Technical Report

NREL/TP-550-47605

July 2010

Parabolic Trough Reference 

Plant for Cost Modeling with 

the Solar Advisor Model (SAM)

C. Turchi
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Technical Report

NREL/TP-550-47605

July 2010

Parabolic Trough Reference 

Plant for Cost Modeling with 

the Solar Advisor Model (SAM)

C. Turchi

Prepared under Task No. SS01.2340
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1 

Parabolic Trough Reference Plant for Cost Modeling with the 

Solar Advisor Model

Summary

This report describes a component-based cost model developed for parabolic trough solar power 

plants. The cost model was developed by the National Renewable Energy Laboratory (NREL) 

with assistance from WorleyParsons Group Inc. for use with NREL’s Solar Advisor Model 

(SAM). This report includes an overview and explanation of the model, two summary contract 

reports from WorleyParsons, and an Excel spreadsheet for use with SAM 2010-04-12. The cost 

study uses a reference plant with a 100-MWe capacity and six hours of thermal energy storage. 

Wet-cooling and dry-cooling configurations are considered. The spreadsheet includes capital and 

operating costs by component, e.g., mirrors, heat transfer fluid, operators, etc., to allow users to 

estimate the impact of changes in component costs. Costs estimated by WorleyParsons were 

adjusted for a slight change in plant size and relocation to southwest Arizona. The solar field 

costs estimated by WorleyParsons were reduced based on input from trough developers. The 

spreadsheet also allows users to estimate the costs of different-size plants and to take into 

account changes in commodity prices. The Excel spreadsheet can be downloaded at 

https://www.nrel.gov/analysis/sam/templates.html. 

Background and Motivation

The Solar Advisor Model was developed to assist solar stakeholders in assessing the 

performance and cost of photovoltaic (PV) and concentrating solar power (CSP) electricity 

generation systems. SAM incorporates modules that estimate the performance of different PV 

and CSP systems based on design parameters and climate files that include solar and weather 

data for the selected location. The current SAM version, released in April 2010, is available at 

https://www.nrel.gov/analysis/sam/. SAM also includes algorithms to estimate the levelized cost 

of electricity (LCOE) based on a variety of selectable financial and incentive assumptions. 

Essential inputs of the LCOE calculations include the estimated installed cost and operating cost 

of the technology. 

Parabolic troughs represent the most mature of the different CSP technologies and more than 500 

MW of trough plants are operating in the United States and Spain. In addition, several gigawatts 

(GW) of trough plants have been proposed for locations around the world [1]. Because of this, 

the parabolic trough model is one of the more commonly used components within SAM. The 

trough plant model within SAM uses a set of cost inputs to calculate the total installed cost and 

LCOE of the specific plant case input by the SAM user.

Prior to October 2009, NREL’s default cost inputs for the parabolic trough were based on 

references dating back as far as 1999, as well as more recent discussions with developers and 

industry members. Knowing that the 2009 release of SAM would be a major revision, NREL 

decided to undertake an update to the parabolic trough cost model. This update started by 

specifying conditions for a representative plant and contracting with an experienced engineering 

firm to perform a conceptual design and budgetary cost estimate for the facility. The desire to 

update the parabolic trough cost model was further motivated by the fluctuations in commodity 
2 

prices witnessed from 2007 to 2009. Simple corrections for inflation rate were not accurate for 

tracking yearly changes in system components such as steel and nitrate salt. The revised cost 

model was to tie different system components (e.g., heat-transfer fluid, nitrate salt, steel tanks 

and heat exchangers) to industry price indices that provide a better mechanism for tracking 

market price fluctuations.

Approach

NREL contracted with WorleyParsons Group, Inc. (Golden, CO) to perform a design and cost 

analysis of the representative trough plant. WorleyParsons’ Renewable Energy Program includes 

comprehensive services related to all aspects of project development, environmental impact 

assessment, detailed design, procurement, construction and operations & maintenance of 

renewable energy power plants. WorleyParsons’ capability in CSP system engineering and 

design is exemplified by their history of engineering design and cost support for multiple 

renewable energy and conventional power projects in the United States and abroad. 

NREL provided WorleyParsons with nominal design specifications for the reference plant, as 

outlined in Table 1. Using this guidance, WorleyParsons completed a conceptual design and cost 

assessment of a parabolic trough plant with wet cooling and optional dry cooling. The wetcooled plant represented the base case for the analysis; a dry-cooled plant with the same nominal 

capacity was also examined. WorleyParsons considers the confidence interval for this level of 

cost estimate to be ±30%.

Table 1. Baseline trough plant specifications provided to WorleyParsons

Baseline Plant Conditions

Nameplate Capacity 100 MWe

Thermal Storage (operating time 

at nameplate capacity) 6 hours

Solar Multiple 2.0

Heat Transfer Fluid Synthetic oil

Storage Fluid Binary Na/K nitrate salt

Thermal Storage System Indirect “2-tank” system [6]

Power Cycle Superheated steam Rankine cycle with wet cooling

Location Daggett, CA

Variation (1) 

Air-cooled system of same nominal capacity & 

storage

In addition to the contract work provided by WorleyParsons, NREL continued a dialog with 

various solar developers and engineering/construction firms. In general, discussions with 

industry indicated equivalent or slightly lower costs than reported by WorleyParsons. Some of 

the difference was attributed to developers’ vertical integration or negotiation of final prices, 
3 

although it is also likely that scope and accounting practices are not completely consistent. The 

resulting values for a hypothetical 100-MWe net plant are shown in Table 2. These values 

consider input from WorleyParsons as well as from other solar industry members. 

The primary purpose of the WorleyParsons contract was to develop a line-item cost model that 

SAM users could manipulate to represent cases of interest. The costs shown in Table 2 are for a 

reference plant located in southwest Arizona with merit-shop labor and may not be 

representative of other locations or markets within the United States. As in previous versions of 

SAM, users are cautioned to review the inputs and determine whether they are appropriate for 

their specific analysis.

Table 2. Cost inputs used for SAM Reference case Parabolic Trough plant.

Direct Cost (DC) Category Value used in 

SAM

Units

Site Improvements 25* $/m2

Solar Field 295 $/m2

HTF System 90 $/m2

Storage 80 $/kWh-t

Fossil Backup 0 $/kW

Power Plant (wet-cooled), based on turbine gross 940 $/kW

Power Plant (dry-cooled), based on turbine gross 1160 $/kW

Contingency 10 % of DC

Indirect Cost Category

Engineer, Procure, Construct 15 % of DC

Project, Land, Management 3.5 % of DC

Sales Tax 7.75 %

O&M Cost Category

Fixed Annual Cost 0 $/yr

Fixed Cost by Capacity 70 $/kW-yr

Variable Cost by Generation 3 $/MWh

Fuel Cost 0 $/MMBTU

Other

Availability (based on 2-week outage in January 

plus 7 days forced outage per year)

96 % 

* average value. Estimate is slightly higher for wet-cooled plant and slightly lower for a 

dry-cooled plant due to elimination of evaporation ponds 

System Availability is used in SAM to reduce the annual generation that is estimated by plant 

design and climate data alone. In the case of a solar plant, daily output varies by season and the 

impact of an outage in summer is much greater than one in winter. The value of 96% assumes a 
4 

two-week planned outage in January and seven days of forced outage throughout the year. The 

forced outage days assume an annual average daily output is lost. Forced outages are not weather 

related, but indicate some equipment-related failure. 

Wet-Cooled and Dry-Cooled Plant Results

The WorleyParsons contract reports on the wet-cooled plant and dry-cooled plant are provided as 

Appendix A and B, respectively. Table 3 is a summary comparison of the two designs. The 

WorleyParsons cost analyses were performed for an Engineering, Procurement, and Construction 

Management (EPCM) project contract. As such, several typical project costs were not included 

in the WorleyParsons estimates— most notably, those normally associated with owner’s costs. 

Typical owner’s costs include permitting, land, legal fees, geotechnical and environmental 

surveys, taxes, interest during construction, and the owner’s engineering and project 

management activities. In addition, WorleyParsons did not include sales tax in their analysis. 

These categories are accounted for in SAM under Indirect Capital Costs and are essential for 

calculating LCOE.

The bottom of Table 3 includes an estimate of Total Installed Cost and LCOE taken from SAM 

for the wet-cooled and dry-cooled designs. These estimates use the SAM cost values presented in 

Table 2, as explained above. The sizing parameters in SAM (e.g., solar field area, power block, 

reference insolation) were set to match the values in the WorleyParsons reports. Financial 

assumptions in SAM match those provided in the SAM Sample Parabolic Trough Systems file, 

i.e., 2.5% inflation rate, 8% loan rate, 8% real discount rate, 30-year project life, 35% federal and 

8% state tax rates, 15% required internal rate of return (IRR), Modified Accelerated Cost 

Recovery System (MACRS) depreciation, and 30% investment tax credit (ITC). 
5 

Table 3. Comparison of wet-cooled and dry-cooled parabolic trough plants in 

Daggett, CA, based on WorleyParsons Plant design.

Design Parameters Wet-Cooled 

Design

Dry-Cooled 

Design

% Change 

Power block net rating (MWe) 103 103 0

Thermal energy storage at design point (hours) 6.3 6.3 0 

Design conditions DNI (W/m2) 1000 1000 0

Design conditions wet-bulb temperature (°C) 21.8 21.8 0

Design conditions dry-bulb temperature (°C) 42.2 42.2 0

Size Parameters

Turbine gross rating (MWe) 118 120.5 +2.1%

Plant footprint (acres) 1018 1024 +0.6%

Solar Field area (m2) 987,540 1,062,750 +7.6%

Thermal storage media (metric tonnes) 62,000 66,800 +7.8%

Thermal storage size (MWh-t) 1988 2144 +7.8%

Output values estimated by WorleyParsons

Annual net electricity generation (MWh) 426,717 438,790 +2.8%

Capacity factor (based on 103 MWe net) 47% 48% +2.8%

Annual water consumption (m3) 1,530,000 

(1240 acreft)

114,000 

(90 acre-ft)

-93% 

Design point parasitic: HTF circulation pumps 

(MWe)

7.9 8.4 +6% 

Design point parasitic: Cooling system (MWe) 2.0 3.6 +80%

Design point parasitic: Total (MWe) 15.0 17.6 +17%

Annual O&M costs $11.8M $11.7M -1%

SAM Results using design and size parameters in 

this table and cost values from Table 1

Annual net electricity generation (MWh) 414,500 419,100 +1.1%

Total Installed Costs ($/kWe) 8950 9,810 +10%

LCOE (¢/kWh), nominal with 30% ITC 18.4 19.7 +7%

LCOE (¢/kWh), real with 30% ITC 14.6 15.6 +7%

SAM case files were created with the Physical Trough Model to replicate as closely as possible 

the WorleyParsons’ design assumptions. The SAM analysis was performed using the TMY3 

climate file for Daggett, CA, because this was the dataset used by WorleyParsons. The TMY3 

data have a slightly lower annual average insolation versus the TMY2 data for Daggett. 

The SAM runs gave total energy generation about 3% to 4% lower than that provided by 

WorleyParsons for both wet-cooling and dry-cooling cases. The difference is primarily due to 
6 

NREL using a plant availability of 96%, while WorleyParsons did not include plant availability 

in their estimate of annual net generation. Switching from wet to dry cooling raised plant 

installed cost by about 10% and LCOE by 7%. LCOE does not increase as much as installed cost 

due to the greater annual energy generation of the dry-cooled plant. The dry-cooled plant 

produces more energy because the solar field and power block are oversized to maintain designpoint generation at high ambient temperature. At the lower ambient temperatures that 

characterize most of the year, this combination generates more energy than the slightly smaller 

wet-cooled plant.

The annual energy generation and associated capacity factors shown in Table 3are higher than 

NREL normally estimates for a trough plant having six hours of storage. This results from the 

conservative design approach taken by WorleyParsons in the ratio of solar field to turbine size. 

The ratio of energy supply of the solar field to energy use by the power block at a specified 

reference condition is known as the solar multiple. Even without storage, solar trough plants are 

normally designed with a solar multiple larger than 1.0 to allow the power block to run at design 

point under less than ideal solar conditions. With six hours of storage, a solar multiple of 2.0 has 

been shown by NREL to minimize LCOE under typical conditions. Using WorleyParsons’ solar 

field and turbine size, SAM calculates a solar multiple of approximately 2.25. The relatively high 

solar multiple leads to a higher total installed cost, although the effect on LCOE is less dramatic, 

and under certain conditions negligible, due to additional energy generation. WorleyParsons 

believes the difference can be explained by their treatment of thermal loses external to the 

troughs and guaranteed (WP) vs. expected (SAM) equipment performance. 

One surprising finding is the dry-cooled plant occupies less land per MWh than the more 

efficient wet-cooled plant. This occurs because the additional solar field area required to 

maintain the net capacity of the dry-cooled plant is offset by elimination of over 60 acres of 

evaporation ponds.

Water Consumption

The primary reason for using dry cooling is to minimize water consumption. All thermoelectric 

power plants prefer to use wet cooling because this approach yields higher thermal-cycle 

efficiency. However, water may not be available or its usage may be prohibited or limited by 

policy. The WorleyParsons work found that a relatively small initial temperature difference 

(ITD) of 14°C in the air-cooled condenser (ACC) was the preferred design approach for drycooled parabolic trough plants. The smaller ITD means a more expensive ACC, but minimizes 

the additional solar field and turbine capacity needed to overcome the lesser efficiency of the 

dry-cooled plant. 

Table 4 highlights a comparison of water consumption by the two plant designs. Switching to dry 

cooling reduces water consumption by more than 93% by eliminating the evaporative-cooling 

tower. Remaining water consumption for mirror washing and steam-cycle applications increase 

due to the lower plant efficiency, but these effects are overwhelmed by eliminating the cooling 

tower. In the WorleyParsons design, a small amount of makeup water is necessary to support a 

wet-surface air cooler to provide low temperature cooling water for turbine components. Annual 

water consumption for the two plants is also listed in terms of acre-ft of water used per acre of 

total plant area. This format provides a useful comparison to agricultural water consumption. 
7 

Typical western crops such as cotton, alfalfa, and sugar beets require 2 to 4 feet of water for 

irrigation [4,5], i.e., more than twice the water required by a wet-cooled plant and more than 22 

times by a dry-cooled plant. 

Table 4. Comparison of water consumption for wet-cooled and dry-cooled trough plants. See Table 

3 for plant size information.

Water Usage (acre-ft per year)

Note: 1 acre-ft = 1233 cubic meters

Wet-Cooled 

Design

Dry-Cooled 

Design

% Change

Cooling tower makeup 1165 3 -99.7%

Blow-down quench and steam-cycle makeup 23 24 +4% 

Steam-cycle makeup during startup 13 19 +46%

Mirror washing 40 44 +10%

Total 1241 90 -93%

Annual water consumption (acre-ft/acre) 1.2 0.09 -93%

Impact of Labor Cost

Daggett, CA, has an excellent solar resource and has served as the CSP program’s de facto

representative location for several years. Although the resource and topography are attractive, the 

WorleyParsons analysis highlighted the relatively high labor rates in this region. Comparing the 

solar resource and labor rates for southern California and southwest Arizona indicates a 

significant reduction in installed cost and LCOE for a site in southwest Arizona. The NREL 

reference plant provided in the spreadsheet uses a southwest Arizona site. Relocation of the 

NREL CSP reference plant to SW Arizona also aligns with the historic use of Phoenix as the 

reference site for installed photovoltaic cost estimates. The reader should note that the 

WorleyParsons reports provided in the appendices use the higher Riverside, CA, union shop 

wage rates relevant for Daggett, CA. As described in the following section, NREL adjusted the 

WorleyParsons labor costs from southern California to southwest Arizona using data from the 

US Bureau of Labor. The Bureau of Labor statistics indicated a reduction of approximately 47% 

in labor rates (private industry, mean hourly wage, union labor, Riverside, CA versus nonunion 

Phoenix, AZ) [2]. 

WorleyParsons labor rates are based on an “all-in crew rate” for union labor in southern 

California that includes items which some developers may not consider labor. These overhead 

categories include rental equipment, field offices, temporary facilities, small tools, consumables, 

etc.; a complete listing is given in section 3.3.5 of the Appendix reports. Some of these labor 

overhead costs are fixed and not dependent on local payroll rates. Thus, as calculated by 

WorleyParsons, the reduction in “labor cost” by moving from California to Arizona is not equal 

to the 47% listed by the Bureau of Labor CA-AZ differential. To simplify labor rate corrections 

we shift a fraction of the labor costs into materials before applying the Bureau of Labor 

differential as described in the following section. This shift is also consistent with developer 
8 

feedback that the fraction of solar field cost that is affiliated with labor is significantly less than 

reported by WorleyParsons. 

For comparison, WorleyParsons also estimated labor using a “force account rate” that includes 

only payroll, fringe benefits, and statutory overheads. Accordingly the force account rate is 

substantially lower than the all-in crew rate. Discussion with solar developers suggests that 

developers may be using a labor rate closer to the force account rate and accounting for the items 

WorleyParsons considers labor overheads elsewhere. That is, the companies may utilize different 

labor accounting methods. 

Parabolic Trough Model Spreadsheet and NREL Reference Trough Plant

The primary objective of the WorleyParsons contract was to help create a model framework that 

would allow SAM users to look at the cost impact of individual components of a typical 

parabolic trough plant. For example, mirror manufacturers wish to know how much of the total 

plant cost is due to the cost of the reflector materials. Secondly, the rapid fluctuations in 

commodity prices over the last two years highlighted the need to keep the cost model current by 

incorporating appropriate cost indices for the different cost components. The result of these 

objectives was the creation of a spreadsheet-based cost model for a hypothetical parabolic trough 

plant of 100-MW capacity with 6 hours of thermal energy storage, based partly but not entirely 

on the WorleyParsons work. The model allows users to update costs for changes in technology or 

markets. This spreadsheet, available for download at 

https://www.nrel.gov/analysis/sam/templates.html, is designed to interface with the Physical 

Trough Model in SAM. Users are encouraged to customize the spreadsheet model for their 

individual purpose. Guidelines for use are provided below and within the spreadsheet itself. 

The spreadsheet includes cost indices to escalate component and labor costs for inflation and 

market factors. Cost indices in the spreadsheet model are based on the Chemical Engineering 

Plant Cost Index published monthly in Chemical Engineering Magazine and available online at 

http://www.che.com/. Additional cost indices are taken from the U.S. Bureau of Labor’s 

Producer Price Index (PPI), which can be tracked on line at http://www.bls.gov/ppi/. The 

spreadsheet includes a PPI index for synthetic ammonia to represent the nitrate salt storage 

media in trough plants. This public index tracks the nitrogen fertilizer market; however, vendor 

data suggest it may not be an accurate surrogate for solar salt prices. Salt price has a large impact 

on overall storage costs and users are encouraged to check with vendors for these prices. A 

vendor-supplied estimate of historic solar salt prices is included. Users may also customize the 

spreadsheet by choosing alternative cost indices. Within the spreadsheet, a specific cost index is 

selected by changing the Matl cost esc Factor or Labor cost esc Factor. 

The spreadsheet contains cost information for two trough plants: a “reference plant” and a 

“project plant.” The reference plant (highlighted in yellow) is defined as a 100-MWe trough plant 

with 6 hours of thermal energy storage located in southwest Arizona. The solar multiple was set 

to 2.0, and SAM was used to calculate the associated solar field size. The TMY3 climate file for 

Blythe, CA was selected as the best representation of southwest Arizona. Blythe sits on the 

California/Arizona border. If this climate file is not in your SAM database it can be downloaded

from the TMY3 website by following the instructions on the SAM Climate Page. (As an 

alternative the user can use the Tucson TMY2 climate file included in SAM.) Because the 
9 

WorleyParsons work did not exactly match these plant conditions, the line-item capital and labor 

cost values provided by WorleyParsons were adjusted as follows: 

• Solar field, site preparation, and heat transfer fluid (HTF) system costs were scaled 

linearly to the smaller solar field area in the NREL reference plant.

• Thermal storage costs were scaled linearly to the smaller storage capacity in the 

NREL reference plant.

• Power block costs were scaled by the 0.7 power to the smaller power block in the 

NREL reference plant.

• Labor rates were adjusted to represent Arizona wage scales. This adjustment was 

made by comparing the mean hourly earnings for workers in the occupation category 

of Natural Resources, construction and maintenance from the U.S. Bureau of Labor. 

The adjustment compared Phoenix, AZ, and union-shop, LA-Long Beach-Riverside, 

CA, datasets from April 2008 [2]. 

• Several solar developers told NREL that labor accounts for less than 20% of their 

installed solar field cost. The WorleyParsons analysis indicates a labor contribution of 

45% for an Arizona location and even higher for a California labor pool. As noted in 

the Impact of Labor section, some costs that WorleyParsons includes with labor do 

not scale with local labor rates. For the NREL reference plant, WorleyParsons’ all-in 

crew labor costs were reduced by 40% and the costs were distributed over the 

materials categories. For consistency this shift of labor overhead to material overhead 

was applied to all direct cost categories, i.e., site preparation, solar field, power block, 

etc. Note that this adjustment reduces the labor fraction of the direct cost categories 

but does not change the overall installed cost. The implicit assumption is developers 

and WorleyParsons differ in how they account for certain cost categories. 

• Discussion with solar field developers, including some who have recently built 

parabolic trough plants, indicated their estimated solar field costs were significantly 

less than that shown in the WorleyParsons reports. While different labor overhead 

rates could account for this discrepancy, those rates would impact all cost categories, 

not just the solar field and the other cost category estimates were comparable. NREL 

reduced the WorleyParsons site preparation and solar field costs by 25% to bring the 

final $/m2 number closer, although still slightly higher than, numbers reported by 

developers. Whether this adjustment represents the vertical integration of developers, 

conservative design on the part of WorleyParsons, newer collector technology, etc. is 

unclear. It likely is some combination of these factors. Nonetheless, NREL believes 

the values provided in the spreadsheet to be representative; however, as with any cost 

estimate users are cautioned to carefully examine solar field cost and distribution to 

determine if it is appropriate for your specific case. 

WorleyParsons did not provide detailed operation and maintenance (O&M) categories, but only 

a rollup of O&M costs, as shown in Appendix A and B. Thus, the labor categories on sheet 

O&M$ were generated by relying on information from NREL’s Excelergy spreadsheet model, 

which was based on data from the California SEGS plants. The total O&M costs were 

manipulated to closely match the WorleyParsons rollup costs for the plant size and location used 
10 

in the WorleyParsons analysis. Annual salary values used on the O&M$ sheet come from the 

U.S. Bureau of Labor under NAICS 221100, Electric Power Generation, Transmission and 

Distribution, May 2008. National mean values are shown in the spreadsheet. These values are 

adjusted within the spreadsheet to represent a workforce in different geographic regions [2]. 

As noted previously, WorleyParsons provided only the EPCM indirect costs and did not include 

an estimate of Owner’s costs. General indirect cost categories are listed in the spreadsheet with 

NREL estimated values. Owner’s costs include such items as permitting, land, legal fees, 

geotechnical and environmental surveys, taxes, interest during construction, and the owner’s 

engineering and project management activities. For simplicity SAM uses only three indirect cost 

categories: (1) Engineer, Procure, Construct; (2) Project, Land, Misc.; and (3) Sales Tax. In 

SAM’s default files, the combined indirect costs are approximately 25% of total 

direct+contingency costs. Because project costs can vary greatly and have a significant impact on 

total installed cost and LCOE, users are cautioned to review and revise these estimates, as 

appropriate.

The project plant provided in the spreadsheet (highlighted in orange) is intended to represent the 

user’s specific scenario. The spreadsheet calculates the project plant costs by comparing its size 

to that of the reference plant. As supplied, the project plant is adjusted to match NREL’s SAM 

default trough plant case. 

Users can link the cost model spreadsheet to SAM 2010 through the Excel Exchange linkage. 

SAM allows users to connect any input variable in SAM to a cell or range of cells in a Microsoft 

Excel workbook. This feature allows users to use external spreadsheet-based cost and 

performance models to generate values for SAM input variables. A list of the exchange variables 

used in the cost model template is provided in Table 5. User-defined input variables can also 

share values with external workbooks. For example, User Variable 2 returns an estimate of 

annual utility costs to SAM. UV-2 can be divided by the annual generation to check if SAM’s 

estimated Variable Cost by Generation is accurate. This extra step is required because Variable 

Cost by Generation requires SAM’s estimate of annual generation which cannot be passed

a priori to the spreadsheet.
11 

Table 5. Sent to/captured from variable list for SAM Excel Exchange.

SAM variables sent from SAM to 

Excel

Excel cell Comments

Design gross output h11 

Actual aperture h12 Total solar field aperture area

TES thermal capacity h13

User Variable 1 h15 Cost reference year

Inflation Rate h16

Row spacing h18 Used to estimate land area

Aperture width, total structure h19 Used to estimate land area

Sales Tax h20

User Variable 4 h21 Labor rate multiplier

SAM variables captured by SAM from Excel

Sales Tax Percentage of Direct Costs i37 Based on the fraction of direct costs made 

by materials

Site Improvement Cost per m2 i26

Solar Field Cost per m2 i27

HTF System Cost per m2 i28

Storage System Cost per kWht i29 

Fossil Backup Cost per kWe i30

Power Plant Cost per kWe i31

Contingency i32

Engineer,Procure,Construct i35

Project,Land,Management i36

Fixed Annual Cost i41

Fixed Cost by Capacity i42

User Variable 2 i43 Annual utility costs in $/yr

Fossil Fuel Cost i44

User Variable 3 i45 Estimated O&M labor force
12 

To access Excel data exchange in SAM, first click Configure Simulations to view the Configure 

Simulation page: 

Then click Excel Exchange to display the Excel data exchange options: 

More information on SAM with Excel Exchange can be found in the SAM help files. When 

retrieving data from Excel via the SAM Excel Exchange, the cells in Excel must not have $ or % 

formatting. Such formatting will cause an error message in SAM. Also, note that after the 

exchange process, the spreadsheet does not

References

retain the values read in from SAM; in contrast, the 

SAM case does retain the values captured from the spreadsheet.

1. SolarPACES project lists available at http://www.nrel.gov/csp/solarpaces/ 

2. National Compensation Survey, U.S. Department of Labor, April 2008, available at 

http://www.bls.gov/ncs/ncswage2008.htm and http://www.bls.gov/ncs/ocs/compub.htm 

3. Kelly, B., “Nexant Parabolic Trough Solar Power Plant Systems Analysis, Task 2: 

Comparison of Wet and Dry Rankine Cycle Heat Rejection,” Subcontract Report, 

NREL/SR-550-40163, July 2006. 

4. Blaney, H.F., “Monthly Consumptive Use of Water by Irrigated Crops and Natural 

Vegetation,” General Assembly of International Union of Geodsy and Geophysics, 

Toronto, Canada, 1957. 

5. Consumptive Use of Water by Major Crops in the Southwestern United States, United 

States Department of Agriculture, ARS Conservation Research Report 29, May 1982. 

6. Kelly, B., and D. Kearney, “Thermal Storage Commercial Plant Design Study for a 2-

Tank Indirect Molten Salt System,” Subcontract Report, NREL/SR-550-40166, July 

2006. 
13 

Appendices to NREL TP-550-47605, 

Parabolic Trough Reference Plant for Cost Modeling with the Solar Advisor Model; C. Turchi

Appendix A

CSP Parabolic Trough Plant Cost Assessment

WorleyParsons Group 

Report under NREL contract KAXL-9-99205-01

September 9, 2009 
NATIONAL RENEWABLE ENERGY LABORATORY
 

CSP Parabolic Trough Plant 

Cost Assessment 

59002501 – NREL-0-LS-019-0001 

9 September 2009 

WorleyParsons Group
 

Americas, Northwest Region
 

Denver Office
 

1687 Cole Blvd,
 

Suite 300,
 

Golden, CO, 80401, USA
 

Tel: +1 303 928 4226
 

Fax: +1 303 928 4230
 

14
NATIONAL RENEWABLE ENERGY LABORATORY 

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Disclaimer 

This report has been prepared for the National Renewable Energy Laboratory, and is 

subject to and issued in accordance with the agreement between National Renewable 

Energy Laboratory and WorleyParsons Services Pty Ltd. WorleyParsons Services Pty 

Ltd accepts no liability or responsibility whatsoever for it in respect of any use of or 

reliance upon this report by any third party. 

PROJECT 59002501 ­

REV DESCRIPTION ORIG REVIEW WORLEYPARSONS 

APPROVAL 

DATE CLIENT 

APPROVAL 

DATE 

A DRAFT Issue for Client 

Review D.Ross R.Bowers G.Aron 

07-24-09 N/A 

0 Final Issue DR 

D.Ross 

RB 

R.Bowers 

GA 

G.Aron 

4-Sep-09 N/A 

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TABLE OF CONTENTS 

1. SUMMARY............................................................................................................................4
 

2. PROJECT DESCRIPTION....................................................................................................5
 

2.1 Site Characteristics ..................................................................................................5
 

2.2 Mechanical System Descriptions .............................................................................9
 

2.3 Electrical System Descriptions...............................................................................31
 

2.4 Instrumentation and Control System Descriptions.................................................35
 

2.5 Civil Sitework Descriptions.....................................................................................39
 

2.6 Structural Support and Foundation Descriptions ...................................................43
 

3. COST ESTIMATE BASIS (SUBJECT TO REVISION) ......................................................46
 

3.1 Quantity Development ...........................................................................................46
 

3.2 Material and Equipment Pricing .............................................................................46
 

3.3 Construction Labor.................................................................................................47
 

3.4 Clarifications...........................................................................................................48
 

3.5 Exclusions ..............................................................................................................50
 

APPENDICES 

Appendix A – Capital Cost Estimate Summary 

Appendix B – O&M Cost Estimate Summary 

TOC 

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LIST OF ACRONYMES 

ASHRAE – American Society of Heating, Refrigeration, and Air-conditioning Engineers 

ASME – American Society of Mechanical Engineers 

BOP – balance of plant 

COC – cycles of concentration 

CSP – concentrating solar power 

DCS – distributed control system 

DNI – direct normal insolation 

EPC – engineer-procure-construct 

EPCM – engineer-procure-construction manage 

HCE – heat collection element 

HTF – heat transfer fluid 

kV - kilovolt 

kVA – kilovolt amps 

kW – kilowatt 

MVA – megavolt amps 

MWe – megawatt electric 

MWth – megawatt thermal 

MCC – motor control center 

MTO – material take off 

NFPA – National Fire Protection Association 

NPSHA – net positive suction head available 

NREL – National Renewable Energy Laboratory 

NSRDB – National Solar Radiation Data Base 

P&ID – process and instrumentation diagram 

PLC – programmed logic controller 

PDC – power distribution center 

SAM – Solar Advisor Model 

SCA – Solar Collector Assembly 

SCADA - supervisory control and data acquisition 

SFC – solar field control 

SJAE – steam jet air ejector 

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SSG – solar steam generator 

STG – steam turbine generator 

SUNY – State University of New York 

TES – thermal energy storage 

TMY – typical meteorological year 

VFD – variable frequency drive 

VSD – variable speed drive 

WMO – World Meteorological Organization 

LIST OF TABLES AND FIGURES 

Figure 1 – DNI profile plot 

Figure 2 – Power block general arrangement sketch 

Figure 3 – SCA component diagram 

Figure 4 – Loop layout sketch 

Figure 5 – Solar field general arrangement sketch 

Figure 6 – Empirical sun tracker picture 

Figure 7 – Heat collection element picture 

Figure 8 – Parabolic mirror picture 

Figure 9 – Process flow diagram 

Figure 10 – Water balance, peak summer 

Figure 11 – Water balance, average annual 

Figure 12 – Water balance, average winter 

Figure 13 – Thermal storage system sketch 

Figure 14 – Mirror wash truck picture 

Figure 15 – Electrical one-line diagram, sheet 1 

Figure 16 – Electrical one-line diagram, sheet 2 

Figure 17 – Asphalt road section detail 

Figure 18 – Perimeter road section detail 

Figure 19 – Gravel road section detail 

Figure 20 – Evaporation pond section detail 

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Figure 21 – Salt storage berm section detail 

Figure 22 – Salt storage maintenance access drive ramp section detail 

Figure 23 – Solar collector foundation pylon, normal 

Figure 24 – Solar collector foundation pylon, drive 

Table 1- Direct normal insolation 12x24 data set, TMY3 

Table 2- Direct normal insolation 12x24 data set, TMY2 

Table 3- Direct normal insolation 12x24 data set, SUNY 

Table 4 – Major mechanical equipment list 

Table 5 – Heat balance output summary 

Table 6 – Major electrical equipment list 

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1. SUMMARY 

The purpose of this cost study is to provide the solar power industry with approximate capital and 

reoccurring costs for a concentrating solar power (CSP) plant using parabolic trough technology. The 

National Renewable Energy Laboratory (NREL) intends to update the cost output portion of their 

Solar Advisor Model (SAM) using the results of this study. All costs found by this study are based on a 

conceptual engineering effort prepared at a high-level, consistent with the intended purpose and 

confidence of a Level 2 (+/-30%) cost estimate. The base plant design will generate 103MWe net 

(118MWe gross) power to the grid at 230kV using wet cooling and having 6.3 hours of molten salt 

thermal energy storage. The reference plant requires approximately 1018 acres (4,095,435 m2

) of 

desert land in Daggett California. Site geographic location resource information is limited to solar 

radiation, ambient conditions, and labor rate profiles. No further site specific information is known, any 

information necessary for cost estimating (i.e. utility interconnections, water source, infrastructure etc.) 

is assumed and stated later in the report. 

The goal is to capture costs for a “typical” parabolic trough stand-alone plant designed and built in the 

United States. The Solar Advisor Model calculations will scale, escalate, and adjust the costs of this 

reference plant given user inputs, and cost indices to arrive at an approximate cost for the userdefined plant design. This study should be viewed as a high-level assessment with the understanding 

that site specific information along with more research, optimization, detailed engineering and capital 

cost estimating is required in order to arrive at an optimal CSP parabolic trough plant design that 

meets the Owner’s needs. Owner’s costs (i.e. land, permitting, Owner’s engineer, risk, loan interest 

etc.) are excluded from this estimate and will be defined as a user input in SAM. 

Total installed capital cost for the 103MWe net reference plant with 6.3 hours of thermal storage in 

Daggett is $1.016 Billion ($9,861/kW net) with a +/-30% confidence. Operation and maintenance cost 

is $14.8 MM (1.33% of total installed cost). The plant is designed with an expected life of 30 years 

with daily startup and shutdown cycling. 

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2. PROJECT DESCRIPTION 

All included subsections provide a brief description of the major cost elements contributing to the total 

installed cost of the reference plant. Description of the cost estimating process is discussed in a 

separate section. 

2.1 Site Characteristics 

NREL has selected Daggett California for the reference plant location, as it has been NREL’s historic 

representative location for CSP power plant case studies. No site boundary, resource information, or 

coordinates were provided. The assumed site acts only as a reference site with the purpose of 

providing adequate weather, solar, and labor information to estimate the cost of the CSP trough plant. 

All items affecting cost are identified throughout this report. 

2.1.1 Ambient Conditions 

Local weather information is used for Rankine cycle performance modeling, heat loss calculations, 

and equipment specifications. Two sources of weather data were used—American Society of Heating, 

Refrigeration, and Air-Conditioning Engineers (ASHRAE) and Typical Meteorological Year 3 (TMY3) 

data from Barstow-Daggett Airport station in Daggett California. Heat and mass balance modeling 

requires ambient conditions such as dry bulb and wet bulb temperatures and atmospheric pressure. 

Site elevation for Daggett is 1929 feet (589 meters) above sea level which corresponds to an 

atmospheric pressure of 13.70 psia (0.945 bar) (ASHRAE Handbook – Fundamentals (IP)). Three 

ambient temperature cases were established to capture the range of site conditions over a typical 

operating year. All equipment is designed based on the peak summer design case; 108.0°F (42.2°C) 

dry bulb (ASHRAE 2% monthly frequency) and 71.3°F (21.8°C) wet bulb (average of Jun/Jul/Aug 2% 

monthly frequency). The other two off-design cases are average annual and average winter. Average 

annual temperatures (81.5°F DB [27.5°C] and 58.1°F [14.5°C] WB) are weighted against the hourly 

thermal input to the power block for a typical year in order to “best” represent the average operating 

profile of the plant. For example, midnight temperatures are given zero weight since the plant is 

offline, whereas noon temperatures are given partial-to-full weight since the plant is at part or full load, 

respectively. Similarly, average winter temperatures (58.9°F [14.9°C] DB and 44.4°F [6.9°C] WB) are 

derived by the same method as average annual except only December, January, and February 

months are included. 

Offline dry bulb temperatures average approximately 60°F (15.6°C). The relatively high dry bulb 

temperatures in desert locations, which rarely drop below freezing (<1%/year), will help to reduce heat 

loss and hours of freeze protection/circulation operation and therefore increase the amount of solar 

thermal energy used for generating electricity and/or reduce the amount of overall gas and parasitic 

power consumption. 

Maximum daily wind speed averages range from 2.9 m/s in December to 6.7 m/s in May (TMY3), 

while the maximum occurring wind speed in a typical year is 17.5 m/s. Equipment manufacturers 

typically require their troughs to be stowed at wind speeds exceeding ~15.6 m/s (35 mph). Based on 

hourly TMY3 data, this will occur for 10 total hours in a typical year with 8 hours during operation. 

These infrequent high-wind occurrences support the assumption of not including a wind fence around 

the solar collector field. However, an in-depth wind study should be done during the project’s 

procurement stage to properly determine the need for wind screening. In addition, wind rose parallel 

to the trough axis can have a significant effect on receiver heat loss, as opposed to the transverse 

direction, depending on wind speed and fractional annual duration. Wind rose direction is also critical 

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in cooling tower orientation. Nevertheless, for purposes of this cost study no wind rose analysis was 

performed. 

2.1.2 Solar Radiation Resource Selection 

The intensity of available solar radiation, or “fuel”, for a concentrating solar power project is among the 

primary factors driving the power generation capabilities. CSP requires direct normal insolation (DNI) 

or direct normal irradiation—the component of sunlight that emanates directly from the sun. This direct 

insolation excludes diffuse and horizontal radiation which is used by photovoltaic solar power. Multiple 

solar resource data sets were considered and evaluated for modeling solar energy output at the 

Daggett reference site. 

TMY3, TMY2, and State University of New York (SUNY) are among the available data sets for this 

site. The TMY3 and TMY2 data sets use combined ground measured and satellite-derived data 

collected from 1991-2005 and 1961-1990, respectively. SUNY data uses a combination of satellitederived data with geographical information system (GIS) data collected from 1998-2005. All data sets 

use similar algorithms that produce one full year of hourly data to represent a “typical” year among the 

collected pool. TMY compiles a typical year of solar data using a complete month’s dataset closest to 

the average for the respective month; whereas SUNY uses a complete year’s dataset having monthly 

datasets closest to the average for the respective month. Average hourly DNI per month for each 

data set is illustrated in Tables 1 to 3 below. 

Table 1. TMY3 (1991-2005) direct normal insolation (watt-hr/meter2/year) hourly averages per month at Barstow 

Daggett Airport in Daggett, CA (NSRDB Class I, WMO station 723815). 

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Table 2. TMY2 (1961-1990) direct normal insolation (watt-hr/meter2/year) hourly averages per month at Barstow 

Daggett Airport in Daggett, CA (NSRDB Class A, WMO station 723815). 

Table 3. SUNY (1998-2005) direct normal insolation (watt-hr/meter2/year) hourly averages per month for 10km 

grid over undisturbed area in Daggett, CA (radwx_116653495_9805.tm2). 

TMY3 data was selected as the representative dataset for the Daggett site. Although SUNY records 

data within a 10km grid over the site, it will not be used primarily due to the uncertainty of the TMY3 

data being categorized as Class 1, which is the lowest uncertainty among all solar radiation data 

sources. National Solar Radiation Data Base (NSRDB) Class I data sets have a complete period of 

record for all parameters from 1991 to 2005 with an uncertainty of ±10-15%. SUNY data has 

estimated uncertainties that range up to ± 20% (NREL Solar Resources Workshop “NSRDB 10 km 

Gridded Hourly Solar Database” Oct. 2008 presentation). Furthermore, TMY3 gathers data from a 

larger pool than SUNY (14 years vs. 7 years) and therefore may be more representative of the site’s 

radiation profile for a typical year. The considered TMY2 data for Daggett (same WMO station as 

TMY3 for Barstow-Daggett Airport) is highly ranked Class A data (having a minimum of 15 candidate 

months without more than 2 consecutive hours of missing data). Nevertheless, TMY2 data was 

collected nearly 20 years ago and could possibly misrepresent the recent climate changes, thus 

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adding to the uncertainty of the data. 

Annual DNI averages shown in the figures above illustrate the close similarity between the three 

available datasets; TMY3 rests between the two other data sources. In summary, TMY3 data for the 

Daggett site has a few slight advantages over the other considered solar resources. Specifically, 

TMY3 data has the least error uncertainty, has the most recent and largest combined data pool, and 

is within < 3% of SUNY and TMY2 data. 

Design point direct normal insolation for solar field sizing was selected at 1,000 watts/m2 (at zero 

incident angle), typical of most Southwestern United States CSP sites and further supported by 

Chapter 6 in “Recent Advances in Parabolic Trough Solar Power Plant Technology” (Kearney & 

Associates and NREL,). For annual generation the occurrence of design point DNI is an important 

factor. Although this study does not estimate annual performance, it’s important to note that Daggett 

SUNY data shows 3 hours of 1000 watts/m2 or greater over the 8760 hours in a year; whereas TMY3 

has 37 hours. 

Without storage, the plant is designed to have a solar multiple of 1.25 (i.e. 25% larger than needed for 

full plant output at 1000 watts/m2). The purpose of this solar multiple is to provide more mirror area to 

account for radiation losses when the sun is at lower latitude and when radiation is less than design 

(mornings & afternoons). 

Figure 1 below compares peak day, peak month average, and minimum month average DNI by hour 

for the Daggett site. Sun angle and shortened days are the main contributors to the low winter DNI. 

Hence a solar multiple (defined later) is applied to the solar field size to account for the lower radiation 

seen in shoulder and winter months as well as the off-design DNI in the early and later hours of the 

day. Keep in mind these trends are not directly related to plant output; mainly due to the impact of 

thermal storage and increased steam cycle efficiencies where lower ambient temperatures are 

coincident with high DNI. 

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Figure 1. Peak day, average peak month, and average minimum month DNI profiles using TMY3 data for 

Daggett California. 

2.2 Mechanical System Descriptions 

The stand-alone parabolic trough plant with thermal storage is made up of several interconnecting 

systems all working together to provide electricity to the power grid. The following systems make up 

the thermal cycle for the reference plant: 

o Solar thermal collection field 

o Heat transfer fluid system 

o Rankine cycle 

o Thermal energy storage 

o Balance of plant 

A brief description of each primary system and its sub-systems will be discussed throughout this 

section. Below is a list of the major mechanical equipment which makes up the reference plant 

design. Bulk mechanical materials such as valves, piping, fasteners etc. are not listed at this design 

level, but are included in the cost estimate. Further supporting sketches, flow diagrams, lists, tables, 

and figures are provided to better illustrate the design basis of the cost estimate. Other significant cost 

items in a CSP plant include civil, structural, electrical, and controls. These are discussed later in the 

report. 

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Table 4. Major mechanical equipment list for Daggett reference plant. 

EQUIPMENT NAME QTY 

SOLAR COLLECTOR ASSEMBLIES 

Solar Collector Mirrors 405,888 

Solar Collector Receiver Tubes (Heat Collection Elements) 43,488 

Solar Collector Assemblies/Drives 1208 

THERMAL ENERGY STORAGE (by EPC Vendor) 

Cold Salt Tanks (incl. foundations) 2 

Cold Tank Immersion Heater 4 

Hot Salt Tanks (incl. foundations) 2 

Hot Tank Immersion Heater 4 

Hot Salt Pumps 3 x 50% / tank 

Cold Salt Pumps 3 x 50% / tank 

Salt to HTF Heat Exchangers 6 

Bulk Salt Storage 62 kMT 

Nitrogen Storage and Vaporization System Lot 

STEAM TURBINE & AUXILIARIES 

Steam Turbine 1 

Generator (w/ steam turbine supply) 1 

Gland Steam Condenser (w/ steam turbine supply) 1 

Lube Oil and Hydraulic Oil Skids (w/ steam turbine supply) 1 

Cooling Tower 1 

Steam Surface Condenser 1 

Steam Jet Air Ejector (SJAE) (Holding and Hogging ejectors) 1 

Deaerator/Storage Tank (open feedwater heater #4) 1 

Closed Feedwater Heaters (3 LP and 1 HP) 4 

HEAT EXCHANGERS 

Economizer (preheater) 1x100% 

EQUIPMENT NAME QTY 

Evaporator (steam generator) 2x50% 

Reheater 2x50% 

Superheater 1x100% 

Closed Cooling Water Heat Exchangers 2x100% 

HTF Freeze Protection Condenser 1 

PUMPS 

HTF Main Circulation 4x33% 

HTF Freeze Protection Circulation 1x100% 

HTF Overflow Tank Transfer (to Exp Tank) 2x100% 

Feedwater 2x100% 

Feedwater Drip Pump 2x100% 

Circulating Water 2x100% 

Aux Cooling Water (backup/startup) 1x100% 

Closed Cooling Water 2x100% 

Boiler Blowdown Sump (from sump to cooling tower basin) 2x100% 

Cooling Tower Blowdown Booster (circ water header to evap ponds) 2x100% 

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Condensate Forwarding 2x100% 

Demineralized Water Forwarding (cycle makeup) 2x100% 

Demineralized Water Startup/Cycle Makeup Pump 1x100% 

Demineralizer Feed Pumps 2x100% 

Potable Water 2x100% 

Oil-Water Separator Effluent Forwarding 2x100% 

Well Water Forwarding 3x50% 

Service Water (from Raw/Fire water Tank) 2x100% 

Firewater Pump (Electric Driven, see emission-generating equipment below) 1x100% 

Firewater Jockey (Pressure Maintenance) 1x100% 

TANKS 

Demineralized Water Storage (Field Erected) 2x100% 

Raw/Fire/CT Makeup Water Storage (Field Erected) 1x100% 

Potable Water Storage (Shop Fab) 1x100% 

Blowdown/Flash Tank (Shop Fab) 1x100% 

Turbine Area Flash Tank (Shop Fab) 1x100% 

Closed Cooling Water Expansion Tank (Shop Fab) 1x100% 

HTF Expansion & Overflow Tanks (Shop Fab) 

1 Expansion 

6 Overflow 

HTF ULLAGE SYSTEM 

Ullage Vessel Return Pump 1x100% 

Ullage Recirculating Pump 1x100% 

Ullage Recirculating Air-Cooler 1 

Ullage Air-Cooled Condenser 1 

Ullage Drain Vessel Intercooler 1 

Ullage Vessel 1 

Ullage Waste Storage Tank (Hot) 1 

Ullage Waste Storage Tank (Cold) 1 

Ullage Flash Tank 1 

Ullage Drain Vessel 1 

EMISSION GENERATING EQUIPMENT 

Gas-Fired Auxiliary Packaged Boiler (turbine seals/warm-up, SJAE) 1 

Emergency Diesel Generator 1 

Diesel-Driven Firewater Pump 1x100% 

OTHER EQUIPMENT 

Oil-Free Air Compressor, Dryer, Receiver Tank 2x100% 

Bulk Nitrogen Storage & Vaporizer 1 

Diesel Fuel Tank & Pump System (On-site Mirror Wash Trucks) 1 

Mirror Wash Truck Demineralized Water Fill Station 1 

Oil/Water Separator (not for HTF/water separation) 1 

Sample Panel 1 

Cycle Chemical Feed Lot 

Cooling Tower Chemical Feed/Storage System Lot 

Demineralized Water Treatment System Lot 

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Figure 2 below represents a conceptual layout of the major equipment within the power block for the 

reference plant. Equipment sizes are based on vendor information, past project archives, or 

engineering judgment/estimates. Equipment arrangement aims to provide a functional layout which 

meets plant operation and maintenance needs. 

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Figure 2. Reference plant conceptual power block general arrangement layout. 

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2.2.1 Solar Thermal Collection Field 

Figure 3. Solar collector assembly 

diagram showing direct radiation path. 

As illustrated in figure 5 below, the solar 

field area will also encompass permanent 

HTF piping, power and instrument cable, 

asphalt access roads and perimeter gravel 

roads, security fencing, storm water 

detention pond, waste water evaporation 

ponds, land farm / bioremediation area, 

switchyard, water and natural gas supply 

lines and the utility’s transmission lines. 

Solar field temporary facilities include a 

fabric tent solar collector assembly facility, 

and a construction lay down area with 

trailers and parking for solar field and power 

block construction. 

The Daggett reference plant consists of 

1208 solar collector assemblies (SCA), each 

150 meters long having 817.5 m2 of 

effective aperture mirror area. Combined, 

the solar field has 987,540 m2 of effective 

aperture mirror area which can provide 

~250MWth to the thermal storage system 

and ~407MWth to the power block. Four (4) 

SCAs make up a single circuit of “cold” 

(~560°F / 293.3°C) to “hot” (~740°F / 

393.3°C) HTF where two SCAs are aligned 

end-to-end in a common row and connect to 

another row of two SCAs making the loop 

(Figure 4). 

Parabolic trough technology concentrates DNI, using 

single-axis sun tracking, onto a heat collection element 

(HCE) located at the focal line of the parabolic surface 

(Figure 3). A high temperature heat transfer fluid (HTF) 

such as synthetic oil with a relatively low freezing point, low 

vapor pressure, and the capability to retain heat absorbs 

the thermal energy in the HCE as it flows through the 

receiver tubes. Heat collected in the HCE is transported to 

the solar power block where a series of shell-and-tube heat 

exchangers, collectively the solar steam generator (SSG) 

boils and superheats incoming feedwater. 

Figure 4. Typical 4x SCA loop layout. 

“Cold” HTF is pumped through the “cold” header pipes from the power block to the first SCA in each 

loop. “Hot” HTF is returned to the “hot” header pipes and transferred back to the power block SSG. 

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Figure 5. Reference plant conceptual solar field general arrangement layout. 

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SOLAR COLLECTOR ASSEMBY 

An SCA is primarily composed of parabolic mirror facets with backing plates, heat collection elements 

with supports, a hydraulic actuator drive, and a sun tracking sensor; all supported by a metal support 

structure. The interconnecting piping system (except ball joints) and collector foundations are typically 

not considered part of the SCA manufacturer’s supply; but are engineered and constructed by the 

general contractor. 

The collector field is made up of multiple rows of SCAs, which are the basic, modular building blocks 

of the solar energy collection system. The solar collectors will rotate slowly east to west during each 

day to track the sun’s movement and to keep the sun’s rays focused on the absorber tube. This 

reference plant uses hydraulic actuators which are driven by a ~1 hp (0.746 kW) electric pump motor. 

These two-speed drives intermittently track the sun (low speed) and continuously stow the SCAs 

(high speed) during the appropriate operation mode. 

Each SCA will track the sun via a logic controller located in 

the collector drive housing. The logic is preprogrammed 

using a GPS system to orient the SCA at the calculated sun 

position. Additionally included in this reference plant design 

is an empirical sun tracker that directly watches the sun’s 

path by measuring a voltage differential created by a 

shadow casted on a flat plate photovoltaic cell which sits 

centrally behind the HCE just in front of the mirror (Figure 6). 

This empirically based tracker will typically orient the SCA 

during operation while the logic tracker will be used for 

deploy and stow positioning, or when clouds obscure the 

sensor. 

HEAT COLLECTION ELEMENT 

The heat collection element absorbs heat into the HTF. This 

element consists of a coated stainless steel tube surrounded 

by a glass tube insulator holding a vacuum between the pipe 

and the glass, also known as evacuated glass (Figure 7). The 

coating on the steel tube decreases reflectivity and increases 

its heat absorption capabilities. The outer glass cylinder has 

anti-reflective coating on the inner and outer surfaces to 

reduce reflective losses, increasing the transmission of solar 

energy. Metallic substances called “getters” are installed in the 

annular space to absorb hydrogen and other vacuum depleting 

gases. 

MIRRORS 

The parabolic mirrors that reflect solar energy to the HCE use 

in this study will be low-iron laminated or monolithic glass 

mirrors. These mirrors are known to be reliable components 

that show no long-term degradation in reflective quality. 

Reflectivity of the mirrors is closely monitored to determine the 

frequency and method of mirror washing. Regular mirror 

washing has been proven to maintain mirror reflectivity at 

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Figure 6. Empirical sun tracker. 

Figure 7. Heat collection element 

Figure 8. Parabolic mirror facets. 

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installed conditions. More recent alternative mirror technology intended to drive down cost is also 

available. 

2.2.2 Heat Transfer Fluid System 

Heat transfer fluid is the link between the sun’s radiation energy and the steam energy utilized in the 

power block. In a parabolic trough plant, HTF travels through a series of processes such as pumping, 

expanding, heating, cooling, and purifying. Circulation, expansion, ullage, and freeze protection are 

the primary HTF sub-systems. 

The HTF selected for the reference plant is a high-temperature synthetic oil that has a proven 

operating history and is used in operating CSP trough plants and other heat transfer processes. It has 

a maximum operating temperature of 750°F (399°C) and a freezing temperature of 54°F (12.2°C). 

These properties are critical factors in the design of the HTF system. Because the HTF maximum 

temperature is the primary factor limiting the steam cycle efficiency, proper HTF selection is important 

in actual plant design. 

Although having HTF that could reach temperatures above 950°F would be beneficial to the plant’s 

performance, its use would significantly increase the capital cost by requiring special alloy piping in 

the solar field. In addition, the relatively high freezing temperature of this HTF will require a freeze 

protection system which consumes a significant amount of electricity or fossil energy to keep the fluid 

in a liquid state during the evening. More details on the handling of HTF are discussed throughout this 

section. 

HTF CIRCULATION 

The solar collector system involves an extensive piping network which circulates HTF in a closed loop 

to and from the power block and solar field. This system is designed to maintain an equally distributed 

flow through all the SCAs so as to avoid low and high temperature areas. Variable speed pumps, 

quadrant control valves, loop balancing valves, and temperature sensors are used to control the “hot” 

HTF to a constant temperature. 

Expansion loops will be located as required to maintain pipe stresses within the limits allowed by 

ASME B31.1 - Power Piping Code and to meet component manufacturer load limitations. Main supply 

and return header pipe running to/from the solar field sections and to/from the pumps range from 42­

inch to 24-inch nominal diameter. Solar field header pipe beginning at each section of loops (6 

sections depicted in the solar field layout sketch above) which supply/return HTF to/from each loop 

range from 24-inch to 4-inch nominal diameter. All solar field HTF piping is insulated carbon steel and 

supported by pier-mounted pipe supports. Each loop of SCAs will be interconnected with 2.5-inch 

standard wall insulated carbon steel. Single and double ball joints will allow for independent SCA 

rotation while maintaining a fixed interconnecting pipe position. 

Four (4) -33% centrifugal type circulation pumps, each requiring 4000 hp motors, will circulate the 

HTF in the closed loop system. They are the highest single parasitic load in the plant and will be 

driven by variable speed drives (VSD) in order to reduce their power requirements when the system 

flow is less than 100%. In addition, a dedicated freeze protection circulation pump with a 200 hp fixed 

speed motor will circulate HTF through the freeze protection heat exchanger. Both circulating pumps 

and the freeze protection pump are located on a common foundation and spill containment area 

underneath the pipe rack with a reserved motor/pump pull space for maintenance. 

HTF EXPANSION & NITROGEN BLANKETING 

As the HTF is heated from its lowest allowable overnight temperature of 100°F (37.8°C) to its 

operating temperature of up to 740°F (393.3°C), the resulting large change in fluid volume requires 

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one 75,000 gallon (284 m3) expansion tank and six 75,000 gallon overflow tanks (same design as 

expansion tank) to accommodate this additional volume. During HTF warm-up the expansion tank 

reaches its max capacity and sends HTF to the first overflow tank and continues until all tanks are 

nearly full at full-load operation. As the HTF temperature decreases during shutdown, and the HTF 

contracts, an overflow tank transfer pump intermittently transfers HTF from the overflow tanks to the 

expansion tank until cold HTF temperature is reached and only the expansion tank is partially full. 

These pumps are located in a common containment area with the tanks. 

Due to the heat reserve in the thermal storage system, the expansion system can be located on the 

cold side of the HTF cycle, which results in a cost saving with a reduction in wall thickness and a 

slight reduction in expansion/overflow tank capacity. During extended cloud transients, the thermal 

storage system will provide a buffer to maintain the plant at its “pre-cloud” load. During short-term 

cloud transients, the HTF system mass (HTF plus steel) will provide a buffer. Plants without storage 

may opt to locate the expansion system on the hot side to act as a more significant cloud buffer. 

The expansion tank is also blanketed with nitrogen which serves to partially control the closed loop 

system pressure (similar to a bladder tank) and suppress HTF vapor formation by assuring the lowest 

pressure in the system remains above the HTF vapor pressure. The correct initial nitrogen blanketing 

pressure at the cold HTF condition, a function of expansion tank excess capacity, will assure that the 

tank pressure will be above the HTF vapor pressure when the nitrogen is compressed and heated by 

the HTF expansion. The nitrogen also guards against oxidation and contamination from air contact 

and eliminates a potentially explosive mixture. Oxidation will lead to a decrease in HTF heat transfer 

abilities and overall useable life of the fluid. 

A bulk liquid nitrogen storage and vaporization system will be located adjacent to the expansion tank. 

Nitrogen will continuously be bled and replenished from the system due to the ullage system 

operation (further explained below). 

HTF ULLAGE SYSTEM 

The ullage system consists of heaters, coolers, flash tanks, storage tanks, pumps, drains, vents, and 

interconnecting piping and instrumentation. During operation the HTF breaks down into components 

having high and low boiling points as it is exposed to oxygen and/or overheated. The components 

with a low boiling point (low boilers) will be removed as vapors, along with other non-condensables 

and moisture (steam), out the top of the expansion tank and processed in the ullage system which 

releases this vaporous waste to atmosphere while recovering any high-quality liquid HTF. The 

components with high boiling points (high boilers) will be removed as liquid and sediment through the 

HTF flash system. The “good” HTF flashed vapor will be recovered and returned to the system, the 

remaining high boiler liquid waste and sediment will either be trucked off site or treated in the 

bioremediation area. 

HTF FREEZE PROTECTION 

The selected HTF freezes at 54°F (12.2°C), which is well above the Daggett area winter and/or nighttime temperatures. Once the SCAs stop transferring heat to the HTF and the HTF temperature drops 

significantly the freeze protection circulating pump circulates the HTF at approximately 10% of normal 

flow rate. Once a majority of the heat dissipates to atmosphere the HTF will be directed through a 

steam-to-HTF shell and tube condensing heat exchanger in order to keep it at approximately 100°F 

(37.8°C). The steam source will be from the auxiliary boiler providing superheated steam which will be 

desuperheated with condensate spray before entering the heat exchanger. Alternatively the thermal 

storage system can be used to keep the HTF at the minimum temperature. Heat tracing will also be 

employed to protect small HTF piping, valves and instruments and/or where HTF may be stagnant. 

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2.2.3 Power Cycle 

Typical CSP parabolic trough plants have a reheat Rankine power cycle driven by oil-to-water heat 

transfer. As described above, hot HTF flows from the solar field through a series of heat exchangers 

in the power block, which ultimately provides superheated high pressure steam to drive the 118MWe 

steam turbine generator. 

Condensate is pumped through a series of low pressure closed feedwater heaters and into an open 

deaerating type feedwater heater used to remove oxygen from the system. This saturated and 

deaerated water is then sent to the deaerator storage tank, which serves as the suction for the 

feedwater pumps. The feedwater pump discharge is sent through a high pressure closed feedwater 

heater and into the economizer, evaporator and superheater. The steam from the steam generator 

train is admitted at ~700°F (371°C) and ~1325 psia (91.4 bar) to the high pressure (HP) turbine. HP 

turbine exhaust is reheated in the oil-to-steam reheater where lower pressure 700°F steam is 

admitted to the low pressure (LP) turbine. LP turbine exhaust is then condensed in a wet surface 

condenser, using cool circulating water from a mechanical draft cooling tower, where the condensate 

is collected in the hotwell, from which the condensate pumps take suction. 

Figure 9 below illustrates this process in more detail and includes high-level thermal storage and 

water treatment processes. This process flow diagram shows the relationship between all thermal 

process systems including HTF, water, steam, molten salt, and natural gas. 

The electric generation side of the power cycle involves a generator, transformers, circuit breakers, 

switches, and supporting transmission equipment. These systems are discussed later in the report 

along with civil, structural, and instrumentation/control systems. 

HEAT BALANCE 

Given NREL’s basic plant design criteria and WorleyParsons’ assumptions, the reference plant’s 

power cycle model was established. Conceptual Rankine cycle heat balances were modeled using 

General Electric’s GateCycle© software at three cases. The design case sets all equipment sizes 

based on peak ambient weather data as previously described. In addition, two off-design cases are 

modeled for winter and annual average ambient conditions. 

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Table 5. Heat balance output summary for reference plant. Not all model outputs are shown. 

Description Design 

Case 

Winter 

Average 

Annual 

Average 

Ambient Conditions DB Temperature (°F / °C) 108.0 / 

42.2 58.9 / 14.9 81.5 / 27.5 

Relative Humidity (%) 17% 29% 23% 

System Performance Gross Power Output (kW) 117,994 119,166 118,906 

HTF from Solar Field Flow (lb/hr) 10,253,326 10,254,841 10,254,837 

Temp (°F / °C) 740 / 393.3 740 / 393.3 740 / 393.3 

HP Steam to STG 

Flow (lb/hr / kg/min) 

1,053,158 / 

7,961 

1,053,185 / 

7,962 

1,053,185 / 

7,962 

Temp (°F / °C) 700 / 371 700 / 371 700 / 371 

Press (psia / bar) 1325 / 91.4 1325 / 91.4 1325 / 91.4 

Enthalpy (BTU/lb) 1301 1301 1301 

HRH Steam to STG 

Flow (lb/hr / kg/min) 

910,716 / 

6,885 

910,715 / 

6,885 

910,715 / 

6,885 

Temp (°F / °C) 700 / 371 700 / 371 700 / 371 

Press (psia / bar) 362 / 25 362 / 25 362 / 25 

Enthalpy (BTU/lb) 1365 1365 1365 

From Condenser 

Hotwell 

Flow (lb/hr / kg/min) 

732,054 / 

5,534 

721,732 / 

5,456 

726,588 / 

5,943 

Temp (°F / °C) 109 / 42.8 95 / 35 101 / 38.3 

Press (psia / bar) 

1.25 / 

0.0861 0.81 / 0.0558 

0.99 / 

0.0683 

Enthalpy (BTU/lb) 77.1 62.6 69.5 

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Figure 9. Reference plant process flow diagram of main thermodynamic systems. 

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WATER BALANCE 

Water balance calculation results for the three heat balance cases are shown in Figures 10 to 12 below. 

The water balance is representative of simultaneous operating consumers at full turbine output for a 

given ambient condition. Intermittent and emergency users (firewater, hose streams, safety showers etc.) 

are not running during normal operation and are therefore excluded from the water balance. Mirror wash 

water consumption is shown coincident to Rankine cycle operation for clarity, although it will not be 

performed so. 

The primary water consumer is cooling tower makeup which is over 90% of the plant’s instantaneous 

water consumption. Annually, cooling tower makeup equals about 93% of the plant’s total annual water 

consumption. Mirror washing is the next largest consumer at nearly 4%. The remaining water 

consumption is attributed to cycle makeup, blowdown quench, domestic (service water), and waste 

streams from the demineralized water treatment system. 

Major assumptions are listed in each water balance case; primarily the cooling tower cycles of 

concentration (COC) which is the most influential input. Without having site specific water quality data, a 

representative five cycles of concentration (COC) was assumed. The overall water consumption is largely 

dependent on COC. Although poor raw water quality can be pretreated to save water, capital cost for 

pretreatment systems can become very expensive depending on the raw water constituents. No 

pretreatment system is included in the cost estimate for the reference plant. 

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Figure 10. Design case water balance at 108°F (42.2°C) DB and 71.3°F (21.8°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes. 

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Figure 11. Annual average case water balance at 81.5°F (27.5°C) DB and 58.1°F (14.5°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes. 

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Figure 12. Winter average case water balance at 58.9°F (14.9°C) DB and 44.4°F (6.9°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes. 

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FEEDWATER 

The reference plant feedwater pumps take suction off the deaerator storage tank and discharges 

the feedwater through one high pressure heater and into the economizer. Two full capacity 

centrifugal-type ring section multistage feedwater pumps with 3000 hp motors with VSD hydraulic 

couplings are the primary pressure source in the steam cycle. These pumps sit at grade below 

the elevated deaerator storage tank. 

SOLAR STEAM GENERATOR 

The solar steam generator (SSG) transfers solar energy from the HTF to feedwater, generating 

steam used in a traditional reheat Rankine cycle for electricity generation. The steam generator 

system uses traditional shell and tube heat exchangers. The hot oil from the solar collector field 

passes through one 1x100% economizer, 2x50% evaporators, 1x100% superheater and 2x50% 

reheaters. The economizer acts as a preheater to raise the incoming high pressure feedwater 

close to saturation temperature. In the evaporator, saturated high pressure feedwater is boiled, 

sent through a separator (internal to kettle boiler) and on to the superheater to produce ~700°F 

(371°C) superheated steam for HP turbine admission. HP turbine exhaust, or cold reheat, is sent 

to the reheater, raised to ~700°F (371°C) and admitted to LP turbine. 

STEAM TURBINE ISLAND 

One 118MWe rated steam turbine with reheat is selected for the Daggett reference plant. The 

reference turbine has a single flow LP section with last stage blades designed for wet surface 

condensing. The generator is located between the HP and LP sections where the LP rotor 

directly couples with the generator and the HP turbine rotor mates with a speed reducing gear 

box for generator connection. All turbine auxiliaries provided by the steam turbine generator 

(STG) equipment manufacturer include: turbine modules, gearbox, stop/control valves, electrical 

generator, lube oil skid, control oil skid, seal/gland steam condenser skid, stand alone control 

system and an outdoor noise enclosure. All auxiliaries work together to maintain maximum 

turbine performance. 

CONDENSATE 

LP steam turbine exhaust is condensed in a wet cooled surface condenser and pumped by a 350 

hp vertical centrifugal can pump from the condenser hotwell, through three(3) closed LP 

feedwater heaters and into the deaerator. Additionally condensate is used as desuperheating 

spray for the LP turbine bypass system and aux boiler steam admission to the HTF freeze 

protection condenser. The deaerator and associated storage tank are supported ~70 feet (21.3 

meters) above grade to provide a sufficient net positive suction head (NPSH) for the feedwater 

pumps. 

CIRCULATING COOLING WATER 

The primary components in the circulating water system include a forced draft five-cell cooling 

tower, circulating pumps/pipe, and a dedicated chemical feed system. Steam condensing 

temperature in a wet-cooled plant is driven primarily by ambient wet bulb temperature. 

Specifically, cooling water rejects its heat by latent heat of evaporation through the counter flow 

water-to-air cooling tower. The two-speed 250 hp tower fans force ambient air up through its cells 

where the cooling water counter flows downward via gravity and is dispersed over several 

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thousand square feet of cooling tower fill (honeycomb type trays) which maximize heat transfer. 

Large vertical turbine type pumps, mounted on a concrete intake structure providing adequate 

NPSHA, circulate approximately 67,000 gpm (4,227 liter/sec) of cooling water through a 48-inch 

underground pre-stressed concrete pipe header from the cooling tower basin to the cold side of 

the condenser and back to the top of the tower just below its fan deck. 

The cooling tower has three sources of water loss: evaporation, blowdown, and drift (refer to 

water balances in figures 10 to 12 above). Evaporation is by far the largest loss and it basically 

fixed for a given duty and set of ambient conditions. Blowdown (driven by COC) and drift (water 

droplets leaving the tower and not fully evaporated) are the smaller water losses of the tower. 

Altogether, these losses must be replaced and therefore constitute the makeup flow to the tower 

basin. For the reference plant, untreated cooling tower makeup water will be gravity fed from the 

nearby raw water storage tank to the cooling tower basin. A chemical feed storage building 

(complete with tanks, totes, metering pumps, and chemicals) injects chemicals into the tower 

basin to prevent scaling, and micro-biological fouling in the pipe, condenser and tower, which 

ultimately blocks the tower fill and diminishes the tower’s heat transfer capability. 

2.2.4 Thermal Energy Storage 

Thermal energy storage (TES) provides the ability to extend the plant operating hours beyond 

that available from DNI. The reference plant is designed for 6.3 hours (or 1988 MWth-hrs) of 

thermal storage at full turbine output. Energy is stored in large insulated tanks containing molten 

salt made up of 60% (by weight) sodium nitrate and 40% potassium nitrate. The reference plant 

has two tank sets with one ‘hot’ and one ‘cold’ tank per set. As seen in the process flow diagram 

sketch above, during TES charging hot HTF from the solar field exchanges heat with cold salt 

from the cold tank as it flows through an elevated heat 

exchanger and into the hot tank. The reverse happens 

during TES discharging. Hot salt exchanges heat with 

cold HTF where it is then sent to the solar steam 

generators for power generation. TES primary equipment 

includes salt to oil heat exchangers (3 per tank set), 

vertical pumps with variable frequency drive (VFD) motors 

mounted on top of the tanks (3 per tank), valves and 

piping all supported on an elevated pipe rack at full tank 

height to allow draining which prevents salt freezing 

during TES offline hours. 

Since the plant is designed with the ability to fully charge 

TES while generating electricity at full capacity, the solar 

field mirror area must increase to accommodate the 

larger energy demand. A plant with storage will have a 

larger solar multiple (previously defined) than a plat 

without to accommodate the added energy delivered to storage while the power block operates at 

full load. When the power block is generating electricity and the TES is charging, one portion of 

the field delivers energy to the TES and the other to the steam generator train. 

Figure 13. Typical two-tank molten salt 

TES system. 

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2.2.5 Balance of Plant 

Systems supporting the primary thermal systems above are called “balance of plant” systems. 

These include, but are not limited to: fire protection, auxiliary cooling, auxiliary steam, blowdown, 

drains, water treatment, raw water, demineralized water, potable water, wastewater, sanitary 

drains, fuel gas, and compressed air. Systems such as the sampling, condenser air removal, and 

steam turbine auxiliaries are briefly mentioned in other sections of the report. 

FIRE PROTECTION 

All fire prevention and fire protection systems will be designed to protect personnel from injury 

and prevent property damage. The primary fire hazard of a parabolic trough plant is combustion 

of leaking HTF. Reference plant fixed fire suppression systems (sprinkler or deluge) protect the 

HTF expansion tank area, HTF ullage area, HTF pump area, STG area, lubricating oil skid, fire 

pump house, administration/control building, warehouse/maintenance building, water treatment 

building, generator step-up transformer, and the auxiliary transformers. Some of these fixed 

systems may not be necessary depending on the Owner’s insurer requirements; however all are 

included to provide a reference plant design. 

The largest fixed system demand is the outdoor HTF expansion tank area which has a concrete 

firewall between every two tanks to divide the protection area and reduce flow demand. This 

demand plus hose stream flow requires a 3000 gpm (189 liter/sec) firewater pump. One electric 

motor driven and one diesel engine driven 100% capacity pump are included in the reference 

plant. A small 5 hp jockey pump is also needed to maintain pressure in the fire main at all times. 

National Fire Protection Association (NFPA) code recommends that a 2-hour firewater supply 

must be stored onsite and reserved for emergencies. Thus 360,000 gallons (1363 m3

) of firewater 

is reserved via a standpipe in the raw water storage tank. 

The firewater delivery system includes fire hydrants and monitors, post indicating valves, 

manually controlled valve houses, self detecting and actuating deluge systems and an 

underground loop main that feeds all firewater users. Buildings will be equipped with alarms, 

sensors, and fire extinguishers per NFPA code. 

Most constructed CSP plants will require a fire risk evaluation, consultation with an insurance 

company, evaluation of potential on-site fire brigade and emergency plan to determine the best 

approach to fire protection and prevention of the solar field. It is expected that fire protection for 

the solar field will, for the most part, be provided by zoned isolation of the HTF lines in the event 

a rupture of any line results in a fire. A HTF fire will most likely be allowed to extinguish itself 

naturally since the remainder of the solar collector field consists of nonflammable material 

(aluminum, steel, and glass) and the separation between SCAs is significant. Therefore, no solar 

field fire protection equipment is included in the cost estimate. 

AUXILIARY COOLING 

Certain rotating equipment requires cooling water to maintain lubricating oil temperature specified 

by the manufacturer. Turbine lubricating oil, turbine generator, sample panel, HTF pumps, TES 

pumps, feedwater pumps and possibly TES tank foundations all require auxiliary cooling water. 

The auxiliary cooling is accomplished via a closed loop cooling system that absorbs heat from 

each user’s cooler and rejects the combined heat in a common plate-and-frame heat exchanger. 

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Daggett’s high ambient temperatures allow the cooling water system to operate without any 

glycol additive. The heat sink for the closed loop cooling system is the circulating water system. 

A small stream of circulating water is drawn from the system and routed to the closed loop 

cooling system heat exchangers and back to the cooling tower. During start-up when the 

circulating water pumps are not operating, an auxiliary cooling water pump (located in the 

circulating water intake structure) is used to cool the heat exchangers. 

AUXILIARY STEAM 

A natural gas fired auxiliary boiler is needed to supply steam during plant startup and overnight to 

maintain STG seals, condenser vacuum and occasionally for HTF freeze protection. The primary 

auxiliary steam user is the vacuum Hogger which uses steam to evacuate the condenser during 

startup. Once vacuum is established, the Steam Jet Air Ejector (SJAE) holds the vacuum to 

condenser operating conditions. The auxiliary boiler duty is sized for the largest flow which is the 

HTF freeze protection condenser, but at the required SJAE temperature and pressure. 

Secondary auxiliary steam users include the gland steam system for turbine sealing and the 

deaerator for startup sparging steam. 

BLOWDOWN 

Steam cycle chemistry is partially maintained by continuous blowdown of saturated liquid from 

the evaporator. Blowdown is flashed in the blowdown tank where the left over condensate is 

quenched by raw water, collected in the blowdown sump and pumped to the cooling tower basin 

to reduce cooling tower makeup. 

VENTS AND DRAINS 

All steam piping has vents and drains for pressure bleeding, air venting and condensate draining. 

Drain lines are critical for steam system warm-up and condensate removal to avoid turbine water 

induction. 

WATER TREATMENT 

No pre- or post-water treatment is included in the reference plant design. Plant water treatment 

includes demineralized water, potable water, cooling tower chemical feed, and cycle chemical 

feed. Each of these systems is briefly discussed in its own section. 

RAW WATER 

Three-50% capacity centrifugal type well water forwarding pumps will supply the raw water 

storage tank from offsite wells. The underground supply pipeline is 10-inch high density 

polyethylene (HDPE) plastic pipe and extends from the raw water tank to an assumed 200 feet 

(61 meters) off the property boundary north of the access gate. Three (3) 10-inch diameter wells, 

500-feet (152 meters) deep, 200 feet (61 meters) off the property boundary have been included 

in the cost estimate. Assuming well water as the raw water source is a significant assumption. 

Raw water supply is completely site dependent and could vary in source (surface, well, utility), 

quality, and quantity. 

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Figure 14. High 

pressure mirror wash 

The field-erected carbon steel raw water storage tank is sized to provide 14 hours for cooling 

tower makeup, blowdown quench, demineralized treatment system, and service water; as well as 

the aforementioned reserved firewater volume. Service water pumps typically supply blowdown 

quench water, plant hose streams and demineralized and potable treatment systems. 

DEMINERALZED WATER 

The demineralized system, located in the water treatment building, will use electrostatic 

deionization equipment with multimedia filtration and reverse osmosis processes. Water 

treatment design is very specific to the incoming water quality. A general water quality was 

assumed to arrive at a typical system for the reference CSP trough plant. The plant’s two 

demineralized water users are mirror washing and steam cycle makeup. Demineralized water is 

stored in two field-erected lined carbon steel water tanks. Water storage capacity holds up to 30 

hours of cycle makeup, 2 days of cycle makeup for startup, and 2 days of solar field mirror 

washing. 

Steam cycle makeup replaces cycle blowdown. Cycle makeup flow is significantly higher during 

startup than normal operation due to the larger blowdown flows and condensate consumption for 

bypass desuperheat spray. 

Mirror wash water is transferred from the storage tanks to the truck fill 

station. Although reverse osmosis filtered water can be used, 

demineralized water quality is the best quality water for mirror washing— 

leaving no spots or scaling which could reduce reflectivity. Mirror 

washing profiles are estimated based on reports from the existing Solar 

Electric Generating Station (SEGS) at Kramer Junction California. In the 

summer, deluge spray trucks and high pressure rigs wash the field 

nightly to maintain mirror reflectivity to its installed value. In off-summer 

months, mirror washing is dramatically decreased due to lower wind 

speeds, natural cleaning by precipitation, and less frequent plant 

operation. Wash trucks will fill their water tank and fuel tank at a common 

station. An aboveground diesel storage tank with built-in pump will 

provide several months of fuel for wash trucks and general facility 

maintenance trucks. The canopy covered fill station will have dedicated 

parking spaces for the extra large wash trucks. 

POTABLE WATER 

A potable water treatment skid will be located in the water treatment building and supply a small 

shop fabricated potable water tank with a 36-hour supply. Potable water forwarding pumps will 

supply typical users such as building facilities (sinks and showers), eye washes, and safety 

showers. 

OILY WASTEWATER 

Spill containment will be provided for HTF pumps, expansion tanks, and ullage systems to collect 

possible HTF leaks and/or pump lubrication oil leaks. Containment is an open concrete curbed 

area sloping to a low point drain sump. Discharge from the HTF containment areas cannot be 

tied into the oily waste water system because HTF is heavier than water, whereas traditional oilwater separators used at power plants operate on the opposite principle. No HTF-laden water 

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waste system has been included in the cost estimate; it is assumed that waste hauling trucks will 

periodically remove such waste water, although an alternate solution may be possible. Non-HTF 

oily waste water from truck fueling area, large transformer areas and STG lube oil areas will be 

routed to a common underground oil-water separator where the effluent water is then pumped to 

the cooling tower basin to reduce make-up water. 

SANITARY DRAINS 

Personnel sanitary waste facilities will discharge to the onsite septic tank located underground 

just outside of the water treatment building. Effluent will distribute across the adjacent leach field. 

Waste hauling trucks will periodically clean out the septic tank. 

FUEL GAS 

The reference plant single natural gas user is the auxiliary boiler. It is assumed that a nearby 

natural gas pipeline is available for interconnection. A 1.5-inch carbon steel supply line, locally 

regulated at the interconnection, will feed fuel gas to the auxiliary boiler with secondary regulation 

at the boiler. 

COMPRESSED AIR 

Two redundant oil-free rotary screw type air compressors with an air dryer and receiver tank will 

be located in the water treatment building. Small bore (less than 2” nominal diameter) stainless 

steel piping will supply instrument and service air throughout the power block for control valve 

actuation, instrument control, and general operator service. No instrument or service air will be 

installed in the solar field. All solar field HTF valves will be motor driven or manual. 

2.3 Electrical System Descriptions 

The electrical systems will consist of a generator with step-up transformer, an auxiliary supply for 

the power block, a distribution system for the solar field, and a transmission tie line with an 

interconnecting substation. The generator voltage is 13.8 kV, the step-up transformer will be 

13.8/230kV, the transmission tie line will be 230 kV and the auxiliary power block and solar 

distribution systems will be both 4160v and 480v. 

A brief description of each primary system and its sub-systems will be discussed throughout this 

section. Below is a list of the major electrical equipment which make up the reference plant 

design. Bulk mechanical materials such as cable, connectors, panel boards etc. are not listed at 

this design level, but are included in the cost estimate. 

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Table 6. Major electrical equipment list for Daggett reference plant. 

EQUIPMENT NAME QTY 

TRANSFORMERS 

Generator Step-Up Transformer 1 

Unit Auxiliary Transformer 2 

Station Service Transformers 9 

Excitation Transformer 1 

Solar Field Transformers 9 

Solar Collector Drive Power Converters 1208 

Emergency Transformer 1 

CIRCUIT BREAKERS 

Generator Circuit Breaker 1 

Main Circuit Breaker 1 

SWITCHES 

Circuit Switcher (switchyard) 1 

Main Disconnect Switch 4 

Transmission Line Disconnect Switch 2 

Generator Disconnect Switch 1 

Automatic Transfer Switch (for back-up battery power) 2 

OTHER EQUIPMENT 

Isolated Phase Bus Duct (IPBD) Lot 

Metering Current Transformers (CTs) 3 

Metering Potential Transformers (PTs) 3 

Control Relays Lot 

Ground Grid Lot 

Distributed Control System 1 

Uninterrupted Power Supply (UPS) - Balance of Plant 1 

Power Distribution Center (PDC1A) with Switchgear and Motor Control 

Centers (MCC) - Cooling Tower & TES Areas 

1 

Power Distribution Center (PDC2A) with Switchgear and Motor Control 

Centers (MCC) - STG & HTF Areas, includes ESS Switchgear 

1 

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Figure 15. Conceptual electrical one-line diagram including all 4160 V connected equipment. Sheet 1.
 

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Figure 16. Conceptual electrical one-line diagram including all 4160 V connected equipment. Sheet 2.
 

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2.3.1 Transformers 

The generator step-up (GSU) transformer will be 125 MVA and connected to the generator via an 

isophase bus duct. An additional T-connected isophase bus duct will connect the two auxiliary 

transformers (25 MVA) to the isophase bus duct on the low side of the GSU. These transformers 

will be set up to split the load under normal operating conditions, but will be able to pick up the 

entire load if necessary through tie breakers between the switchgear and motor control centers 

(MCC). There will be two power distribution center (PDC) in which the switchgear and MCC’s will 

be located. A 750 kW emergency generator will be provided to serve the critical loads including 

the SCA’s in the solar field and essential loads in the power block area. 

2.3.2 Solar Field Power Distribution 

The solar field will be served from the 4160v switchgear in the power block PDC. There will be 

nine 225 kva, 4160v-480v transformers with adjacent 480v panelboards. The panelboards will 

provide individual feeds to subpanels to serve the SCA’s. The cables to serve the transformers 

will be undergrounded in duct banks. 

2.3.3 Switchyard 

The grid tie line will be 230 kV connecting the generator step-up transformer through an 

interconnecting substation to the utility grid. This will be a single line connection with breaker and 

disconnect switches. 

2.4 Instrumentation and Control System Descriptions 

Instrumentation and controls are provided to monitor and control the solar collection field and the 

power block equipment. The plant control system consists of two functional systems: a 

distributed control system (DCS) for the power block including the HTF system, and a solar field 

control (SFC) system for the solar field equipment. 

2.4.1 Power Block System Controls 

All plant control systems are microprocessor-based. All key system parameters are monitored, 

controlled, displayed, alarmed, recorded and trended. The system has a distributed architecture 

comprised of standard technology including Ethernet and serial communications with standard 

communications protocols such as TCP/IP and MODBUS TCP/IP. 

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The system is based on Windows-compatible work stations and servers for operator interface 

and system engineering functions. Additional operator interfaces can be placed in local control 

centers, supervisor's offices, etc. The system engineering workstations also support all operator 

station functions. 

Independent process controllers are provided for major plant systems including: HTF, balance of 

plant, steam generation, etc. Process controllers may be distributed to local control centers or 

other remote concentrations throughout the plant. 

2.4.2 Power Block Distributed Control System (DCS) 

PLANT SYSTEM CONTROL 

The DCS provides control functions for power generation either manually or semi-automatically. 

The control system provides automatic coordinated control, turbine follow, sliding pressure, and 

manual control configurations. The DCS controls all plant systems including: 

condensate/feedwater and steam, turbine / generator and heat transfer fluid. Integration of 

vendor supplied programmed logic controllers (PLC) and controls are seamless with the process 

control and information management system. 

The DCS monitors and controls the following auxiliary systems: 

o	 Auxiliary boiler including: fuel systems, burner management, combustion air, furnace 

draft and selective catalytic reduction (SCR). 

o	 Water treatment system through a PLC-based control system provided by the equipment 

supplier. 

o	 Diesel generator through a PLC-based control system provided by the Diesel Generator 

supplier. 

o	 Circulating water system 

o	 Closed Cooling Water System 

o	 Condenser Vacuum System 

o	 Chemical Feed Systems 

TIME SYNCHRONIZATION 

A GPS time synchronization system is supplied with the DCS. IRIG B signals from this system 

shall be used to synchronize time in all DCS equipment as well as the solar field control system. 

This time signal is used in the algorithm for calculating the position of the sun and manoeuvring 

the solar collectors. 

2.4.3 Power Block Control Room and Electronics Room 

CONTROL ROOM OPERATOR INTERFACE 

The control room design is a soft DCS display-based operator interface consisting of multiple 

operator workstations, and a DCS server/workstation cabinet. A common control room is 

provided for the power block and solar field operator displays. 

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An auxiliary benchboard control panel is provided for hardwired trip pushbuttons for the steam 

turbine trip and auxiliary boiler trip, direct steam generator level indication, direct hardwired 

operator interface with the turbine direct current (DC) oil pumps, direct hardwired operator 

interface with the emergency diesel generator, and turbine synchronization switches and 

synchroscope. 

Visual and audible alarms are provided to alert the operator of abnormal operating conditions and 

to provide a record of operations events. All alarms are recorded in the plant data historian. 

The DCS has data historical storage and retrieval capabilities in order to facilitate long-term 

monitoring of plant equipment and performance. This system provides the ability to generate 

reports and trends of the stored historical data. 

ELECTRONICS ROOM 

The electronics room provides housing for the engineering workstations, vibration monitoring 

system cabinets for the steam turbine, boiler feed pumps and HTF pumps, UPS Power 

Distribution panels, generator / transformer protection panels, switchyard protective relaying 

cabinets, DCS control processor and I/O cabinets, STG control system and the DCS networking 

cabinet. 

2.4.4 Power Block Communications Network 

The DCS data highway is based on a Gigabit Ethernet communications system. The data 

highway and remote I/O communications are redundant (see Figure x). The data highway inside 

the control room and electronics room utilizes the DCS vendor’s standard copper cable for short 

connections. Fiber optic cables are used for longer routes between buildings and rooms. 

2.4.5 Power Block Instrumentation Requirements 

Redundant measurements are performed for system critical process variables.: The redundant 

measured variables include: turbine throttle pressure & temperature, turbine reheat pressure & 

temperature, steam generator pressure & level, feedwater pressure & temperature, condensate 

pressure & temperature, deaerator tank level, condenser pressure, hotwell level, superheater 

pressure & temperature, BFP flow, feedwater & condensate heater level and instrument air 

header pressure. 

The control system processes triple redundant inputs using a median select algorithm be used for 

control and protection. Dual redundant instruments are averaged. An alarm is generated if the 

deviation between instruments exceeds a predetermined deadband. 

2.4.6 Solar Field Control System and Equipment 

The solar field control (SFC) system consists of a microprocessor based supervisory control and 

data acquisition (SCADA) system, and local controllers for each solar collector. All solar field 

system parameters are monitored, controlled, displayed, alarmed, recorded and trended. The 

system is based on Windows-compatible work stations and servers for operator interface and 

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system engineering functions. The SFC network is seamless with the power block DCS network. 

All data is shared between networks. 

SOLAR FIELD CONTROL SYSTEM 

The SCADA system provides monitoring and high level control of the entire solar field. The 

SCADA system provides each local controller with master Track, Defocus, Stop, and override 

control signals. The system monitors the operation and performance of each local controller and 

associated solar collector and provides process indication and alarms on a central control room 

display. 

A local controller is provided for each solar collector assembly. The controller contains a 

microprocessor based control system such as a PLC, a variable speed drive / servo valves for 

actuation of the collector drive system, a network switch and any electrical distribution and 

protection equipment. 

Each local controller operates independently. Once given a master control signal from the 

SCADA system that initiates the Track mode, the local controller calculates the position of the 

sun based on its latitude and longitude and the time from the GPS clock and positions the solar 

collector appropriately. 

The local controller monitors the angular position of the collector for accurate closed loop 

feedback control. Any deviations from the calculated position are alarmed in the control room. 

A temperature element is installed in the HTF pipe at each solar collector. The local controller 

monitors this temperature and “defocuses” the positioning of the solar collector to prevent overtemperature conditions. 

SOLAR FIELD CONTROL ROOM 

The SCADA operator interface displays are seamless with those provided with the DCS. The 

control network provides data sharing between the power block and solar field systems. A 

common control room is provided for the power block and solar field operator displays. 

Independent data historical storage and retrieval capabilities are provided for the solar field 

network in order to facilitate long-term monitoring of the solar field equipment and performance. 

SOLAR FIELD COMMUNICATIONS NETWORK 

The SFC data highway is a based on a star – ring configuration. The network utilizes multi-mode 

fiber optic cable. To eliminate any potential for disruptive signal noise, no copper communication 

cables are utilized in the solar field. 

The solar field is divided into sectors. Each sector has it own network using a HIPER-ring or 

turbo-ring design. This design provides an inherent level of redundancy in that if a segment is 

broken the data signal is transmitted around the ring in both directions. 

Each solar field sector is connected to the plant control network using a star configuration. The 

fiber optic cables forming the star are non-redundant; however, spare fiber is installed in the 

event that one or more strings are damaged. 

SOLAR FIELD INSTRUMENTATION 

A meteorological tower station is included. Each tower is equipped with instrumentation to 

monitor wind speed, wind direction, normal incident solar radiation, temperature and barometric 

pressure. Each tower is supplied with power from separate and independent power sources. 

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The instrument signals communicate with the plant control network using a wireless 

communications system. 

2.5 Civil Sitework Descriptions 

2.5.1 Roads, Parking, and Fencing 

The reference plant will be accessed from the nearest major intersection in Daggett, CA via an 

existing public road that has been assumed to be asphalt paved. Due to heavy construction traffic 

this public road will need to be resurfaced when construction is complete. All existing roadways, 

intersections, and bridges will need to be evaluated for oversized/heavy haul deliveries. All 

proposed roadways will be designed for this as well. A proposed asphalt paved entrance road will 

intersect the existing public road and continue towards the solar field. This entrance road will 

terminate at a guard house and gated entrance at the northeast corner of the reference solar 

field. Access will continue along the east side of the solar field and turn west towards the power 

block on an asphalt paved power block road. A loop road will encompass the perimeter of the 

power block. The southern half of the power block loop road will be paved with asphalt, while the 

northern half will be surfaced with gravel. An asphalt surfaced parking lot will be located adjacent 

to the Warehouse/Maintenance Building and Administration Building within the power block. 

Refer to figures 17 to 19 below for roadway sections and details. 

Figure 17. Typical road section detail for site access and inner power block asphalt roads. 

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Figure 18. Typical road section detail for perimeter gravel roads. 

Figure 19. Typical road section detail for gravel roads. 

Solar array access roads will be provided between each parabolic trough for mirror washing 

activities. These solar array roads will consist of proof rolled compacted native soil. A gravel loop 

road will encompass the perimeter of the solar field. A diversion channel will be located on the 

upstream side of the gravel solar field loop road to divert offsite watershed runoff around the solar 

field site. A perimeter security fence will be located just outside of the diversion channel, 

encompassing the perimeter of the solar field, including the detention and evaporation ponds. 

2.5.2 Bioremediation / Land Farm Area 

A bioremediation/land farm unit will be required to treat non-hazardous soil contaminated from 

HTF spills. Soil contaminated from HTF spills that test as a Resource Conservation and 

Recovery Act (RCRA) characteristic waste will be managed as hazardous waste. The 

bioremediation area will include a concrete-lined shallow basin and a leachate collection and 

removal system (LCRS). 

Treatment in the bioremediation unit will involve the addition of nitrogen and phosphorous (i.e., 

fertilizers) as nutrients to the HTF-contaminated soil to stimulate consumption of HTF by the 

native bacteria. The soil will remain in the bioremediation unit until concentrations are reduced 

sufficiently to allow its re-use as on-site fill material. Soil for reuse would be placed within the 

fence boundaries to preserve isolation between the adjacent wildlife and habitat and any 

bioremediated soils. 

The land farm area will be located next to the bioremediation area. Soils will be brought to the 

unlined land farm, mixed with compacted lime treated native soil, and stored there until 

hazardous concentrations are low enough to be used as fill material on the site. Natural 

attenuation is the only “treatment” that occurs at the land farm; no additives (e.g., fertilizer, water) 

would be used. 

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2.5.3 Site Preparation, Earthwork, and Improvements 

Since the topography of the reference plant is unknown, a grading plan to establish earthwork 

quantities was not performed. One of the main objectives of a site grading plan design is to 

minimize earthwork movement. A zero balance grading plan is ideal (i.e. no import or export of 

earthwork) and has been assumed to be achievable for this reference plant. At a minimum 6 

inches (152 mm) to 1 foot (304.8 mm) of soil will be removed and/or relocated within the site 

during clearing, grubbing, and grading activities. It has been assumed for this reference plant 

that 1 foot (304.8 mm) of earthwork (cut/fill) will be moved over the entire solar field site. It has 

also been assumed that the entire solar field site is covered with desert vegetation (shrubs, etc.). 

Therefore the entire solar field site will need to be cleared and grubbed prior to rough grading. 

Prior to beginning any earthwork activities, including clearing and grubbing, site preparation must 

be performed by strategically placing erosion and sediment control measures (Best Management 

Practices – BMPs) per the Erosion and Sediment Control Plans and Details. This includes the 

installation of silt fence, rock check dams, riprap, inlet/outlet protection, gravel construction 

entrances, construction laydown and stockpiling areas, slope protection/erosion control blankets, 

etc. There will be two temporary aggregate surfaced construction laydown and parking areas, 

one for the power block and one for the solar field, located just outside of the power block. 

Adjacent to the temporary solar field laydown area there will be a temporary solar collector 

fabrication area. The final surfacing for the power block will be yard aggregate while the final 

surfacing for the solar field will be native soil. 

2.5.4 Onsite Drainage, Detention, and Evaporation Ponds 

A 1% to 2% slope range, in the east-west direction, and 0% (flat) to 1% in the north-south 

direction is ideal for the east to west single-axis sun tracking parabolic trough field in aboveequator regions. It has been assumed that the reference plant’s topography will allow for this 

grading scheme. Ideally, evaporation ponds will be located downstream of the power block to 

allow for gravitationally fed cooling tower blowdown. Detention ponds will always be located 

downstream of the natural flow of storm water runoff. Site specific information may require 

several smaller detention ponds separately located around the perimeter of the field; however, 

one larger one was assumed for this reference plant. 

Figure 20. Typical evaporation pond detail. 

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The 20 Acre-Ft detention pond will capture the developed major storm event and release the 

runoff through a concrete outlet structure at the historic rate. The detention pond will also be 

equipped with an emergency spillway designed to pass the developed major storm event. 

Existing major drainage washes will be diverted around the solar field site via diversion channels. 

These diversion channels will return the upstream offsite runoff to their original course on the 

downstream side of the solar field site. 

2.5.5 Thermal Storage Salt Containment Berm 

An earthen berm will surround the thermal salt storage tanks inside the power block. The berm 

shall be designed to contain the volume of two salt storage tanks. This is assuming two of the 

four tanks have a failure at the same time. Access will need to be provided from the power block 

loop road into the salt storage tank area. This will require concrete surfaced vehicular ramps 

down into the containment over the berm. These ramps will be located in an area where 

adequate run out and turning space is provided as the vehicles enter the containment area (i.e. 

not immediately adjacent to the salt storage tanks). The ramps shall be sloped and laid out to 

accommodate safe access by all potential maintenance vehicles. At least two ramps will be 

provided; one ramp for smaller day to day maintenance vehicle access and another ramp for 

larger semi-trailer and crane access. 

Figure 21. Salt storage berm section detail. 

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Figure 22. Salt storage berm maintenance access drive ramp detail. 

2.6 Structural Support and Foundation Descriptions 

2.6.1 Solar Field Structures and Foundations 

Each SCA will be supported by drilled piers (caissons). Not having any soil data, caisson 

diameter and depth were assumed. The HTF pipe header and SCA loop piping supports will also 

be supported by drilled caissons. These caissons also have an assumed diameter and depth. 

The power block will have structural steel pipe racks to support HTF/steam/water pipe, 

electrical/control cable, and lighting. A larger heavy duty rack will support the HTF headers up 

until the final reheater vessel, where the rack will transition into a smaller rack to support the 

lighter steam and water lines. A similar pipe support rack will be needed for HTF header pipe 

feeding the TES system. 

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Figure 23. Solar collector foundation—normal drive pylon section detail. 

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Figure 23. Solar collector foundation—drive pylon section detail. 

2.6.2 Power Block Structures and Foundations 

There will be several equipment foundations and containment areas required in the power block 

area, with the STG concrete foundation supporting the heaviest duty. The HTF Expansion Tank 

and overflow pumps will share a common concrete foundation system with concrete containment 

and a local sump for potential HTF leaks/spills. The bulk nitrogen storage and vaporizer will 

require smaller individual concrete slab foundations. The HTF circulation pumps will require a 

concrete slab foundation with curbing/containment. The solar steam generator heat exchangers 

will share a common concrete foundation system with curbing/containment. 

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3. COST ESTIMATE BASIS (SUBJECT TO REVISION) 

The estimate is based on an Engineer – Procure – Construction Management (EPCM) approach. 

Engineering and Design, Construction Management, and Start-up & Commissioning costs are 

included. 

Material Take-off (MTO) and Design Allowances are included in the estimate and are intended to 

compensate for the degree of engineering that is incomplete. This is not a contingency; rather it 

is a minor allowance included to cover the nominal quantity growth which inevitably occurs as the 

design is further developed. 

Contractor mark-up on bulk materials reflects the mark-up that contractors will apply to bulk 

materials provided under their respective contracts. A rate of 5% is used for these materials. 

This has been reduced from the more typical rate of 8% to account for the “engineered bulks”, 

including most of the piping being supplied by the EPCM contractor and thus not being subject to 

a mark-up.. 

The estimate excludes escalation. All costs are presented as overnight 2nd Quarter 2009 

dollars. 

Project Contingency addresses unforeseen elements of costs within the current defined project 

scope. It is expected that by the end of the project the entire contingency will be spent on either 

direct or indirect costs. The contingency is applied as follows, 5% on equipment, 10% on bulk 

material, 10% on installation labor for the solar field and 15% on the balance of installation labor, 

and 0% on professional services. 

3.1 Quantity Development 

Equipment quantities for major equipment components are based on preliminary engineering 

provided in drawings, flow diagrams, process and instrumentation diagrams (P&IDs), equipment 

lists, and electric one-line diagrams. Major piping networks such as HTF, steam, feedwater, 

condensate, circ water, and firewater were conceptually laid out and specified on P&IDs. 

Minor balance of plant equipment not included in the project design documents are based on 

similar plant designs previously developed by WorleyParsons. Examples of minor balance of 

plant equipment include steam turbine gland steam seal system, condenser air removal system, 

cooling tower chemical feed system, service air system, steam / water sampling system, and 

compressed air systems. Bulk material quantities were developed for select major systems based 

on conceptual routings and sizing where available. Quantities for the balance of plant systems 

were developed by scaling from a similarly sized plant to meet specific NREL site requirements. 

3.2 Material and Equipment Pricing 

The following equipment costs are based on budgetary quotes: 

o Thermal energy storage system (EPC turnkey) 

o Steam turbine generator, gland steam condenser, and lube oil skid 

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o Cooling tower 

o Solar steam generator heat exchangers 

o Feedwater heaters 

o Demineralized water treatment system 

o HTF expansion tanks 

o Temporary solar collector assembly fabrication tent 

o Salt nitrates for thermal storage 

o HTF fluid 

Remaining equipment costs are based on WorleyParsons cost estimating database, adjusted to 

2Q2009 dollars. The bulk material costs are based on recent pricing for similar materials from the 

WorleyParsons estimating database, adjusted to 2Q2009 dollars. Most of the equipment and 

materials will be transported by truck to the project site. 

3.3 Construction Labor 

Overall construction labor costs include wage rates, installation hours, labor productivity, labor 

availability and construction indirect costs. 

3.3.1 Wage Rates 

Union shop wage rates are based on the 2009 RS Means Labor Rates for the Construction 

Industry. Rates are based on Riverside, CA and are valid to 2Q 2009. 

As an added level of project cost verification, WorleyParsons performed a cost comparison using 

Yuma, AZ merit shop craft wage rates as a baseline. It appears that Riverside, CA union wage 

rates add approximately 38% to the labor cost component (without the productivity factor), and 

approximately 56% when the productivity factor is included. 

3.3.2 Installation Hours 

WorleyParsons maintains a database of standard unit installation hours. The database 

represents standard installation rates for US Gulf Coast Merit Shop. Equipment setting manhours were developed by evaluating estimated weights, equipment size, and number of 

components in conjunction with crew sizes and approximated time. Bulk material man-hours are 

based on standard unit installation rates. The resultant hours are further adjusted for productivity 

(described below). 

3.3.3 Labor Productivity 

The estimate reflects productivity for the Daggett, CA area. In evaluating productivity, factors 

such as jobsite location, type of work (i.e. new construction) and site size are considered. Labor 

productivity factors (multipliers over US Gulf Coast Merit Shop) have been included to reflect 

anticipated site specific labor productivity. A productivity factor of 1.2 was applied to the USGC 

labor hours, with the exception of the SCA assembly work performed n the on-site fabrication 

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structure and the hours associated with salt melting. No productivity adjustment was applied to 

furnish and erect quotes obtained specifically for this project. 

3.3.4 Labor Availability 

Labor is based on a 50-hour work-week (5-10s). The estimate includes an allowance of $60/day 

for travel and per diem. No additional incentives have been included to attract or retain craft 

labor. The estimate is based on an adequate supply of qualified craft personnel being available to 

staff this project. 

3.3.5 Construction Indirect Costs 

In addition to base wage rates and fringe benefits, labor costs include construction indirect costs 

consisting of: 

o	 Payroll taxes and insurances 

o	 Contractor’s General Liability insurance 

o	 Construction supervision 

o	 Indirect craft labor 

o	 Temporary facilities 

o	 Field office 

o	 Small tools & consumables 

o	 Material handling 

o	 Safety / incentives 

o	 Mobilization / demobilization 

o	 Premium time portion of extended work week 

o	 Craft bussing within the construction site 

o	 Construction rental equipment 

o	 Fuel, oil & maintenance for construction equipment 

o	 Contractor’s overhead and profit (on labor-related costs) 

3.4 Clarifications 

3.4.1 Civil / Structural 

o	 The site is relatively flat. No underground obstructions, rock formations, or unusual 

site conditions exist. 

o	 All grading will be balanced across the site. 

o	 Earthwork (rough grading) is based on 1 ft of earth movement over the entire solar 

field site. 

o	 Site geography is assumed to have an average slope between 1% and 2% and can 

be graded with conventional equipment. 

o	 Topsoil removal is not required. The topsoil will be scarified and compacted. 

o	 Approximately 1000 acres (4,046,873 m2

) of land will be cleared and grubbed. Desert 

vegetation (shrubs, etc.) covers the entire site. 

o	 Dewatering is not required. 

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o	 The power block and access roads will be paved (asphalt or gravel). The solar field 

roads will be compacted native soil (proof rolled). 

o	 Soil binder/stabilizer is not included for dust control at solar field roads. 

o	 The entire site will be fenced with 8 foot (2.4 m) high chain link fencing with barbed 

wire. 

o	 The evaporation ponds will have a single HDPE liner. A leak detection system is not 

included. (In the process of verifying whether double liner and leak detection is 

required by California Code) 

o	 The detention pond will be unlined with a compacted native soil bottom. 

o	 The soil under the bio-remediation area will be lime treated. 

o	 Concrete foundations are based on 4000 psi concrete. Piles are not required. 

o	 Concrete foundations are included for all equipment and buildings. 

o	 The steam turbine and ancillary equipment will be outdoors. 

o	 Warehouse & maintenance, water treatment, administration, and cooling tower 

chemical feed/storage buildings are included. 

o	 A fabrication tent for the solar array structure assembly is included. 

o	 Sanitary waste will not be piped offsite; rather it will run through a septic tank and run 

through an onsite leach field. 

3.4.2 Mechanical / Piping 

o	 Thermal energy storage system is a completely installed, tested and commissioned 

turnkey EPC cost from a vendor. 

o	 Not having any known land constraints, the solar collector field is laid out in a squareshaped array with a central power block to minimize HTF pumping loads. 

o	 The salt fill will be delivered in one-tonne supersacs. Salt melting equipment and 

labor are included. Salt blending is not required, therefore, it is excluded. 

o	 Cooling tower blowdown will be discharged to three on-site evaporation ponds. 

o	 Cooling tower makeup will be gravity fed from the adjacent raw/fire/CT makeup 

storage tank. 

o	 Stress relieving for piping is included as required by code. 

o	 Expansion loops for the HTF piping are included. 

o	 Water supply will be provided by three water wells. Electric well pump power is not 

included in the plant’s auxiliary power load and will be purchased directly from the 

utility having jurisdiction. 

o	 No water quality information is known and therefore no pre or post water treatment is 

included. 

o	 A natural gas pipeline with adequate pressure and allowed permission is assumed 

within reasonable proximity for plant interconnection (i.e. no onsite natural gas 

compression or propane storage is needed). 

o	 SCA costs are built bottoms up from individual component costs (mirror, structure, 

receiver). 

o	 An empirical sun-tracker using a shadowed PV plate concept is included on all 

SCAs. These are typically not needed if the drives have pre-programmed tracking 

logic built-in. The empirical tracker is included for redundancy per NREL’s direction. 

o	 No wind fence is included in the estimate. 

o	 No fire protection equipment is included in the solar field. Only power block 

equipment is protected. 

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o	 Underground steel pipe is coated and wrapped. 

3.4.3 Electrical / Instrumentation 

o	 A 13.8kV-230kV generator step-up transformer is included. 

o	 An on-site switchyard with 230kV main circuit breaker and main disconnect switches 

are included. 

o	 No transmission lines beyond the switchyard are included. 

o	 The estimate includes auxiliary transformers, station service transformers, and solar 

field transformers. 

o	 SCA drive power converters are included. 

o	 PDC buildings and equipment are included. 

o	 Underground duct bank is included. 

o	 Cathodic protection is included for underground piping. 

3.4.4 Other 

o	 Engineering work assumes that the selected site is void of all fatal-flaws which could 

significantly impact project cost and schedule. These flaws include, but are not 

limited to: habitat and locations of threatened-endangered and sensitive species, 

abundance of other protected (e.g., native) species, distribution of noxious weeds, 

areas of critical wildlife habitats and movement corridors, contaminated soil or 

hazardous materials, archaeological artefacts, distribution and significance of cultural 

resources, Native American Tribal concerns, recreational areas, special land use 

designations (e.g., BLM Areas of Environmental Concern), and others. 

o	 Utility transmissions such as natural gas and supply water are included (excluding 

electric transmission) up to 200 feet off the furthest site boundary 

3.5 Exclusions 

As discussed above, the scope of the estimates is generally limited to scope within the 

project fence. A list of items excluded from the estimate is as follows: 

o	 Demolition and removal of existing structures 

o	 Import duties & tariffs 

o	 Extraordinary noise mitigation or attenuation 

o	 Owner’s Costs 

o	 Allowance for funds used during construction 

o	 All taxes with the exception of payroll taxes 

o	 All offsite infrastructure costs 

o	 Upgrades to existing rail spur to accommodate delivery of large equipment 

o	 Temporary housing and facilities for the construction workers 

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3.5.1 Typical Owner’s Costs 

Owner’s costs are excluded from the estimate. Typical Owner’s costs include, but are 

not limited to, the following: 

o Permits & Licensing 

o Land Acquisition / Rights of Way Costs 

o Economic Development 

o Project Development Costs (Geotechnical Investigation & Site Survey) 

o Legal Fees 

o Owner’s Engineering / Project & Construction Management Staff 

o Plant Operators during start-up 

o Electricity consumed during start-up 

o Fuel and Reagent consumed during start-up 

o Initial Fuel & Reagent Inventory 

o Transmission Interconnections & Upgrades 

o Operating Spare Parts 

o Financing Costs 

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APPENDIX A
 

CAPITAL COST ESTIMATE SUMMARY
 

68
ESTIMATE SUMMARY 

(Using Riverside, CA union labor rates)

NREL Task 1 Parabolic Trough Cost Assessment

103 MW net with 6.3 hrs Thermal Storage

9/4/2009 Revision 1 

01 02 03 04 05 

06 07 08 

09 

ITEM QTY UNIT MATERIAL LABOR T

Site Improvements 1 LS $ 13,545,000 $ 18,626,000 $ 

Solar Field 1 LS $ 197,203,000 $ 260,999,000 $ 4HTF System 1 LS $ 50,304,000 $ 53,150,000 $ 1

Thermal Energy Storage 1 LS $ 191,786,000 $ 5,450,000 $ 1

Fossil Backup 1 LS $ - $ - $ 

Power Plant 1 LS $ 79,436,000 $ 41,570,000 $ 1

EPCM Costs 1 LS $ Project, Land, Misc. 1 LS $ 

%DC's Sales Tax Applies 1 LS $ 

Subtotal $ 532,274,000 $ 379,795,000 $ 9

Contingency $ 

TOTAL ESTIMATE - EPCM BASIS $ 1,0

 $  $ 

CRITICAL NOTES 

1 Thermal energy storage equipment cost is based on a turnkey budgetary quote from the single commercially available salt storage vendor. 

approach would be to estimate the storage system from the ground up and compile vendor quotes for each sub-component (tanks, pumps, 

2 NREL has selected a 2.0 solar multiple. The solar multiple has a significant capital cost impact and is subject to the project developer's fina3 Cost reflects NREL's selected 150-meter trough design. This trough is the most proven design with the most utility-scale installations; how

labor costs are higher than alternative emerging designs (i.e. 100-meter trough, or SkyFuel) 

4 Labor rates are union-based for Riverside, California with a productivity factor of 1.2. Alternatively, merit-shop based labor rates can signifi

SAM User 1 
APPENDIX B
 

O&M COST ESTIMATE SUMMARY
 

70
Project Name: CSP Trough Plant Cooling Study 

Project Desc: 103MW net w/ 6.3 hrs TES - Wet Cooled 

Location: Daggett, CA 

Client: National Renewable Energy Laboratory 

Date: 11/05/09 

Revision: B 

Originator: D. Ross 

Reviewer: G. Aron 

Model Inputs 

Est Gas Cost $/MMBtu $6.00 

Est Water Cost $/acre-ft $450 

Est Auxiliary Power Cost $/kWh $0.08 

Field Design 

Solar Field Effective Mirror Aperture Area m2 987,540 

Net Plant Output to Grid MWe 103 

Annual Net Power Generation MWe-hr 426,717 

Total Installed Capital Cost $ $1,015,661,000 

O&M Cost Breakdown 

Onsite Staff $5,283,900 

Utilities 

Purchased Auxiliary Electricity $296,240 

Natural Gas $53,400 

Water $558,450 

Utilities Sub-Total $935,333 

Consumables $1,031,043 

Maintenance & Repairs 

Solar Field $903,751 

HTF System $278,298 

TES System $338,000 

Power Block $2,071,188 

Maintenance & Repairs Sub-Total $3,698,974 

Chemicals & Water Treatment $145,119 

Office & Administration $105,464 

Training $81,242 

Contract Services $377,308 

Miscellaneous Cost $110,203 

Total Annual O&M Cost $11,768,584 

O&M Percent of Total Installed Capital Cost 1.16% 

NOTES 

1 Fixed and variable costs are based on 2nd quarter 2009 US$ projected to 2012 first operating year.
 

2 Water consumption estimates are based on the analysis performed under this task.
 

3 Raw and waste water assume no pre or post water treatment, respectively.
 

4 Maintenance and repairs includes spare parts and labor.
 

5 Solar collector mirror washing is sub-contracted from June through Sept. Mirror washing is performed by plant staff for the remaining months.
 

6 Miscellaneous costs are 2.5% of maintenance/repairs, chemicals/water treatment, office/administration, training, and contract services.
 

71
Appendices to NREL TP-47605, 

Parabolic Trough Reference Plant for Cost Modeling with the Solar Advisor Model; C. Turchi 

Appendix B 

CSP Parabolic Trough Plant Cost Assessment

Dry-Cooling Option 

WorleyParsons Group 

Report under NREL contract KAXL-9-99205-01 

December 14, 2009 

72
NATIONAL RENEWABLE ENERGY LABORATORY 

Dry Cooling Option 

ADDENDUM TO: 

CSP Parabolic Trough Plant 

Cost Assessment 

59002501 – NREL-0-LS-019-0002 

REVISION B 

14DEC2009 

WorleyParsons Group 

Americas, Northwest Region 

Denver Office 

1687 Cole Blvd, 

Suite 300, 

Golden, CO, 80401, USA 

Tel: +1 303 928 4226 

Fax: +1 303 928 4230 

73
NATIONAL RENEWABLE ENERGY LABORATORY 

DRY COOLING OPTION 

ADDENDUM TO: CSP PARABOLIC TROUGH PLANT COST ASSESSMENT 

Disclaimer 

This report has been prepared for the National Renewable Energy Laboratory, and is 

subject to and issued in accordance with the agreement between National Renewable 

Energy Laboratory and WorleyParsons Group, Inc. WorleyParsons Group Inc. accepts 

no liability or responsibility whatsoever for it in respect of any use of or reliance upon 

this report by any third party. 

PROJECT 59002501 ­

REV DESCRIPTION ORIG REVIEW WORLEYPARSONS 

APPROVAL 

DATE CLIENT 

APPROVAL 

DATE 

B Issued for Final DR 

D.Ross 

RB 

R.Bowers 

GMA 

G.Aron 

12-14-09 N/A 

74
TABLE OF CONTENTS 

1. SUMMARY............................................................................................................................3
 

2. PROJECT DESCRIPTION....................................................................................................4
 

2.1 Mechanical System Descriptions .............................................................................4
 

2.2 Electrical System Descriptions...............................................................................18
 

2.3 Instrumentation and Control System Descriptions.................................................22
 

2.4 Civil Sitework Descriptions.....................................................................................22
 

2.5 Structural Support and Foundation Descriptions ...................................................22
 

3. COST ESTIMATE BASIS...................................................................................................24
 

3.1 Quantity Development ...........................................................................................24
 

3.2 Material and Equipment Pricing .............................................................................24
 

3.3 Construction Labor.................................................................................................25
 

3.4 Clarifications...........................................................................................................26
 

3.5 Exclusions ..............................................................................................................28
 

APPENDICES 

Appendix A – Capital Cost Estimate Summary 

Appendix B – O&M Cost Estimate Summary 

TOC 

75
LIST OF ACRONYMES 

ACC – air cooled condenser 

BOP – balance of plant 

CSP – concentrating solar power 

DCS – distributed control system 

EPC – engineer-procure-construct 

EPCM – engineer-procure-construction manage 

hp - horsepower 

HP – high pressure 

HTF – heat transfer fluid 

kMT – kilometric tons 

kV - kilovolt 

kW – kilowatt 

LP – low pressure 

MVA – megavolt amps 

MWe – megawatt electric 

MWth – megawatt thermal 

MCC – motor control center 

MTO – material take off 

NREL – National Renewable Energy Laboratory 

P&ID – process and instrumentation diagram 

PDC – power distribution center 

SAM – Solar Advisor Model 

SCA – solar collector assembly 

SSG – solar steam generator 

STG – steam turbine generator 

TES – thermal energy storage 

LIST OF TABLES AND FIGURES 

Figure 1 – Power block general arrangement sketch 

Figure 2 – Solar field general arrangement sketch 

Figure 3 – Process flow diagram 

Figure 4 – Water balance, design case 

Figure 5 – Water balance, annual average case 

i 

76
Figure 6 – Water balance, winter average case 

Figure 7 – Electrical one-line diagram, Sheet 1 

Figure 8 – Electrical one-line diagram, Sheet 2 

Table 1 – Major mechanical equipment additions to base case 

Table 2 – Major mechanical equipment deletions from base case 

Table 3 – Heat balance output summary 

Table 4 – Major electrical equipment modifications to base case 

ii 

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1. SUMMARY 

The purpose of this alternative design, which utilizes an air cooled condenser (ACC) in lieu of a wet 

cooling tower, is to provide the solar power industry with an alternative to the wet cooled plant (also 

referred to as “base case”). The majority of solar power plants will be located in geographical regions 

that have previously adjudicated water or where water is scarce and/or poor quality. 

This report acts as an addendum to the formerly issued “CSP Parabolic Trough Plant Cost 

Assessment” (also referred to as “base report”). which presented a complete description and cost 

estimate summary for a 103MWe wet cooled parabolic trough plant with 6.3 hours of thermal energy 

storage (TES). This report only covers the changes to the base case design and identifies all 

constants between the two. The cost summary presented herein, however, is the same level of detail 

as provided in the base report. The National Renewable Energy Laboratory (NREL) intends to update 

the cost output portion of their Solar Advisor Model (SAM) using the results of this study. All costs 

found by this study are based on a conceptual engineering effort prepared at a high-level, consistent 

with the intended purpose and confidence of a Level 2 (+/-30%) cost estimate. 

The alternative dry cooled case will hold plant net power to the grid (103MWe) and available TES 

hours of dispatch (6.3 hrs) at design conditions (i.e. TES, heat transfer fluid, Rankine cycle, and 

supporting systems operating simultaneously at full load). To achieve the same net output as the wet 

cooled plant, the steam turbine generator (STG) must now generate 120.5MWe due to the increase in 

plant parasitic power. The dry cooled plant requires an additional 6 acres (24,281 m2

) or 

approximately 1024 acres (4,143,998 m2

) altogether. The solar collector field and power block areas 

increased by a combined 58 acres (234,718 m2

) and the evaporation ponds decreased by 52 acres 

(210,437 m2

), resulting in the net overall footprint increase. Reference site characteristics remain 

constant from the base plant design. The primary advantage of dry cooling is water savings. Based 

on the findings of this study and the base case, dry cooling can save over 13 times the annual water 

consumption over wet cooling, provided the assumptions effecting water consumption are in place. 

As in the wet cooled baseline work, this study should be viewed as a high-level assessment with the 

understanding that site specific information along with more research, optimization, detailed 

engineering and capital cost estimating is required in order to arrive at an optimal concentrating solar 

power (CSP) parabolic trough plant design that meets the Owner’s needs. Owner’s costs (i.e. land, 

permitting, Owner’s engineer, risk, loan interest etc.) are excluded from this estimate and will be 

defined as a user input in SAM. 

Total installed capital cost for the dry cooled option is $1.097 billion with a +/-30% confidence, an 

increase of roughly $81 million from the wet cooled plant base design. Annual operation and 

maintenance costs are $11.8 million (1.07% of total installed cost). The plant is designed with an 

expected life of 30 years with daily startup and shutdown cycling. Refer to Appendix A and B for 

further cost details. 

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2. PROJECT DESCRIPTION 

All included subsections provide a brief description of the major cost elements impacted by the 

change in cooling methods. Description of the cost estimating process is discussed later in Section 3. 

The same site characteristics and ambient conditions discussed in Section 2 of the base report are 

also used in designing the dry cooled plant. 

2.1 Mechanical System Descriptions 

The established design approach of holding net output and thermal storage dispatch capacity requires 

significant equipment and bulk commodity changes to the wet cooled plant in all thermal systems 

discussed in the base report. Rankine cycle (also referred to as “steam cycle”) and balance of plant 

(BOP) systems involve new types of cooling equipment for steam condensation and auxiliary cooling. 

In the Rankine cycle, the air cooled condenser replaces the circulating water system and steam 

surface condenser. Although the dry cooled plant design has less cooling equipment items, the 

conceptual power block layout (Figure 1) utilizes over 3 acres (12,140 m2

) of additional power block 

area to accommodate the large ACC. A wet cooled plant condenses the turbine exhaust steam on the 

surface condenser tubes, which reject this heat to the circulating water system to atmosphere via 

evaporation in the cooling tower. Because water has a much higher heat transfer coefficient (W/m2

­

°K) than air, forced convective heat transfer with water allows for a much smaller heat transfer surface 

area and therefore a smaller condenser is needed. The ACC requires significantly more air flow than 

the wet cooling tower; consequently its fans consume more plant auxiliary power than the wet cooling 

tower fans and circulating water pumps combined. On the whole, the dry cooled plant design point 

auxiliary load is 17.6MWe, approximately 2.6MWe greater than the wet cooled plant. As a result, a 

larger steam turbine generator is necessary to maintain the net power output to the grid provided by 

the base case. 

Furthermore, wet cooled plant heat rejection is evaporative and is governed by ambient wet bulb 

temperature. Dry cooled plant heat rejection is sensible and governed by ambient dry bulb 

temperature, which is always higher than the wet bulb, and thus the achievable turbine back pressure 

is always higher with dry cooling than wet cooling. Consequently, the design point Rankine cycle 

efficiency drops from 37.4% (wet) to 35.4% (dry), further increasing the required heat input to maintain 

103MWe net capacity. 

The increase in steam cycle heat input constitutes an increase in the solar thermal collection field and 

heat transfer fluid (HTF) system. The thermal energy storage system also grows in capacity (from 

1988MWth-hrs to 2144MWth-hrs) due to the decline in steam cycle efficiency. Unlike added/deleted 

equipment to the Rankine and BOP systems, all three aforementioned systems maintain the same 

types of equipment. These changes are further discussed later in this section. 

A brief description of the major mechanical changes from the wet cooled base design to the dry 

cooled option is discussed throughout this section. The tables below list the major mechanical 

equipment added to and deleted from the base wet cooled plant, which constitutes the dry cooled 

option. All major mechanical equipment listed in Table 4 of the base report, but not shown here, are 

included in the dry cooled plant design. Mechanical equipment size and configuration modifications to 

common wet/dry plant designs are discussed later in this section. 

Bulk mechanical components such as valves, piping, fasteners, etc. are not listed, but are included in 

the cost estimate. Further supporting sketches, flow diagrams, lists, tables, and figures are provided 

to better illustrate the design basis of the cost estimate. Other significant cost items impacted by the 

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dry cooling design include civil, structural, electrical, and controls; also discussed later in this

addendum.

Table 1. Dry cooled plant major mechanical equipment additions to the base wet cooled plant.

Equipment Name Qty

Air Cooled Condenser 1x100%

Condensate Tank 1x100%

Wet Surface Air Cooler (WSAC) – Aux Cooling 1x100%

Air Cooled Heat Exchanger (Fin-Fan Cooler) – Aux Cooling 1x100%

Wastewater Sump Blowdown Booster (to evap ponds) 2x100%

WSAC Makeup Tank (field erected) 1x100%

WSAC Chemical Feed/Storage System** Lot

**No designated enclosure is necessary. Equipment will be located in the water treatment building adjacent to the WSAC.

Table 2. Dry cooled plant major mechanical equipment deletions from the base wet cooled plant.

Equipment Name Qty

Cooling Tower 1x100%

Steam Surface Condenser 1x100%

Closed Cooling Water Heat Exchangers 2x100%

Circulating Water Pumps 2x100%

Aux Cooling Water (backup/startup) 1x100%

Cooling Tower Blowdown Booster Pumps (circ water header to evap ponds) 2x100%

Cooling Tower Chemical Feed/Storage Enclosure 1

Figure 1 below represents a conceptual layout of the major equipment within the power block for the

dry cooled option. Equipment sizes are based on vendor information, past project archives, or

engineering judgment/estimates. Equipment arrangement aims to provide a functional layout which

meets plant operation and maintenance needs.

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Figure 1. Dry cooled option reference plant conceptual power block general arrangement layout.

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2.1.1 Solar Thermal Collection Field

The less-efficient dry cooled Rankine cycle requires more heat input from the solar field than needed

in the wet cooled design to maintain net power to the grid. Additionally, the dry cooled plant auxiliary

power requirements are greater, which increases design STG output over the base case. The

combination of these conditions requires a larger solar collector field. Specifically, the dry cooled plant

requires 92 additional solar collector assemblies (SCA) which translates to 23 additional collector

loops having 4 SCAs per loop. The same collector type and configuration assumed in the base design

is used in the dry cooling option design.

In total, the dry cooled option solar field has 1,062,750 m2of effective aperture mirror area which can

simultaneously and independently provide energy to the steam cycle and TES system via a common

HTF system. The solar field size assumes a solar multiple of 2.0, which was independently optimized

by NREL specifically for this reference plant. Both wet and dry plants maintain the same solar

multiple.

Additional collectors constitute additional commodities such as grading, roadwork, fencing, piping,

insulation, pipe supports, cable, control input/output contacts, and other additions or modifications to

the base design. These additional commodities are included in the cost estimate.

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Figure 2. Dry cooled option plant conceptual solar field general arrangement layout.

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2.1.2 Heat Transfer Fluid System

The dry cooled solar collector field remains divided into 6 sections, as in the base case, and therefore

maintains the same HTF pipe header lengths which supply fluid from the pumps to the loop headers

at the inlet of each section (see Figure 2 above). However, additional SCAs will require new loop

supply/return header piping which requires larger diameter header piping throughout the entire HTF

piping network. The HTF volume of the larger system is 1.157 million gallons (4.38 million liters) at

100°F. As a result, larger HTF circulation pumps are needed. The base case HTF expansion tank

system, however, has enough available capacity with its single expansion tank and six overflow tanks

to accommodate the dry cooled design.

Due to physical and performance limitations of HTF pumps, five (5) 25% capacity centrifugal type

circulation pumps driven by 3000 hp motors (with variable speed drives) are required in the dry

cooled design. The wet cooled design required four (4) 33% capacity 4000 hp pumps. In comparison,

the wet cooled plant’s HTF pumps (at design conditions) consume 7.86MWe of auxiliary power while

the dry cooled plant’s HTF pumps consume 8.40MWe.

No significant changes to the HTF ullage, freeze protection and nitrogen systems were necessary and

therefore no changes were made at this preliminary design level.

2.1.3 Power Cycle

Figure 3 below illustrates the dry cooled power cycle in more detail and includes high-level thermal

storage and water treatment processes.

Conceptual Rankine cycle heat balances were modeled using General Electric’s GateCycleTM

software at three ambient conditions. The design case sets all equipment sizes based on peak

ambient weather data as previously described. In addition, two off-design cases are modeled for

winter and annual average ambient conditions at 100% solar heat input to the steam cycle.

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Table 3. Heat balance output summary for dry cooled option. Not all model outputs are shown.

Description Design Case Winter

Average

Annual

Average

DB Temperature (°F / °C) 108.0 / 42.2 58.9 / 14.9 81.5 / 27.5 Ambient Conditions Relative Humidity (%) 17 29 23

System Performance Gross Power Output (kW) 120,483 127,592 127,093

Flow (lb/hr / kg/min)

11,061,541 /

83,624

11,061,541 /

83,624

11,061,541

HTF to SSGs / 83,624

Temp (°F / °C) 740 / 393.3 740 / 393.3 740 / 393.3

Flow (lb/hr / kg/min)

1,135,687 /

8,585

1,135,654 /

8,585

1,135,655 /

8,585

Temp (°F / °C) 700 / 371 700 / 371 700 / 371

Press (psia / bar) 1,325 / 91.4 1,325 / 91.4 1,325 / 91.4

HP Steam to STG

Enthalpy (BTU/lb) 1,301 1,301 1,301

Flow (lb/hr / kg/min)

984,205 /

7,440

983,968 /

7,439

983,985 /

7,439

Temp (°F / °C) 700 / 371 700 / 371 700 / 371

Press (psia / bar) 362 / 25 362 / 25 362 / 25

HRH Steam to STG

Enthalpy (BTU/lb) 1365 1365 1365

Flow (lb/hr / kg/min)

808,477 /

6,112

783,270 /

5,921

787,142 /

5,951

Temp (°F / °C) 133 / 56.1 102 / 38.9 107 / 40.6

Press (psia / bar)

2.41 /

0.166

1.02 /

0.0703

1.18 /

0.0814

From Condenser

Hotwell

Enthalpy (BTU/lb) 100.9 70.5 75.4

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Figure 3. Dry cooled plant process flow diagram of primary thermodynamic systems.

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WATE R BAL ANCE

Water balance calculation results for the three heat balance cases are shown in Figures 4 to 6 below.

The water balance is representative of simultaneous operating consumers at full turbine output for a

given ambient condition. Intermittent and emergency users (firewater, hose streams, safety showers, etc.)

are not running during normal operation and are therefore excluded from the water balance. Mirror wash

water consumption is shown coincident to Rankine cycle operation for clarity, although it will more

frequently be performed off-line.

With an air cooled condenser, no cooling tower makeup water is needed to replace the evaporated

cooling water as in the wet cooled design. Therefore, the dry cooled plant has significantly less water

consumption with its primary consumer being the demineralized water users (steam cycle and mirror

washing). At design operating conditions, approximately 91% of the incoming raw water is treated by

reverse osmosis (RO); the other 9% is used as miscellaneous domestic water and blowdown quench

water in the steam cycle. About 22% of the RO feed is rejected to the evaporation ponds. Approximately

11% of the RO product is used as WSAC makeup, the remainder is sent to the electrostatic deionization

system to produce demineralized water. Altogether plant demineralized water accounts for ~64% of the

plant’s total water consumption at design point (not representative of annual consumption).

The base case wet cooled plant is estimated to consume 1241 acre-feet/year of raw water for operational

use during a typical year. In contrast, for the same net power out, the dry cooled plant is estimated to

consume 90 Acre-feet/year, about 7% of the wet cooled plant consumption. Below is a breakdown of raw

water consumers for each cooling case.

Wet Cooled

• 1165 acre-feet/year, cooling tower make-up

• 23 acre-feet/year, blowdown quench & steam cycle make-up

• 13 acre-feet/year, steam cycle make-up (during plant startup)

• 40 acre-feet/year, mirror washing

Dry Cooled

• 3 acre-feet/year, WSAC make-up

• 24 acre-feet/year, blowdown quench & steam cycle make-up

• 19 acre-feet/year, steam cycle make-up (during plant startup)

• 44 acre-feet/year, mirror washing

Due to the slightly larger steam flow in the dry cooled plant, respective increases in blowdown quench

and steam cycle make-up water result. Mirror wash water consumption also slightly increases due to the

larger solar field of the dry cooled plant. No economic conclusions are provided in this study as initial and

operating costs are heavily dependent on available water quality and quantity specific to the plant site.

Likewise, no pre or post water treatment systems are included in the cost estimate.

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Figure 4. Dry cooled plant design case water balance at 108°F (42.2°C) DB and 71.3°F (21.8°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes.

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Figure 5. Dry cooled plant annual average case water balance at 81.5°F (27.5°C) DB and 58.1°F (14.5°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes.

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Figure 6. Dry cooled plant winter average case water balance at 58.9°F (14.9°C) DB and 44.4°F (6.9°C) WB ambient temperatures. Diagram is high-level and not inclusive of all water system processes.

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RANKINE EQUIPMENT

The dry cooled plant uses the same two full capacity centrifugal-type ring section multistage

feedwater pumps, however, with an increase in motor size from 3000 hp (wet) to 3500 hp (dry).

While the connected available motor power is 500 hp greater, the peak operating load is only

200hp (149 kW) greater. The larger feedwater pumps are needed to accommodate the increase

in steam flow through the larger steam turbine. Similarly, condensate pumps have no change in

pump type or configuration. Although they maintain 350 hp connected motor size from the wet to

dry plant design, they require an additional 30 hp (22 kW) at peak operation.

The dry cooled Rankine cycle steam flow is not a large enough increase to warrant any physical

changes in quantity or configuration of the solar steam generator (SSG) equipment. The increase

in shell and tube dimensions will be insignificant and was not determined at this preliminary

design level. Therefore the general arrangement drawing shows no physical change in sizes for

the solar steam generators; however, costs have been adjusted appropriately.

An alternative reheat STG was selected for the dry cooled plant power block equipment layout,

capable of up to 150MWe, has a single flow LP section with last stage blades designed for dry

condensing. Unlike the industrial-scale unit used in the wet cooled base design, the utility-scale

turbine locates its generator at the end of the turbine train where it directly couples with the

common HP/LP shaft. No speed reduction gear box is needed with this larger steam turbine.

Since the HP turbine operates at lower speeds than the wet-cooled machine, the dry-cooled

turbine is able to set both HP and LP turbines on a single shaft at 3600 rpm (generator speed).

This arrangement is typical of most utility-scale steam turbines and offers easier access to the

generator rotor for removal during heavy maintenance activity.

The scope of supply is nearly the same for both machines. The only difference is the type of

enclosures provided in each supplier’s base scope; taking into account that specific enclosure

specifications can be requested at the buyer’s expense. The dry-cooled turbine selected for this

study provides an enclosure for its generator, oil conditioning equipment, and excitation room;

whereas the wet-cooled unit encloses the full turbine train (turbines and generator) but includes

no covering for its oil conditioning equipment.

One supplier is not necessarily better suited than the other for dry-cooling. Use of the selected

turbine for the dry-cooled plant is fully based on the amount of equipment information available at

the time of the study.

AI R COOLED CONDENSER

The dry cooled alternative equipment includes a self-contained 25-cell air cooled condenser

having 5 cells in each of its 5 bays and an initial temperature difference (ITD) of Δ25°F at design 

conditions. ITD is defined as the difference between ambient dry bulb temperature and steam

saturation temperature at the turbine exhaust. The ACC size is driven by the selected ITD which

was optimized for this study based on a high level cost and performance analysis between solar

field size, ACC cost, parasitic load and net power output to the grid. An ACC designed with a

Δ25°F ITD at a design ambient dry bulb temperature of 108°F (42.2°C) corresponds to a 133°F 

saturation temperature and respective 2.41 psia (0.1662 bar) turbine back pressure.

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Exhaust steam exits the LP turbine through the main exhaust duct, a carbon steel duct

measuring 178-inches (4.52 meters) in diameter. The main duct length is minimized to the

greatest extent possible in order to mitigate performance-inhibiting pressure losses that have a

significant impact on turbine efficiency. A drip-leg is provided in the exhaust duct to collect the

condensate in the exhaust steam (i.e. exhaust steam quality is less than 100%). This main

exhaust duct supplies saturated steam to the perpendicular “streets” (rows of bays) at the top of

the tower. Ambient air is forced vertically through the 116-foot (35.4-meter) tall tower with twenty

five (25) fans 36-feet (~11 meter) in diameter. Each fan is driven by a single-speed 200 hp motor

which requires speed reduction via a parallel shaft gear train. Altogether the ACC utilizes 3,570

kWe at design conditions.

Through forced convection heat transfer the saturated steam condenses as it gravitationally

drops down the aluminum-finned tubes arranged in an “A” shape. Condensate collects in the

condensate tank (typically supplied by the ACC manufacturer) located beneath the ACC tower.

Condensate pumps forward the condensate through the low pressure feedwater heaters and into

the deaerator (refer to Figure 3).

2.1.4 Thermal Energy Storage

Higher STG output and lower thermal-to-electric efficiency in the dry cooled plant requires an

additional 156 MWth-hrs of TES capacity to meet 6.3 hours provided in the base plant design.

This larger TES system will store up to 2144 MWth-hrs of thermal energy versus the 1988 MWthhrs stored in the wet cooled design; the salt mass therefore increases from 62kMT to 66.8kMT.

The storage tanks are assumed to slightly increase in height to accommodate the larger salt

mass. TES pumps are assumed to have no change in quantity or motor size but to have a slight

linear increase in operating electric load based on the increased charge and discharge rates. The

quantity of oil-to-salt heat exchangers per module increases from 3 to 4, totaling 8 for the entire

TES system. This quantity increase is based on WorleyParsons’ past project archive with larger

TES systems and their impact on heat exchanger configuration.

2.1.5 Balance of Plant

Changing from wet to dry cooling yields small changes to the balance of plant mechanical

systems, with the exception of auxiliary cooling later discussed. Major BOP systems not changed

in the alternative condensing design include: fire protection, drains, demineralized water, potable

water, sanitary drains, fuel gas, and compressed air. Refer to the base report for a brief

description of these systems. BOP systems affected by the alternate design are discussed below.

AUX ILI ARY COOLI NG

For an ACC facility, the traditional ultimate heat sink (wet tower) for the Closed Cooling Water

(CCW) system is no longer available. An addition of a new heat sink must be added to the

design. The dry cooled plant’s CCW heat exchangers are replaced with either an air cooled heat

exchanger (fin-fan cooler) or a combination of a fin-fan and a wet surface air cooler (WSAC) as a

source to cool the CCW. In climates cooler than the Mojave Desert, a stand alone fin-fan cooler

is sufficient to handle all auxiliary cooling loads and provide cooling water at temperatures

meeting equipment requirements. Since Daggett typically experiences high dry bulb

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temperatures, the fin-fan cooler would be unable to meet the strict cooling water temperatures

required by the STG lube oil cooler and sample panel cooler (and possibly other equipment

coolers). Therefore a WSAC, which uses evaporative cooling, is added in series with the fin-fan

cooler and will operate when the ambient dry bulb temperature exceeds 85°F (29.4°C). The

WSAC cooler is sized to handle auxiliary cooling loads that require a maximum of ~100°F cooling

water at all times. At high ambient temperatures, the WSAC is used to further cool the CCW

coming from the fin-fan to satisfy the STG lube oil cooler, sample panel cooler and any other

cooling loads that require <100°F cooling water. This arrangement minimizes water consumption.

The CCW expansion tank and CCW pumps are still needed in the dry plant design; however the

auxiliary cooling water pump and plate-and-frame heat exchangers are no longer applicable. The

WSAC requires its own set of relatively small cooling water pumps to circulate the water that is

evaporated.

AUX ILI ARY STE AM

A natural gas fired auxiliary boiler is needed in the dry cooled design and serves the same

auxiliary steam hosts as in the wet cooled plant; HTF freeze protection, hogging and holding air

ejectors, gland steam for turbine seals, and sparging steam for startup. In the base design the

boiler size was dictated by a 12 MMBtu/hr HTF freeze protection duty. Because the ACC holds

much more volume than the surface condenser, the hogging steam flow needed to initiate

vacuum conditions nearly doubled, .Consequently, the auxiliary boiler size increases to 18

MMBtu/hr.

BLOW DOW N

The same steam cycle blowdown process applies to the dry cooled Rankine cycle. The only

difference is the condensed blowdown wastewater is sent to a wastewater sump rather than the

cooling tower basin. This wastewater sump also collects WSAC blowdown and water treatment

reject streams. Sump pumps forward all wastewater to onsite evaporation ponds.

RAW WATE R

Well water forwarding pumps remain as three (3) by 50% capacity centrifugal type pumps but

have a decreased motor size from 250 hp (wet) to 75 hp (dry). The underground supply pipeline

decreases from 10-inch to 3-inch high density polyethylene (HDPE) plastic pipe. There is no

change in well location, size, and configuration assumptions.

The field-erected carbon steel raw water storage tank is sized to provide 14 hours of blowdown

quench, demineralized water, and service water usage. A dedicated reserve of firewater is also

stored in the tank providing 360,000 gallons (1,362,748 liters) or 2 hours at 3000 gpm (189

liters/sec). Service water pumps are identical in size and service between the wet and dry

designs.

2.2 Electrical System Descriptions

All high voltage electrical equipment is unchanged. The same generator step-up transformer and

switchyard can be used in the dry cooled plant. The changes in electrical systems are primarily

seen at the medium (4160V) and low (480V) voltage levels. The solar field power distribution

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design and its equipment are largely unchanged from the base design except a linear increase in

power cable feeding the SCA drives.

Below is a list of the major electrical equipment modifications from the base plant design. Bulk

electrical materials such as cable, connectors, panel boards etc. are not listed at this design

level, but are included in the cost estimate.

Table 4. Dry cooled plant major electrical equipment modifications to the base plant design.

EQUIPMENT NAME QTY

Station Service Transformers 9

Solar Collector Drive Power Converters 1300

Power Distribution Center (PDC1A) with Switchgear and Motor Control

Centers (MCC) - TES Area

1

Power Distribution Center (PDC2A) with Switchgear and Motor Control

Centers (MCC) - STG & Solar Field Areas

1

Power Distribution Center (PDC2B) with Switchgear and Motor Control

Centers (MCC) – ACC & HTF Areas

1

The two auxiliary transformers slightly increase to 19/25/31 MVA to accommodate the larger

parasitic load required by the added ACC fans and larger HTF pumps. There will be three power

distribution centers (PDC) containing the switchgear and MCC equipment supplying 480V and

4160V power to the end users. No change in essential service loads and therefore no change in

diesel generator size.

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Figure 7. Conceptual electrical one-line diagram including all 4160 V connected equipment. Sheet 1.

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Figure 8. Conceptual electrical one-line diagram including all 4160 V connected equipment. Sheet 2.

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2.3 Instrumentation and Control System Descriptions

The power block distributed control system (DCS) remains unchanged.

Solar field control system design is unchanged from the base design with the exception of

increased control cable and I/O quantities for the increased number of SCA drives.

2.4 Civil Sitework Descriptions

2.4.1 Roads, Parking, and Fencing

The base design remains largely unchanged with only a small increase in roads and fencing

lengths due to the larger solar field.

2.4.2 Bioremediation / Land Farm Area

The base design remains unchanged.

2.4.3 Site Preparation, Earthwork, and Improvements

The base design remains largely unchanged with only a small increase due to the larger solar

field.

2.4.4 Onsite Drainage, Detention, and Evaporation Ponds

The base design concept remains unchanged. Evaporation ponds decrease from a total of 60

acres to 6 acres due to the absence of cooling tower blowdown.

2.4.5 Thermal Storage Salt Containment Berm

The base design remains unchanged.

2.5 Structural Support and Foundation Descriptions

2.5.1 Solar Field Structures and Foundations

The base design remains unchanged, with the only increase due to longer HTF pipe runs for the

larger solar field.

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2.5.2 Power Block Structures and Foundations

The base design BOP structures/foundations remain largely unchanged, with the exception of

added WSAC, fin-fan, and WSAC make-up tank foundations. The cooling tower basin has been

deleted and ACC support piers added.

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3. COST ESTIMATE BASIS

The estimate is based on an Engineer – Procure – Construction Management (EPCM) approach.

Engineering and Design, Construction Management, and Start-up & Commissioning costs are

included.

Material Take-off (MTO) and Design Allowances are included in the estimate and are intended to

compensate for the degree of engineering that is incomplete. This is not a contingency; rather it

is a minor allowance included to cover the nominal quantity growth which inevitably occurs as the

design is further developed.

Contractor mark-up on bulk materials reflects the mark-up that contractors will apply to bulk

materials provided under their respective contracts. A rate of 5% is used for these materials.

This has been reduced from the more typical rate of 8% to account for the “engineered bulks”,

including most of the piping being supplied by the EPCM contractor and thus not being subject to

a mark-up..

The estimate excludes escalation. All costs are presented as overnight 2nd Quarter 2009

dollars.

Project Contingency addresses unforeseen elements of costs within the current defined project

scope. It is expected that by the end of the project the entire contingency will be spent on either

direct or indirect costs. The contingency is applied as follows, 5% on equipment, 10% on bulk

material, 10% on installation labor for the solar field and 15% on the balance of installation labor,

and 0% on professional services.

3.1 Quantity Development

Equipment quantities for major equipment components are based on preliminary engineering

provided in drawings, flow diagrams, process and instrumentation diagrams (P&ID’s), equipment

lists, and electric one-line diagrams. Major piping networks such as HTF, steam, feedwater,

condensate, and firewater were conceptually laid out and specified on P&ID’s.

Minor balance of plant equipment not included in the project design documents are based on

similar plant designs previously developed by WorleyParsons. Examples of minor balance of

plant equipment include steam turbine gland steam seal system, condenser air removal system,

service air system, steam / water sampling system, and compressed air systems. Bulk material

quantities were developed for select major systems based on conceptual routings and sizing

where available. Quantities for the balance of plant systems were developed by scaling from a

similarly sized plant to meet specific NREL site requirements.

3.2 Material and Equipment Pricing

All applicable vendor quotes obtained in the wet cooled plant estimate were used in the dry

cooled plant and appropriately scaled if necessary. The following equipment costs are based on

budgetary quotes specifically obtained for the dry cooled plant:

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o Steam turbine generator, gland steam condenser, and lube oil skid

o Air Cooled Condenser

o Fin-fan cooler

o Wet surface air cooler

Remaining equipment costs are based on WorleyParsons cost estimating database, adjusted to

2Q2009 dollars. The bulk material costs are based on recent pricing for similar materials from the

WorleyParsons estimating database, adjusted to 2Q2009 dollars. Most of the equipment and

materials will be transported by truck to the project site.

3.3 Construction Labor

Overall construction labor costs include wage rates, installation hours, labor productivity, labor

availability and construction indirect costs.

3.3.1 Wage Rates

Union shop wage rates are based on the 2009 RS Means Labor Rates for the Construction

Industry. Rates are based on Riverside, CA and are valid to 2Q 2009.

3.3.2 Installation Hours

WorleyParsons maintains a database of standard unit installation hours. The database

represents standard installation rates for US Gulf Coast Merit Shop. Equipment setting manhours were developed by evaluating estimated weights, equipment size, and number of

components in conjunction with crew sizes and approximated time. Bulk material man-hours are

based on standard unit installation rates. The resultant hours are further adjusted for productivity

(described below).

3.3.3 Labor Productivity

The estimate reflects productivity for the Daggett, CA area. In evaluating productivity, factors

such as jobsite location, type of work (i.e. new construction) and site size are considered. Labor

productivity factors (multipliers over US Gulf Coast Merit Shop) have been included to reflect

anticipated site specific labor productivity. A productivity factor of 1.2 was applied to the USGC

labor hours, with the exception of the SCA assembly work performed in the on-site fabrication

structure and the hours associated with salt melting. No productivity adjustment was applied to

furnish and erect quotes obtained specifically for this project.

3.3.4 Labor Availability

Labor is based on a 50-hour work-week (5-10s). The estimate includes an allowance of $60/day

for travel and per diem. No additional incentives have been included to attract or retain craft

labor. The estimate is based on an adequate supply of qualified craft personnel being available to

staff this project.

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3.3.5 Construction Indirect Costs

In addition to base wage rates and fringe benefits, labor costs include construction indirect costs

consisting of:

o Payroll taxes and insurances

o Contractor’s General Liability insurance

o Construction supervision

o Indirect craft labor

o Temporary facilities

o Field office

o Small tools & consumables

o Material handling

o Safety / incentives

o Mobilization / demobilization

o Premium time portion of extended work week

o Craft bussing within the construction site

o Construction rental equipment

o Fuel, oil & maintenance for construction equipment

o Contractor’s overhead and profit (on labor-related costs)

3.4 Clarifications

3.4.1 Civil / Structural

o The site is relatively flat. No underground obstructions, rock formations, or unusual

site conditions exist.

o All grading will be balanced across the site.

o Earthwork (rough grading) is based on 1 ft of earth movement over the entire solar

field site.

o Site geography is assumed to have an average slope between 1% and 2% and can

be graded with conventional equipment.

o Topsoil removal is not required. The topsoil will be scarified and compacted.

o Approximately 1024 acres (4,143,980 m2) of land will be cleared and grubbed. Desert

vegetation (shrubs, etc.) covers the entire site.

o Dewatering is not required.

o The power block and access roads will be paved (asphalt or gravel). The solar field

roads will be compacted native soil (proof rolled).

o Soil binder/stabilizer is not included for dust control at solar field roads.

o The entire site will be fenced with 8 foot (2.4 m) high chain link fencing with barbed

wire.

o The evaporation ponds will have a double HDPE liner. A leak detection system is

included.

o The detention pond will be unlined with a compacted native soil bottom.

o The soil under the bio-remediation area will be lime treated.

o Concrete foundations are based on 4000 psi concrete. Piles are not required.

o Concrete foundations are included for all equipment and buildings.

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o The steam turbine and ancillary equipment will be outdoors.

o Warehouse & maintenance, water treatment, administration, and cooling tower

chemical feed/storage buildings are included.

o A fabrication tent for the solar array structure assembly is included.

o Sanitary waste will not be piped offsite; rather it will run through a septic tank and run

through an onsite leach field.

3.4.2 Mechanical / Piping

o The goal is to meet 103 MWe net and 6.3 hours of TES as provided in the wet cooled

base case. The solar field and TES systems were increased to meet this goal.

o The thermal energy storage system is a completely installed, tested and

commissioned turnkey EPC cost from a vendor, with the exception of the salt melting

process.

o The salt fill will be delivered in one-tonne supersacs. Salt melting equipment and

labor are included. Salt blending is not required, therefore, it is excluded.

o The solar collector field is laid out in a square-shaped array with a central power

block to minimize HTF pumping loads.

o Blowdown will be discharged to three on-site evaporation ponds.

o Stress relieving for piping is included as required by code.

o Underground steel pipe is coated and wrapped.

o Expansion loops for the HTF piping are included.

o Water supply will be provided by three water wells. Electric well pump power is not

included in the plant’s auxiliary power load and will be purchased directly from the

utility having jurisdiction.

o Water quality information is unknown and therefore no pre or post water treatment is

included.

o A natural gas pipeline with adequate pressure is assumed to be available within

reasonable proximity for plant interconnection (i.e. no onsite natural gas compression

or propane storage is needed).

o SCA costs are estimated from individual component costs (mirror, structure, and

receiver). Continuing changes in the industry appear to be resulting in a lower SCA

cost than derived at the time of this cost estimate.

o An empirical sun-tracker using a shadowed PV plate concept is included on all

SCAs. These are typically not needed if the drives have pre-programmed tracking

logic built-in. The empirical tracker is included for redundancy per NREL’s direction.

o A wind fence is excluded.

o Fire protection equipment is excluded from the solar field. Only power block

equipment is protected.

3.4.3 Electrical / Instrumentation

o A 13.8kV-230kV generator step-up transformer is included.

o An on-site switchyard with 230kV main circuit breaker and main disconnect switches

are included.

o No transmission lines beyond the switchyard are included.

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o The estimate includes auxiliary transformers, station service transformers, and solar

field transformers.

o SCA drive power converters are included.

o PDC buildings and equipment are included.

o Underground duct bank is included.

o Cathodic protection is included for underground piping.

3.4.4 Other

o Engineering work assumes that the selected site is void of all fatal-flaws which could

significantly impact project cost and schedule. These flaws include, but are not

limited to: habitat and locations of threatened-endangered and sensitive species,

abundance of other protected (e.g., native) species, distribution of noxious weeds,

areas of critical wildlife habitats and movement corridors, contaminated soil or

hazardous materials, archaeological artefacts, distribution and significance of cultural

resources, Native American Tribal concerns, recreational areas, special land use

designations (e.g., BLM Areas of Environmental Concern), and others.

o Utility transmissions such as natural gas and supply water are included (excluding

electric transmission) up to 200 feet off the furthest site boundary.

3.5 Exclusions

As discussed above, the scope of the estimates is generally limited to scope within the

project fence. A list of items excluded from the estimate is as follows:

o Demolition and removal of existing structures

o Import duties & tariffs

o Extraordinary noise mitigation or attenuation

o Owner’s Costs

o Allowance for funds used during construction

o All taxes with the exception of payroll taxes

o All offsite infrastructure costs

o Upgrades to existing rail spur to accommodate delivery of large equipment

o Temporary housing and facilities for the construction workers

3.5.1 Typical Owner’s Costs

Owner’s costs are excluded from the estimate. Typical Owner’s costs include, but are

not limited to, the following:

o Permits & Licensing

o Land Acquisition / Rights of Way Costs

o Economic Development

o Project Development Costs (Geotechnical Investigation & Site Survey)

o Legal Fees

o Owner’s Engineering / Project & Construction Management Staff

o Plant Operators during start-up

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o Electricity consumed during start-up

o Fuel and Reagent consumed during start-up

o Initial Fuel & Reagent Inventory

o Transmission Interconnections & Upgrades

o Operating Spare Parts

o Financing Costs

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APPENDIX A

CAPITAL COST ESTIMATE SUMMARY

105
12/10/2009

Revision 1

ITEM QTY UNIT MATERIAL LABOR TOTAL COMMENTS

01 Site Improvements 1 LS 7,114,000 $ $ 15,723,000 $ 22,837,000

02 Solar Field 1 LS 212,135,000 $ $ 284,253,000 $ 496,388,000

03 HTF System 1 LS 53,280,000 $ $ 56,749,000 $ 110,029,000

04 Thermal Energy Storage 1 LS 202,638,000 $ $ 5,438,000 $ 208,076,000

05 Fossil Backup 1 LS $ - $ - $ -

06 Power Plant 1 LS 112,136,000 $ $ 39,057,000 $ 151,193,000

07 EPCM Costs 1 LS $ 29,001,000 Professional services

08 Project, Land, Misc. 1 LS $ - Excluded

09 %DC's Sales Tax Applies 1 LS $ - Excluded

Subtotal $ 587,303,000 $ 401,220,000 $ 1,017,524,000

Contingency $ 79,227,000

TOTAL ESTIMATE - EPCM BASIS $ 1,096,751,000

CRITICAL NOTES

1

2

3

4

5 Base plant design is wet-cooled. The goal of this alternative dry-cooled design is to fix 103 MWe net and 6.3 hours of storage. Therefore, the solar field and steam turbine

outputs increased to accommodate the larger parasitic load and lower efficiency in a dry-cooled plant.

Thermal energy storage equipment cost is based on a turnkey budgetary quote from the single commercially available salt storage vendor. An alternative cost savings

approach would be to estimate the storage system from the ground up and compile vendor quotes for each sub-component (tanks, pumps, HX, etc.)

NREL has selected a 2.0 solar multiple. The solar multiple has a significant capital cost impact and is subject to the project developer's financial model.

Cost reflects NREL's selected 150-meter trough design. This trough is the most proven design with the most utility-scale installations; however, the associated materials and

labor costs are higher than alternative emerging designs (i.e. 100-meter trough, or SkyFuel)

Labor rates are union-based for Riverside, California with a productivity factor of 1.2. Alternatively, merit-shop based labor rates can significantly reduce costs.

ESTIMATE SUMMARY

NREL Task 1 Parabolic Trough Cost Assessment

103 MW net with 6.3 hrs Thermal Storage - Dry Cooled Option

(Using Riverside, CA union labor rates)

SAM User 1

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APPENDIX B

O&M COST ESTIMATE SUMMARY

107
Project Name: CSP Trough Plant Cost Estimate - Dry Option

Project Desc: 103MWe net with 6.3hrs TES

Location: Daggett, CA

Client: National Renewable Energy Laboratory - DOE

Date: 12/07/09

Revision: B

Originator: D. Ross

Reviewer: R. Bowers

Model Inputs

Est Gas Cost $/MMBtu $6.00

Est Water Cost $/acre-ft $450

Est Auxiliary Power Cost $/kWh $0.08

Field Design

Solar Field Effective Mirror Aperture Area m

2

1,062,750

Net Plant Output to Grid MWe 103

Annual Net Power Generation MWe-hr 438,790

Total Installed Capital Cost $ $1,096,751,000

O&M Cost Breakdown

Onsite Staff $5,523,450

Utilities

Purchased Auxiliary Electricity $318,960

Natural Gas $93,834

Water $43,606

Utilities Sub-Total $456,401

Consumables $891,602

Maintenance & Repairs

Solar Field $1,047,173

HTF System $324,740

TES System $363,923

Power Block $2,369,597

Maintenance & Repairs Sub-Total $4,105,432

Chemicals & Water Treatment $87,096

Office & Administration $110,245

Training $84,925

Contract Services $394,413

Miscellaneous Cost $119,553

Total Annual O&M Cost $11,773,118

O&M Percent of Total Installed Capital Cost 1.07%

NOTES

1

2 Water consumption includes WSAC makeup, mirror washing, and steam cycle makeup.

3 Raw and waste water assume no pre or post water treatment, respectively.

4 Maintenance and repairs includes spare parts and labor.

5 Solar collector mirror washing is sub-contracted from June through Sept,

washing is done by plant staff for the remaining months.

Fixed and variable costs are based on 2nd quarter 2009 US$ projected to 2012 first operating year, based on

3% annual escalation (including inflation).

108
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1. REPORT DATE (DD-MM-YYYY)

July 2010

2. REPORT TYPE

Technical Report

3. DATES COVERED (From - To)

March 2009-April 2010

4. TITLE AND SUBTITLE

Parabolic Trough Reference Plant for Cost Modeling with the Solar 

Advisor Model (SAM)

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

C. Turchi

5d. PROJECT NUMBER

NREL/TP-550-47605

5e. TASK NUMBER

SS01.2340

5f. WORK UNIT NUMBER

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

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

8. PERFORMING ORGANIZATION

REPORT NUMBER

NREL/TP-550-47605

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S)

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13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

This report describes a component-based cost model developed for parabolic trough solar power plants. The cost 

model was developed by the National Renewable Energy Laboratory (NREL), assisted by WorleyParsons Group Inc., 

for use with NREL’s Solar Advisor Model (SAM). This report includes an overview and explanation of the model, two 

summary contract reports from WorleyParsons, and an Excel spreadsheet for use with SAM. The cost study uses a 

reference plant with a 100-MWe capacity and six hours of thermal energy storage. Wet-cooling and dry-cooling 

configurations are considered. The spreadsheet includes capital and operating cost by component to allow users to 

estimate the impact of changes in component costs. 

15. SUBJECT TERMS

CSP; parabolic trough; cost modeling; component-based; Solar Advisor Model; wet cooling; dry cooling; thermal 

energy storage; NREL; Craig Turchi; WorleyParsons; spreadsheet

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