at a future plant. A significant portion of the failures has been due to the hydrogen remover 

(HR) device installed in the HCEs at SEGS VI – X, operational problems that caused bowing, 

and HCE installation procedures. The HR is no longer part of the HCEs provided by Solel. 

Based on these factors, it is possible that future plants will have substantially lower HCE failure rates than 

currently occur at the SEGS plants; however, the SunLab assumption of a 2% failure rate assumes that current 

approaches for reducing failures are successful. S&L believes this is an aggressive assumption that cannot be 

assured for future plants without the field data to verify the failure rate reduction. Using the current replacement 

rate at all the SEGS plants, with step reductions in the replacement rate, reflects the current conditions and 

allows for the aforementioned improvements to reduce the replacement rate. 

Additional development of the HCE will likely be necessary to achieve the future receiver reliability goals. The 

current glass-to-metal seal is one of the more expensive elements and the key failure point of the current 

receiver design. The current design, known as a Housekeeper seal, relies on a sharp metal point being inserted 

into a glass bead. Failures occur when concentrated light focus on seal and the differential expansion between 

the glass and metal causes the failure of the seal. New designs are currently under investigation that attempt to 

improve the match between the coefficient of thermal expansion of the metal and glass. Kramer Junction is 

currently testing a new design UVAC2 with a revised internal shield. 

Another factor that contributes to the higher S&L-estimated O&M costs is the higher component costs, as 

detailed in Appendix D. 

If the HCE reliability can be improved to reduce the replacement rate to that projected by SunLab, the O&M 

costs converge on the values projected by SunLab. 
Appendix G 

Evaluation of O&M Costs – Tower 
 

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G. EVALUATION OF O&M COSTS – TOWER 

G.1 OPERATION AND MAINTENANCE COSTS 

The SunLab O&M estimate is based on the actual costs from SEGS and adjusted accordingly for tower solar 

field and technology. The reduction in O&M cost is primarily a result of the increase in annual plant capacity 

factor, as shown in Table G-1. The plant capacity increases directly as a result of the increases in thermal 

storage. Increasing the size (MWe) and utilization (capacity factor) of the power plant incurs very little increase 

in O&M expenses ($/year). This is because the quantity and complexity of the equipment remain constant and 

staffing remains fairly constant. Our review of conventional fossil power plants show this “economy of scale” in 

staffing for increases in plant size. 

Solar O&M expenses and staff increase with the field size. There are significant cost improvements from 

increases in solar system efficiency, which reduce the solar field size (see Section E.4.2). 

Table G-1 — SunLab CSP Tower Technology O&M Cost Estimate 

Solar One Solar Two Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Net Power, MWe 10 10 15 50 100 200 220 

Plant Capacity Factor, % N/A 19% 78% 76% 73% 74% 73% 

Annual Net Generation, 

GWh/yr 

N/A 16.6 93.3 335 642 1,292 1,406 

Thermal Storage, hrs 0 3 16 16 13 13 12.7 

Solar Field, m2 71,100 81,400 231,000 709,000 1,311,000 2,606,000 2,642,000 

Number of Heliostats 1,818 1,912 2,432 7,463 8,858 17,608 17,851 

Staff 32 33 31 38 47 67 67 

Average Annual Cost (with 

burden) 

$71 $71 $62 $56 $50 $42 42 

Staff Cost $2,272 $2,343 $1,922 $2,128 $2,350 $2,814 $2,814 

Annual Material & 

Services Cost 

$1,000 $400 $600 $900 $1,200 $1,900 $1,900 

Total O&M Cost, $k $3,272 $2,743 $2,522 $3,028 $3,550 $4,714 $4,714 

Total O&M Cost, $/kWhe N/A $0.165 $0.027 $0.010 $0.006 $0.004 $0.003 
 

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G.2 O&M STAFF 

The staffing in the SunLab model was reviewed, and it is a reasonable estimate. The staffing compares with 

SEGS power-generating facilities and the recent O&M Cost Reduction Study performed at Kramer Junction 

(KJCOC 1999). The staffing for tower technology is shown in Table G-2. 

Table G-2 — Staffing for Tower Technology 

SunLab Sargent & Lundy

 Solar 

Tres USA Solar 100 Solar 200 Solar Tres USA Solar 100 Solar 200

Administrative — — — 7 7 7 

Plant Operations — — — 11 11 11 

Power Plant Maintenance — — — 7 7 7 

Solar Field Maintenance & 

Wash Crew 

— — — 8 21 42 

 Total 31 47 67 33 46 67 

The power block staffing (33 minus 8 for solar field equals 25) is comparable to the industry average for a 

120-MWe combined-cycle power plant. The total staffing for a 120-MWe combined-cycle power plant is 25 

based on the SOAPP model. 

The staffing was determined to be reasonable based on the following evaluation: 

• The administrative staff would be the same for the increased plant size. 

• The increase in plant size from 50 MWe to 220 MWe will not require additional operations or 

maintenance staff for operations and maintenance of the power plant. The difference between 

50 and 220 MWe does not increase the quantity or complexity of the equipment. 

• The increase in the solar field maintenance staff, including mirror wash crew, is required to 

support the increase in the solar field. For Kramer Junction, approximately 0.03 maintenance 

staff is required per 1,000 m2 of solar field aperture area. 
 

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G.3 O&M MATERIAL AND SERVICE COST 

G.3.1 Service Contract 

The service contracts include typical contracts and costs expected for this type of facility, including control 

computers, office equipment, waste disposal, road maintenance, and vehicle maintenance, and are shown in 

Table G-3. The contract for weed control, road maintenance, and vehicle maintenance was scaled up to account 

for the larger field area. 

Table G-3 — Service Contracts 

Solar Tres Solar 50 Solar 100 Solar 200 Solar 220

Control System Computers $24,000 $24,000 $24,000 $24,000 $24,000 

Personal Computer/Office Equip. $5,000 $5,000 $5,000 $5,000 $5,000 

Nitrogen Supply $27,000 $27,000 $27,000 $27,000 $27,000 

Sanitary Service $6,000 $6,000 $6,000 $6,000 $6,000 

Waste Disposal $34,000 $34,000 $34,000 $34,000 $34,000 

Weed Control $55,000 $70,232 $107,995 $174,689 $176,375 

Road maintenance $27,000 $34,478 $53,016 $85,756 $86,584 

Vehicle Maintenance $2,000 $2,554 $3,927 $6,352 $6,414 

 Total $180,000 $203,264 $260,939 $362,798 $365,372 

G.3.2 Raw Water and Chemicals 

The estimate is based on water usage and chemical costs from SEGS VI/VII as shown below in Table G-4. 

Water and chemical usage for the power plant thermal is consistent with industry averages for power plants. The 

additional usage for solar (e.g. mirror wash) is based on the O&M Cost Reduction Study (KJCOC 1999). Raw 

water cost is based on actual costs reports at SEGS of $0.00122 per gallon ($0.32 per m3

). The main difference 

between the SunLab reference case and S&L’s case is the cost of raw water. SunLab estimated the cost to be 

$0.021 per m3

), which is about 15 times less than the S&L estimate. 

Table G-4 — Water Usage and Chemical Costs 

Raw Water Cost $0.32 per m3

Cooling Water Chemical Cost $0.043 per m3 cooling tower make-up 
 

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Demineralizer Chemical Cost $0.540 per m3 Condensate make-up 

Cooling Tower Make-up 2.90 m3/MWhe 

Power Cycle Condensate Make-up 0.17 m3/MWhe 

Demineralizer Blowdown 10% 

Mirror Wash Water Consumption 0.022 m3 (water)/ m2 (of collector) /year 

G.3.3 Parts and Material 

Parts and material for the conventional power plant range between 0.3% and 0.4%, depending on the age and 

type of facility. S&L used 0.35% of the capital cost for parts and materials related to the power block and 

balance of plant. 

Parts and material for the solar field are based on the O&M study (KJCOC 1999) for 500,000 m2

 and adjusted 

for the increase in solar size. The estimate is reasonable since it is based on the recent O&M Cost Reduction 

Study performed at Kramer Junction, incorporates the latest cost information from Kramer Junction, and was 

adjusted to account for tower technology. Parts and material costs for a solar field are shown in Table G-5. 

Table G-5 — Parts and Material Costs for a Solar Field 

Unit Cost ($) Replace (%) $/m2-yr 

Mirrors 26 0.5% $0.130 

LOCs 200 0.5% $0.010 

Hdr. Drives 4,500 0.5% $0.093 

Miscellaneous 5% of total equipment costs $0.01 

HTF Pump Seals 1,200 2 $0.05 

 Total — — $0.25 

G.3.4 Miscellaneous 

Miscellaneous costs include administration costs (such as safety, training, travel, supplies, and telephones) and 

vehicle fuel and repair (see Table G-6). The cost of $253,000 per year is reasonable for this size of power plant. 

S&L projected increases for vehicle and fuel to account for the larger number of vehicles needed to support 

maintenance of the larger collector fields. 
 

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Table G-6 — Miscellaneous Costs 

Solar Tres Solar 50 Solar 100 Solar 2002 Solar 220

Vehicle Fuel $17,000 $21,708 $33,380 $53,995 $54,516 

Vehicle Parts and Supplies $28,000 $35,755 $54,980 $88,933 $89,791 

Site Improvements $2,000 $2,000 $2,000 $2,000 $2,000 

Safety & Training School $10,000 $10,000 $10,000 $10,000 $10,000 

Travel $5,000 $5,000 $5,000 $5,000 $5,000 

Office Supplies $28,000 $28,000 $28,000 $28,000 $28,000 

Telephones $67,000 $67,000 $67,000 $67,000 $67,000 

Rental Equipment $34,000 $34,000 $34,000 $34,000 $34,000 

First Aid Equipment $6,000 $6,000 $6,000 $6,000 $6,000 

Other Miscellaneous $56,000 $56,000 $56,000 $56,000 $56,000 

 Total $253,000 $265,463 $296,360 $350,927 $352,307 

G.3.5 Capital Equipment 

Capital equipment (see Table G-7) covers the equipment required to operate and maintain the facility (including 

dump truck, operator vehicles, mirror washing equipment, and tractor). The cost of the equipment is based on 

the recent O&M Cost Reduction Study performed at Kramer Junction (KJCOC 1999) and on Kramer Junction’s 

latest information. The quantity of equipment is scaled-up to account for the increase in the size of the field. 

Table G-7 — Capital Equipment 

Cost * Number Solar Tres Solar 50 Solar 100 Solar 2002 Solar 220

 $/m2 $/m2 $/m2 $/m2 $/m2

Dump Truck $30,000 1 $0.01 $0.02 $0.02 $0.04 $0.04 

SF Operator Vehicle $20,000 3 $0.02 $0.03 $0.05 $0.08 $0.08 

Mirror Wash Rig - Twister $100,000 2 $0.04 $0.05 $0.08 $0.13 $0.13 

Mirror Wash Rig - Deluge $30,000 1 $0.02 $0.03 $0.05 $0.08 $0.08 

Mirror Container Carrier $17,000 1 $0.01 $0.01 $0.01 $0.02 $0.02 

Tractor $20,000 1 $0.01 $0.01 $0.02 $0.03 $0.03 

 Total $0.12 $0.15 $0.23 $0.37 $0.38 

* Capital equipment cost was calculated based on a 5-year equipment life. 
 

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G.3.6 O&M Cost Comparison 

The comparison between the SunLab cost estimate and S&L’s estimate is shown in Table G-8. The major 

differences are the following: 

• Sargent & Lundy scaled-up the cost of contracts associated with increase in field size (e.g., 

weed control). 

• Sargent & Lundy scaled-up the cost of fuel and maintenance of vehicles to account for the 

increase in field size. 

• Sargent & Lundy assumed that the average burdened rate would not decrease between Solar 100 

and Solar 220. 

• Raw water cost used by S&L is based on actual costs reports at SEGS of $0.00122 per gallon 

($0.32 per m3

). SunLab estimated the cost to be $0.021 per m3), which is about 15 times less 

than the S&L estimate. 

• Sargent & Lundy included a contingency of 10%. 

Table G-8 — Comparison of O&M Cost Estimates: SunLab vs. S&L 

Current SunLab Estimates S&L Estimates

 1987/1999 2004 2008 2020 2004 2008 2020

Plant Characteristics

Solar 

One/Two

Solar 

Tres Solar 100 Solar 220

Solar 

Tres Solar 100 Solar 220

Net Power, MWe 10 15 100 220 15 100 220 

Plant Capacity Factor, % 19.0% 78.0% 73.2% 72.9% 78.0% 73.2% 72.9% 

Annual Solar-Electric Efficiency 7.6% 13.7% 16.6% 18.1% 13.0% 16.5% 17.3% 

Thermal Storage, hrs 3 16 13 13.1 16 13 13.1 

Solar Field, m2 81,400 231,000 1,311,000 2,642,000 233,772 1,354,452 2,771,730

O&M Characteristics 

Number of Staff (FTE) 35 31 47 67 33 46 67 

Avg. Burdened Labor Rate, $k/yr $71 $62 $50 42 $62 $50 $50 

Staff Cost, $k/yr $2,485 $1,922 $2,350 $2,814 $2,046 $2,299 $3,364 

Ann. Material & Services Cost, 

$k/yr 

$750 $600 $1,200 $1,900 $686 $2,065 $4,277 

 Total O&M Cost, $k/yr $3,235 $2,522 $3,550 $4,714 $3,041 $5,127 $9,132 

 Total O&M Cost, $/kWhe $0.194 $0.027 $0.006 $0.003 $0.033 $0.008 $0.006 

Note: the Solar One/Two values are a blend from both plants to provide a “best available” estimate for a typical salt plant of 

this size with utility operations. 
Appendix H 

Mirror Reflectivity (SunLab Input) 
 

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H. MIRROR REFLECTIVITY (SUNLAB INPUT) 

The terms “mirror reflectivity” and “reflectivity” are used throughout this report, unless specified otherwise, to 

refer to the solar-weighted specular reflectivity—the fraction of the incident solar energy reflected in a specular 

(rather than diffuse) fashion. The solar-weighting of reflectivity is achieved by measuring the spectral 

reflectivity across a wide range of solar-thermal wavelengths (typically 0.3μ to 2.5μ), then weighting by the 

ASTM-accepted wavelength-dependant energy content of sunlight after it passes through the earth’s atmosphere 

(ASTM G159-98 air mass 1.5 solar spectral irradiance is the standard). The specular nature of a mirror’s 

reflectivity is quantified by measuring the intensity of reflected light only in a limited collection region along the 

ideal angle of reflection. Both laboratory and field portable instruments have been developed that measure the 

specular reflectivity at adjustable acceptance apertures ranging from 1 to 100 milli-stearadian (2π stearadian 

equals the complete hemisphere of possible reflection). A tower receiver subtends about 5 milli-stearadian from 

the furthest heliostat at a very large plant. The accuracy of both the spectral reflectivity and specular reflectivity 

are assured when the measurements are referenced to directly traceable NIST standard reference materials, the 

fundamental geometric optics of the instrumentation is determined, and the mirror scattering characteristics are 

known. The Optical Materials Branch at the National Renewable Energy Laboratory and the Primary Standards 

Laboratory at Sandia National Laboratories provide support in characterizing the reflectivity of mirror materials. 

Microscopic surface irregularities, called specularity errors, in a mirror’s substrate or superstrate material 

slightly reduce a mirror’s measured specular reflectivity because they cause non-specular (scattered) reflections 

that fall outside the acceptance aperture of the measurement instrument. Specularity errors can be measured on 

small mirror samples and generally have a much smaller impact on plant performance than “slope” and 

“curvature” errors, which are errors in the shape of the mirror surface over larger (macroscopic) areas of the 

surface that must be measured on full-size samples. Slope and curvature errors are included and reported in the 

optical performance (efficiency) metric of CSP plants, not in the mirror reflectivity. 

The reflectivity of an ideal (front-surface) silvered mirror is approximately 97%. Since silver degrades quickly 

in the outdoor environment, more durable back-surface glass mirrors have typically been used at CSP plants. 

Glass superstrates result in transmission losses (increased absorption) through the glass medium, with losses 

increasing as a function of both iron content in the glass and thickness. The reflectivity of typical, 4-mm thick, 

low-iron, float glass mirrors, such as the SEGS trough plants in California, is approximately 94%. The 

manufacturing technology for mass-produced commercial glass, which employs formulations with higher iron 
 

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content, is extensive and mature. Mirrors constructed from this type of glass exhibit lower reflectivity, ≤90%, 

due to increased absorption and thickness. Large amounts of low-iron glass are manufactured for use in flatplate collectors used for water heating, but the manufacturing volume is much less than conventional glass. 

Because of the current, low-volume manufacturing capability for low-iron glass products, small order quantities 

of low-iron glass mirrors are expensive. As larger or more numerous CSP plants are built, the cost of low-iron 

mirrors should approach the price-point of the mass-produced conventional glass. 

An approach to increasing reflectivity using conventional glass formulations is to use thin glass mirrors, 

produced in large quantities for commercial applications such as compact cosmetic mirrors, to reduce the 

transmission losses. Thin glass mirrors are typically no less expensive per square meter of reflector than thick 

glass mirrors because the raw material cost savings are offset by increased handling costs and breakage. The 

baseline trough and tower designs use thicker glass as a structural element. The conversion to thin glass in these 

designs would require additional structural support. Additional mirror module support elements could be 

justified in stable markets where high volume, low-cost production approaches would become practical, e.g., 

metal forming of automotive body panels. 

Flexible ultra-thin mirror constructions consisting of silvered micro-thin glass superstrates, all-dielectric (nonmetallic) multilayer constructions, and silvered polymer or sheet metal substrates are being investigated and 

could enable innovative concentrator designs that offer the possibility of lower costs than current designs. 

Reflectivity values >94% have been demonstrated, but a cost-effective mirror product durable enough for use in 

a CSP plant, which requires both long-term outdoor exposure and frequent cleaning, must still be developed and 

proven. 
Appendix I 

Sargent & Lundy Response to the NRC 

Issues and Observations 
 

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I. SARGENT & LUNDY RESPONSE TO THE NRC 

ISSUES AND OBSERVATIONS 

Sargent & Lundy reviewed the National Research Council (NRC) Committee’s “Critique of the Sargent & 

Lundy Assessment of Cost and Performance Forecasts for Concentrating Solar Power, October 12, 2002.” The 

NRC review was performed on Draft 3 of the Sargent & Lundy Report, SL-5641, dated October 2002. S&L was 

authorized by NREL to update the report to expand the executive summary to provide more information as 

suggested by the NRC and perform additional sensitivity analysis. This included the following: 

• Executive Summary 

• Section 4.6, “Risk Assessment for Trough Technology” 

• Section 4.7, “Cost Sensitivities” (Trough) 

• Section 5.8, “Risk Assessment for Tower Technology” 

• Section 5.9, “Cost Sensitivities” (Tower) 

• Appendix I, “Sargent & Lundy Response to the NRC Issues and Observations” 

S&L’s general comments to the NRC critique and response to specific comments are as follows: 

General Comments

A. The NRC review found that “Since 1999, significant progress has been made in understanding the potential 

impacts of thermal storage technologies, thin film glass mirrors, improved heat collection units, improved 

trough support structures, and other technical opportunities to improve CSP technology” (NRC, page 4). 

The NRC review of S&L’s analysis of trough technology found that “Based on the level of uncertainty that 

is inherently present in projecting these deployment rates and technology advances, a more plausible 

estimate would lie somewhere between the two projections (S&L’s and SunLab’s) in 2020. However, if 

deployment does not proceed at the assumed rate, the projected LEC could be much higher than either of 

these estimates” (NRC page 6). S&L welcomes the NRC endorsement of our analysis, finding that projected 

costs are likely to lie somewhere between our high-cost and SunLab’s low-cost estimates for the assumed 

deployment rates. 

B. The NRC Committee also noted “...that S&L took any potential conflict of interest very seriously and made 

a concerted effort to address and avoid it. No obvious example of bias was apparent in S&L’s interpretation 
 

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of the available data nor was there any deliberate omission of pertinent facts. If anything, the S&L analysis 

was more conservative than SunLab’s estimates in assessing areas like time to develop new materials or 

power conversion technologies” (NRC, page 18); and: “...that S&L attempted to maintain a credible process 

by filling in the gaps in its knowledge base with the advice of world-recognized experts” (NRC page 18). 

C. On page 20, the NRC Committee noted: “...that within the time and resources available for this study, S&L 

did a reasonable job in digesting the information provided to it by DOE, S&L expert consultants, and 

members of the CSP industry. For example, S&L’s selection of component costs and economic parameters 

and assumptions regarding performance is well documented.” 

D. Much of the NRC critique of the S&L analysis centered around assumed rates of deployment and incentive 

issues. Deployment and incentive issues were outside the scope of work for S&L. As noted by the NRC: 

“The committee notes that CSP technology is not unique in the requirement for incentivizing the early 

market phases of emerging energy technologies [8]. The committee notes the extensive reports and study 

literature on these issues cited by S&L, including DOE/EERE’s own August 2002 Report to Congress on 

the Feasibility of 1,000 Megawatts of Solar Power in the Southwest by 2006....” DOE noted in their 

presentations to the NRC and S&L that because such studies were available, DOE’s primary concern, and 

the reason for this study, was to determine the potential technical feasibility of CSP. Nevertheless, there are 

several deployment issues worth considering. First, the chicken-and-egg problem of driving down costs by 

deploying technologies, but facing high initial costs that impede deployment, is true of all energy 

technologies, not just CSP. Second, as noted by the NRC and S&L, incentives are a key determinant of the 

rate at which CSP, or any new energy technology, penetrates the market. Evaluating this lies well outside 

the technical analysis requested of S&L. Third, the level of deployment identified by S&L is modest, at 1.5 

to 2.8 GW by 2020 for towers and troughs respectively. The NRC also noted this: “The SunLab deployment 

scenarios evaluated by S&L represent a range from a modest rate of adding one 100 MWe plant per year 

(the first becoming operational in 2004) to an aggressive approach that would result in almost 5,000 MWe 

of new capacity by 2020” (NRC page 5). To place this level of deployment in context, the wind industry 

added 1,700 MW of new capacity in the U.S. in 2001 alone. 
 

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Sargent & Lundy Comments to Specific Observations Made by the NRC

Observation 1: ‘S&L’s modeling approach parallels SunLab’s in almost all aspects.’ [NRC page 4] 

Comment: S&L’s scope of work was to perform a review of the SunLab model (ref: Section 1.3.2) and to 

comment on the accuracy of the inputs and the results, not to develop an independent bottoms-up cost estimate, 

which would involve a much more detailed engineering cost analysis. In addition to its own experience, S&L 

drew heavily from industry experience, vendor quotes, and other independent sources to evaluate cost and 

performance projections. Separately, S&L developed a financial model of the type used in competitive industry 

to support power project planning and financing (ref: Section 1.3.7). 

Observation 2: ‘...its review did not sufficiently examine the effect of uncertainties on these parameters.’ 

[NRC page 5] 

Comment: S&L conducted a limited number of sensitivity studies as pointed out by the NRC (page 5), but due 

to the work scope changes requested by the NRC and DOE and compressed schedule, S&L did not have time to 

develop a full range of sensitivity studies. S&L performed additional cost sensitivities and risk assessments per 

the NRC’s suggestion (see Section 4.6, 4.7, 5.8, and 5.9) for the final report. 

Observation 3: ‘The discussion of risks and uncertainty is extremely shallow’ [NRC page 8] 

Comment: S&L conducted a limited number of sensitivity studies as pointed out by the NRC (page 5), but due 

to the work scope changes requested by the NRC and DOE and compressed schedule, S&L did not have time to 

develop a full range of sensitivity studies. S&L performed additional cost sensitivities and risk assessments per 

the NRC’s suggestion (see Section 4.6, 4.7, 5.8, and 5.9) for the final report. 

Observation 4: Heliostats ‘S&L appears to have accepted ADL’s (Arthur D. Little) analysis without much 

question and has not commented on the viability of ADL’s vendor estimates’ [NRC page 8] 

Comment: S&L reviewed available information on heliostat costs and found that the ADL analysis was the most 

thorough available and therefore used it as a basis for comparison. The viability of the ADL estimate was 

reviewed in detail. The comparison of S&L, SunLab, and ADL cost estimates is shown in Table E-14. Where 

we accepted the ADL cost estimate, a discussion of the reasoning is provided in Appendix E.5. The discussion 

documenting our review for each cost category for manufacturing and installation of heliostats is also provided 

in Appendix E.5. Several examples are provided below: 
 

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• The cost of mirrors referenced in the ADL report was based on actual cost estimates from 

mirror manufacturers (ref: Appendix E.5.1). The SunLab estimate is about twice the cost of 

normal glass, which allows for a premium for manufacturing production runs. The opportunities 

this suggests for further cost reductions were not considered in the analysis. 

• Evaluation of mirror assembly costs was based on ADL and the SolMaT study done by Solar 

Kinetics, Inc. (ref: Appendix E.5.2) 

• Drive costs are based on detailed studies and cost estimates by Peerless-Winsmith, a 

manufacturer of commercial drive mechanisms. The cost data were based on a detailed material 

list of parts, labor, and cost for pattern & tooling. (Ref: Appendix E.5.3) 

• Evaluation of Production (Shop) Fabrication was based on studies done by ADL and Solar 

Kinetics. Both studies were reviewed, and the Solar Kinetics estimate was used for comparison 

instead of the ADL study. (ref: Appendix E.5.5) 

Observation 5: ..scale-up of heliostats from 95 m2 to 148m2. S&L has not commented on the viability of 

this scale-up.’ [NRC page 8] 

Comment: The reasoning behind not including additional discussion is that 148-m2 heliostats have been 

manufactured and prototypes are in service (ref: Section 5.8.2.2). We concur that additional discussion of the 

viability of the scale-up could be provided, but since operational units of that size are available, it is not truly a 

scale-up concern. 

Observation 6: Thinner glass, improved aiming, etc. ‘...assumptions without much to back up how such 

improvements will be accomplished’ [NRC page 8] 

Comment: The current development of thinner glass is identified in Section 4.3.3 for troughs and has been 

referenced in the tower section (Section 5.3.1.1) for the final report. 

Observation 7: It is unlikely that it (steam inlet) will go to 640°C in the next 18 years. [NRC page 8] 

Comment: There is ongoing research to increase steam turbine efficiency by increasing the steam inlet 

temperature. There are units currently operating at 1,100°F (593°C). The question of likely or unlikely is 

dependent on what the demand for solar units is over the next 16 years. Sixteen years ago no one projected 

today’s current market for combustion turbine combined-cycle power plants. For the final report, S&L adjusted 

the base case for tower technology in 2020 not to include the higher temperature turbine or advanced heliostat 

design. We then performed a sensitivity analysis to calculate the change in LEC for the higher temperature 

turbine and advanced heliostat design. 
 

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Observation 8: Furthermore, it is not clear that S&L really determined efficiency levels from GE data 

systems for small-plants.... [NRC page 8] 

Comment: The near-term turbine efficiency was verified based on the ABB-Brown Boveri heat balance 

diagrams for SEGS IX 89-MW unit (ref: Appendix E.6.2.1). S&L used the GE program STGPERF to estimate 

efficiencies, which is typically used for steam turbines in combined-cycle power plant (e.g., ‘small plants’) (ref: 

Section 5.3.2). 

Observation 9: Receivers. ‘S&L makes no comment about the severe technical risk in developing hightemperature and high-heat flux systems for the future.’ [NRC page 9] 

Comment: The overall technical feasibility of high temperature, high heat-flux systems was demonstrated by 

Solar Two in the late 1990s. There remain challenges in scaling up these systems while meeting performance 

and lifetime requirements, but there do not appear to be any fundamental technical limits or “severe” risks. S&L 

did not go into considerable detail, but did indicate that the advance from Solar 200 to Solar 220 (turbine inlet 

steam temperature increase from 540°C to 640°C) would result in several areas of concern. Relative to this 

scale-up, our report states that “The major issue will be the higher temperatures and impact on materials” (ref: 

Appendix E.6.2.2). For the final report, S&L adjusted the base case for tower technology in 2020 not to include 

the higher temperature turbine or advanced heliostat design. We then performed a sensitivity analysis to 

calculate the change in LEC for the higher temperature turbine and advanced heliostat design. 

Observation 10: Thermal Storage. ‘...that advantages were assumed without significant consideration of 

all the side issues that might result with molten salts, e.g. pumps, seals, and pipes at temperature levels of 

> 500°C. [NRC page 9] 

Comment: The overall technical feasibility of high-temperature molten salt storage was demonstrated by Solar 

Two in the late 1990s. There remain substantial challenges in scaling up these systems while meeting 

performance and lifetime requirements, but there do not appear to be any fundamental technical limits. S&L did 

not go into considerable detail, but did indicate that the advance from Solar 200 to Solar 220 (turbine inlet steam 

temperature increase from 540°C to 640°C) would result in scale up concerns as documented in the statement 

that “The major issue will be the higher temperatures and impact on materials” (ref: Appendix E.6.2.2). For the 

final report, S&L adjusted the base case for tower technology in 2020 not to include the higher temperature 

turbine or advanced heliostat design. We then performed a sensitivity analysis to calculate the change in LEC 

for the higher temperature turbine and advanced heliostat design. 
 

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Observation 11: O&M. ‘However, there should be more comment about O&M practices and the 

differences between tower and trough technology.’ [NRC page 11] 

Comment: The differences between towers and troughs are provided in Appendix G. For example: 

• The solar field maintenance staff, including mirror wash crew, is adjusted based on the 

difference in the collector fields. 

• Parts and material, which are similar to both types of plants, are based on actual costs from 

SEGS. 

• Parts and material, which are unique to towers, are estimated based on experience from the 

demonstration projects. 

Observation 12: ‘...is clear that S&L did not do a “due-diligence-like” analysis.’ [NRC page 11] 

Comment: S&L agrees that the review is not a due-diligence review for the deployment of the units. In 

particular, “due-diligence” reviews are of commercially available technologies under consideration for 

investment. In contrast, this review was “due-diligence-like” as the technologies are not commercially available, 

but the intent was to have a similarly rigorous review of the projected technologies’ cost and performance using 

independent reviewers. A due-diligence review would also require estimating the incentive support levels 

necessary for technology deployment, which was not part of the Scope of Work for this study. It is clear that 

without incentives the capital cost cannot be supported by the market and capital cost will not be reduced 

without deployment of significant units to obtain manufacturing efficiencies. Therefore, unless support 

incentives are contemplated, deployment will not occur in any case. 

Observation 13: ‘The committee believes that the S&L projection of a 100-MW plant being operational in 

calendar year 2004 is not credible....’. S&L’s report and projection are deficient in this regard. ‘...the 

committee believes that S&L’s projections is still unrealistically optimistic.’ [NRC page 12] 

Comment: S&L’s scope of work did not include an assessment of market conditions and deployment 

projections. The report clearly identifies that deployment is assumed to occur based on the dates provided by the 

DOE based on earlier, now outmoded, scenarios and projections developed by SunLab. Since this was outside of 

our work scope, we take exception that the ‘report is deficient in this regard.’ As noted previously, DOE has 

separately provided Congress with an analysis of deployment issues. We do, however, agree that no one is 

developing the 100-MW unit, and therefore, it will not occur in the 2004 time frame, although a 50-MW unit is 

now under development in Nevada. 
 

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Observation 14: These time delays (2-year minimum construction delay between new generation plants) 

were not factored into the deployment rate assumed in the S&L study. [NRC page 12] 

Comment: These delays were factored into the deployment rate assumed by S&L. Ref: Appendix E.2 and Table 

E-3. The final report includes a sensitivity analysis for increases in construction duration in Section 4.7 and 5.9. 

Observation 15: It would have helped if S&L had commented on what would have to be done to reduce 

the risk so that investors would be willing to invest this level of capital....’ [NRC page 13] 

Comment: This was not included in our original scope of work. The final report includes sections on risk 

assessment (Section 4.6 and 5.8). 

Observation 16: However, the set of assumptions used in the LEC calculation forced the debt/equity ratio 

from 59.9 percent to 66.5 percent debt, and it did not make much sense to the committee to allow the 

inference that removing one tax incentive would induce a commercial lender to accept more, higher-risk 

debt without raising the interest rate. [NRC page 13] 

Comment: Removing the tax credit has two effects: (1) The project company loses a big offset against other 

income tax during Year 1 because it cannot take the investment tax credit deduction against other income tax. 

(2) The project company has higher depreciation charges without the ITC, because when the ITC is present, the 

depreciable base for the project must be reduced to exclude the ITC. 

Consider Case 5 (Towers, 2020 Startup, SunLab Data). If one simply removes the ITC without increasing 

revenue requirement, the combination of the two impacts mentioned above is to reduce the after-tax return on 

equity (ROE) to 9.4%/yr, which is considerably lower than our study assumption of 14%/yr. (These all are 

nominal dollar values being citing here for illustration, not constant-dollar.) Since we should recognize the ROE 

as a project cost that has to be covered, it is logical to adjust revenues upward until we have restored the 14% 

after-tax return. 

If the leverage is not changed and ROE is restored to 14% by increasing the capacity revenue requirement (is an 

increase of around 20%), then the minimum debt service coverage ratio (DSCR) becomes 1.60 instead of the 

1.35 study assumption, indicating a larger margin of safety for lenders for uncertainties in costs than in the base 

case at 1.35 DSCR. Since interest is covered at a higher multiple, it is reasonable to think the credit spread 

component of the debt interest rate for the 1.60 case would be lower, and the debt interest rates thus would be 
 

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lower than the 7.00% value in the reference 1.35 DSCR case because DSCR is an indicator that is commonly 

used by lenders to assess the level of risk in a deal. Basically, the lenders would be more comfortable with the 

project because the capacity component of the revenue stream would be 20% higher, giving greater margin 

before some adverse event (e.g., unexpectedly higher cost) might prevent debt from being serviced. 

Because we would like to evaluate the various alternatives using the same costs of inputs (which include costs of 

equity capital, the ROE, and debt capital, the rate of interest), it is reasonable to adjust the leverage and capacity 

payment until the DSCR for the no-ITC case is the same as in the base case, and the ROE also is at 14%. If this 

is done, both cases will roughly correspond to a similar level of perceived risk from the lenders’ standpoints, and 

thus the costs of debt capital (and equity capital) for each alternative are the same. This is why the leverage was 

increased from 59.9% debt to 66.5%: to equate the costs of debt in the two cases. 

The NRC has a point in that larger loans and greater leverage generally causes lenders to want a higher interest 

rate, but our assumption here is that DSCR is a reasonable proxy for how the lenders would perceive risk--which 

is true to a first order of approximation (actual underwriting takes into account many factors), so we have 

adjusted leverage to get the same degree of perceived risk, from the lenders’ point of view, in both the base case 

and the sensitivity case. 

Observation 17: To a large degree, the S&L team relied on information provided by DOE, NREL, 

SNL.... [NRC page 14] 

Comment: The work scope was for S&L to perform a ‘due-diligence-like’ review on information provided by 

the client, with additional information provided during the first NRC meeting. The work scope did not include 

independent research for information or developing independent cost estimates. The S&L work did include 

review and assessment of available reports and information, including information from industry and vendors. In 

addition, it should be noted that in the time period that we had to complete the work, we did contact vendors and 

visit the Kramer Junction power station. The limited information we were able to obtain from these sources was 

used to adjust the DOE, NREL, and SunLab data as appropriate. Developing completely independent 

information for the reviews would have increase the cost considerably, increased the schedule significantly, and 

probably not have identified a significant amount of truly new information. 
 

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Observation 18: ‘...S&L claimed that its cost and performance projections came from “industrial 

projections”, a large part of the cost information was generated using the SunLab cost model with a few 

changes to reflect the view of S&L’ [NRC page 14] 

Comment: This is in conflict with the NRC committee’s statement ‘The SunLab cost model has been developed 

with substantial industry input over the years and is backed by industry experience and engineering studies, 

often developed under contract to SunLab of in collaborations among SunLab, industry, and consultants.’(NRC 

page 14) For example, the cost estimate for tower receivers was provided by Boeing, who manufactured the 

receivers for Solar Two and will be the manufacturer for Solar Tres. 

Sargent & Lundy made numerous changes as identified below: 

1. Annual Solar-to-Electric Efficiency (Section 4.2 and 5.2) 

• Trough: S&L estimated 15.5% in comparison to SunLab projection of 17.2% 

• Tower: S&L estimated 17.7% in comparison to SunLab projection of 18.1% 

2. Capital Cost (Section 4.3 and Appendix E.1) 

• Trough: S&L estimated the total plant cost of $3,220 per kWe in comparison to SunLab 

projection of $2,225 kWe. Each cost category was reviewed, and S&L made our estimate based 

on the best available information. 

• Trough: S&L estimated the total plant cost of $590.7 M in comparison to SunLab projection of 

$506.1 M. Each cost category was reviewed, and S&L made our estimate based on the best 

available information. 

3. The net annual solar-to-electric efficiency has a significant impact on the size of the collector field and 

hence the cost. S&L evaluated the efficiencies and made projections based on our review of the available 

information. (Ref: Appendixes D.3.5 and E.3.2) 

• Trough: The three major differences for tower technology were the following: 

 S&L assumed that efficiency for reflectivity would only reach 94% in 2018 as compared to 

the SunLab estimate of 95%. 

 S&L assumed that efficiency for mirror cleanliness would only reach 95% in 2018 as 

compared to the SunLab estimate of 97%. 

 S&L assumed that efficiency for EPGS would only reach 45.4% in 2018 as compared to 

the SunLab estimate of 46.1%. 
 

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• Tower: The major differences for trough technology were the following: 

 S&L assumed that efficiency for reflectivity would only reach 9.5% in 2020 as compared 

to the SunLab estimate of 95%. 

 S&L assumed that efficiency for mirror cleanliness would only reach 95% in 2018 as 

compared to the SunLab estimate of 96%. 

 S&L assumed that efficiency for receiver would only reach 81% in 2020 as compared to 

the SunLab estimate of 85.3%. 

As can be seen, S&L did not just accept the assumptions for the SunLab model, but performed an independent 

evaluation. In cases where we used the SunLab number, the numbers were reviewed and found to be reasonable 

for the purpose of the study. 

Observation 19: ‘...the S&L report did not present sufficient evidence of the likelihood of success for each 

projected advance in technology. [NRC page 16] 

Comment: Appendix D and E discuss the details of our evaluation. For example, Appendix E.9.2 discusses the 

technology improvement for the tower steam generator. The discussion includes the problems encountered 

during the Solar Two demonstration project and what was or is being done to solve the problems. 

Observation 20: ‘...there is no discussion in the S&L report as how these incentives will come about in the 

United States or if they will be sufficient to induce the assumed deployment rates. [NRC page 17] 

Comment: This issue was not included in S&L’s scope of work as discussed above, nor is this issue within the 

NRC’s domain; it properly lies with the President and the Congress. 

Observation 21: ‘All required capital expenditure should include investment in manufacturing capacity 

required, cost for project formation, and so on. [NRC page 17] 

Comment: This was not included in S&L’s scope of work. The pricing of the equipment from the vendors will 

reflect this investment and their projections on the number of units, which will be manufactured allowing them 

to recover their investment costs. Therefore, this issue is really irrelevant for the current discussion. It is relevant 

only to the extent that the manufacturers of the equipment may never develop if the capital costs are too high. 
 

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Observation 22: ‘S&L should have attempted to identify a basis for comparing these two systems (towers 

and troughs) even though both are at a different stage of technical development.’ [NRC page 17] 

Comment: This comparison was not included in S&L’s scope of work, but one indicator can be observed in the 

cost projections for the various systems. 

Observation 23: ‘...mention should have been made of potential siting issues in achieving the level of 

deployment that has been assumed.’ [NRC page 17] 

Comment: The S&L draft report issued September 2002 included a discussion of power generation markets, 

which included siting issues. Subsequently, due to a tight schedule and because deployment issues were 

addressed separately, the DOE directed that the scope of work not include an evaluation of deployment and 

associated issues. 

Observation 24: ‘S&L did not consider the probability that the efficiencies resulting from these technical 

developments might not occur’ [NRC page 18] 

Comment: Additional sensitivity analysis and risk assessment were performed in the final report (Sections 4.6, 

4.7, 5.8, and 5.9). 

Observation 25: ‘S&L did not consider possible accidents that might happen in handling very large 

quantities of potentially hazardous materials for more than 30 years.’ [NRC page 18] 

Comment: The scope of work did not include an environmental impact study. As mentioned in the report, SEGS 

has been operating since 1984 with no significant accidents from the heat transfer fluid. The financial impact of 

significant accidents is no different than for any other industry handling potentially hazardous materials. The 

risk is minimized with (1) proper engineering, design, manufacturing, and construction; (2) proper operating and 

maintenance procedures and methods; and (3) insurance. 

Observation 26: ‘Other sources of uncertainty that were not discussed in the S&L report....’ [NRC page 

18] 

Comment: S&L’s estimate of LEC of tower technology included a 10% contingency for deployment and an 

uncertainty factor for technology (15%), scaling (10%), and volume production (20%). (ref: Appendix E.12) 
 

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Additional sensitivity analysis and risk assessment were performed in the final report (Sections 4.6, 4.7, 5.8, and 

5.9). 

Observation 27: The S&L report has little of no discussion of the risks of not achieving these R&D goals 

nor of the magnitude of the R&D program necessary to accomplish these advances. [NRC page 19] 

Comment: S&L identified the R&D required to achieve cost reductions (for example: Section 4.2.1 discussed 

the R&D required for solar field optical efficiency.) S&L solicited information on the magnitude of the R&D 

program, but a significant portion of the developmental work is being performed by the manufacturers and is 

confidential. Additional sensitivity analysis and risk assessment were performed in the final report (Sections 4.6, 

4.7, 5.8, and 5.9). 

Observation 28: ‘Regrettably, the rational behind S&L’s selections (LEC) is incompletely described in its 

report.’ [NRC page 21] 

Comment: Section 4 (trough technology) and Section 5 (tower technology) discusses our review of major cost 

components. The rational of our evaluation is presented in more detail in Appendix D (trough) and Appendix E 

(tower). The S&L financial model was used to calculate LEC based on our estimated capital cost and annual 

O&M for trough and tower technologies. The rational for the financial model is presented in Appendix B.8, 

“Financial Modeling,” and Appendix C, “Levelized Cost for Ranking Alternatives and Example Calculations.” 

Observation 29: ‘In none of these areas (compound risks associated with the advanced technical 

development and current level of deployment) does S&L clearly articulate the rational and methodology 

used to arrive at component costs and system performance. In light of these deficiencies, the committee is 

unable to ascertain whether S&L’s projected capital costs and LECs are more accurate than those of 

SunLab and others.’ [NRC page 22] 

Comment: Again, the work scope did not include an assessment of deployment and incentives. The rational to 

arrive at component costs and system performance is discussed in the report, in particular Appendixes D, E, F, 

and G. 

Observation 30: ‘...the committee finds that insufficient attention is given to the sensitivity of the 

projected LEC’s to the financial parameters used in the modeling.’ The committee finds that the above 
 

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omission calls into question the reliability, accuracy, credibility, and utility of the S&L analysis. However, 

the committee also finds that these omissions are a correctable defect in the report. [NRC page 22] 

Comment: S&L disagrees with the statement “above omission calls into question the reliability, accuracy, 

credibility, and utility of the S&L analysis.” A more detailed sensitivity analysis was not performed in the draft 

report due to schedule and budget constraints. Additional sensitivity analysis and risk assessment were 

performed in the final report (Sections 4.6, 4.7, 5.8, and 5.9) as a “correctable defect in the report.” 

Observation 31: ‘the committee urges DOE to request a revised executive summary that clarifies and 

points out the important limitations of the analysis methods, assumptions, and parameters in this study. 

[NRC page 22] 

Comment: The executive summary has been revised to include the limitations that we feel are important, but we 

do not agree with all the ‘limitations’ pointed out by the NRC committee are valid. 

Observation 32: ‘...the S&L team did not do a bottoms-up cost analysis of the possibilities (or 

probabilities) of reducing the cost of CSP plants. Rather it relied on a SunLab model and put in some of 

its own judgement. [NRC page 22] 

Comment: Again, our scope of work did not include a bottoms-up cost estimate. Our scope was to review and 

provide an opinion on the cost estimates prepared by SunLab, which was prepared with input from industry and 

vendors. 
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1. AGENCY USE ONLY (Leave blank) 2. REPORT DATE

October 2003 

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Subcontract Report 

4. TITLE AND SUBTITLE

Assessment of Parabolic Trough and Power Tower Solar Technology Cost and 

Performance Forecasts 

6. AUTHOR(S) 

 Sargent & Lundy LLC Consulting Group 

5. FUNDING NUMBERS

CP032000 

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

Sargent & Lundy Consulting Group 

55 East Monroe Street 

Chicago, IL 60603-5780 

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National Renewable Energy Laboratory 

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Golden, CO 80401-3393

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13. ABSTRACT (Maximum 200 words)

Sargent & Lundy LLC conducted an independent analysis of parabolic trough and power tower solar technology cost and 

performance. 

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parabolic trough, power tower, solar, solar technology, concentrating solar power, 

CSP, power generation 16. PRICE CODE

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