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

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

2009 Technical Risk and 

Uncertainty Analysis of the 

U.S. Department of Energy’s 

Solar Energy Technologies 

Program Concentrating Solar 

Power and Photovoltaics R&D

Jim McVeigh, Mark Lausten, Ed Eugeni, 

and Arun Soni

Sentech Inc.

Bethesda, Maryland

Subcontract Report

NREL/SR-6A20-48043

October 2010
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

2009 Technical Risk and 

Uncertainty Analysis of the 

U.S. Department of Energy’s 

Solar Energy Technologies 

Program Concentrating Solar 

Power and Photovoltaics R&D

Jim McVeigh, Mark Lausten, Ed Eugeni, 

and Arun Soni

Sentech Inc.

Bethesda, Maryland

NREL Technical Monitor: Robert Margolis

Prepared under Subcontract No. KACX-8-88314-04

Subcontract Report

NREL/SR-6A20-48043

October 2010
This publication received minimal editorial review at NREL.

NOTICE

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iii

Executive Summary

The U.S. Department of Energy (DOE) Solar Energy Technologies Program (SETP) conducted a 

2009 Technical Risk and Uncertainty Analysis to better assess its cost goals for concentrating 

solar power (CSP) and photovoltaic (PV) systems, and to potentially rebalance its R&D 

portfolio. This report details the methodology, schedule, and results of this technical risk and 

uncertainty analysis. Technical experts were recruited by the Risk Analysis Team to provide 

estimates, in the form of probability density functions, on specific metrics such as total system 

cost (TSC) and operations and maintenance (O&M) cost. Probability is the most prevalent 

method for measuring uncertainty. The experts were asked to provide inputs for creating 

triangular probability distributions, which show the relative likelihood of any given value for a 

metric when the actual value is uncertain. More specifically, experts were asked to predict future 

values for specified target years (i.e., 2015, 2020, and 2025 for CSP; 2010, 2015, and 2020 for 

PV) and based on the following three funding scenarios: no DOE, planned DOE, and expanded 

DOE R&D funding. Once these estimates were obtained, they were aggregated in @Risk, a 

probabilistic model utilizing Latin Hypercube simulation to perform quantitative risk analysis. 

For CSP, the technologies analyzed were utility-scale parabolic troughs and power towers, both 

with six hours storage. Experts provided cost estimates including solar field ($/kilowatt or kW), 

heat transfer fluid/receiver ($/kW), thermal energy storage ($/kWht), power block and balance of 

plant ($/kW), and O&M ($/kW-yr). TSC ($/kW) was calculated from these inputs. For PV, 

experts were asked to provide inputs for the utility, commercial, and residential market sectors. 

Rather than specifying the PV technology, experts were asked to select from crystalline silicon, 

thin-film, and concentrating PV when providing their estimates. This was done so the experts 

could select a technology they believe would produce the lowest cost throughout the time frame 

examined. Experts provided estimates for TSC ($/kW), inverter lifetime (years), inverter 

replacement cost ($/kW), module cost ($/kW), and O&M ($/kW-yr). 

The results of the analyses are expressed in a number of ways, including summary statistics, 

vigntile tables (i.e., values of a metric at every 5th percentile probability from 0% to 100%), and 

fan diagrams that graph the 10th, 50th, and 90th percentiles for each funding scenario over time, 

as well as the SETP goal values. Two of the TSC fan diagrams follow to illustrate some results 

from the analysis. 

First, for CSP troughs, Figure E1 shows the Program goals (light blue line) for TSC may be 

overly aggressive under the planned budget scenario. However, under the expanded budget 

scenario, a noticeable cost improvement when compared to no DOE and planned DOE funding 

(the space between solid colored lines) occurs and, while still an aggressive target, the likelihood 

of achieving the program goals increases significantly. 
iv

CSP- Trough with Storage- Total System Cost 

 Probability Distributions under Different Funding Scenarios

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure E1. Total system cost probability distributions for CSP trough with storage

For utility PV, the results in Figure E2 indicate that experts think the 2015 Program goal value of 

$2,200/kW is very aggressive; and, while unlikely to be reached without DOE funding, the goal 

becomes more likely under the DOE Planned (>10% probability) and DOE Expanded (>20% 

probability) funding scenarios. When looking at the Program’s 2020 goal value of $2,100/kW, 

the experts think that the DOE planned budget is more likely to be achieved (>33% probability) 

than the 2015 goal value, and the expanded budget increases the likelihood to nearly 50% 

probability. 

PV- Utility Scale- Total System Cost 

Probability Distributions under Different Funding Scenarios

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

$5,500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure E2. Total System Cost Probability Distributions for Utility PV Systems 
v 

Table of Contents

Executive Summary...................................................................................................................iii

1 Solar Program Approach to Risk Analysis................................................................... 1

1.1 Introduction......................................................................................................................... 1

1.2 Methodology for the 2009 Solar Risk Assessment............................................................. 2

1.2.1 Risk Analysis Team................................................................................................ 2

1.2.2 Expert Team Members............................................................................................ 2

1.2.3 Distribution of Expert Briefing Reports and Score Sheets ..................................... 3

1.2.4 Specific Budget and Timeframe Assumptions........................................................ 5

1.2.5 Technology Performance Measures and Base Case Scenarios............................... 6

1.2.6 Webinars - Kickoff Meetings and Expert Reviews .............................................. 10

1.2.7 Final Aggregation of Expert Inputs ...................................................................... 12

2 Summary of Results .....................................................................................................13

2.1 Concentrating Solar Power—Trough Risk Analysis Results ........................................... 13

2.2 Concentrating Solar Power—Tower Risk Analysis Results............................................. 14

2.3 Photovoltaics—Utility Risk Analysis Results.................................................................. 15

2.4 Photovoltaics–Commercial Risk Analysis Results........................................................... 16

2.5 Photovoltaics—Residential Risk Analysis Results........................................................... 17

2.6 Photovoltaics—Disruptive Technology Advancements Results ...................................... 17

3 Program Findings on Effectiveness of Methodology ................................................24

3.1 Experts’ Responses—Questions/Issues............................................................................ 24

3.2 Experts’ Understanding of Instructions............................................................................ 24

3.3 Reference Technology Values.......................................................................................... 24

3.4 Confidence in Results....................................................................................................... 25

Appendix A: Concentrating Solar Power (Trough) Risk Analysis, Summary of @Risk 

Results—Fan Diagrams.......................................................................................................... A-1

Appendix B: Concentrating Solar Power (Tower) Risk Analysis, Summary of @Risk 

Results—Fan Diagrams.......................................................................................................... B-1

Appendix C: Photovoltaic (PV) Risk Analysis, Summary of @Risk Results—Fan 

Diagrams.................................................................................................................................. C-1

Appendix D: Concentrating Solar Power (CSP) Risk Analysis, Summary of @Risk 

Results—Aggregated Probability Distributions................................................................... D-1

Appendix E: Photovoltaic (PV) Risk Analysis, Summary of @Risk Results—Aggregated 

Probability Distributions ........................................................................................................ E-1

Appendix F: Summary of @Risk Results–Aggregated Probability Distribution Tables .. F-1

Appendix G: Aggregated Percent Likelihoods for Photovoltaic (PV) Disruptive 

Advancements ........................................................................................................................ G-1
1 

1 Solar Program Approach to Risk Analysis

1.1 Introduction

The Office of Energy Efficiency and Renewable Energy (EERE) of the U.S. Department of 

Energy (DOE) is tasked with assessing the risk and uncertainty in the benefit estimates of its 

Technology Development (TD) programs. These risk assessments require technical experts to 

express their best judgment about the effect of Research and Development (R&D) programs on 

the future cost and performance of each technology in the form of estimated probability 

distributions on parameters, such as capital costs ($/kW) and operations and maintenance 

(O&M) costs ($/kW-yr). 

The main objectives of the EERE risk analysis of its R&D Programs are to: 1) meet the National 

Academy of Science’s requirement to report uncertainty; 2) improve project, portfolio, and 

program performance; 3) clarify issues associated with accepting, managing, or rejecting risks; 

4) link science research opportunities with applied energy R&D; and 5) increase decision-maker 

understanding of potential R&D results. Stated in another manner, results from the technical risk 

and uncertainty analysis equip management teams with the ability to consistently assess and 

manage tasks down their administrative chain, and also to evaluate and communicate program 

performance up the chain. 

Technology experts convened for this task were asked to judge the potential successes of Solar 

Energy Technologies Program (SETP or the Program) research in the areas of concentrating 

solar power (CSP) technologies (i.e., parabolic trough, power tower, and dish-engine) in the 

utility market, and solar photovoltaics (PV) technologies (i.e., crystalline silicon, thin films, and 

concentrating PV) in the residential, commercial, and utility markets. 

Information was obtained on each technology from experts who prepared probabilistic estimates 

of future performance, based on planned R&D programs. Assessments are presented in the 

form of probability distributions to express uncertainty about technology performance in future 

goal years. The Risk Analysts and Facilitators team was tasked with aggregating these 

distributions across the expert subgroups and providing the results of the analysis to DOE and 

national laboratory staff for use in Program and portfolio evaluation. 

The 2009 SETP Risk Analysis effort was based on a similar pilot-scale risk analysis conducted 

in 2008. The DOE and SETP updated the analysis to include recent technology improvements 

and market realities, as well as to incorporate several lessons learned and feedback from the 

experts on how to enhance the expert elicitation process. 
2 

1.2 Methodology for the 2009 Solar Risk Assessment

Through a series of webinars, conference calls, and email communications, the Solar Risk 

Analysis Team coordinated efforts across a group of technology experts from national labs, 

academia, and industry. Virtual meetings (i.e., webinars and conference calls) were held 

separately for CSP and PV to introduce the process and methodology, communicate the inputs 

requested from the experts, and support the experts during the elicitation process. The schedules 

for CSP and PV varied with respect to the days in which activities were conducted, but both were 

completed between February and June 2009. A more detailed explanation of the schedule can be 

found in Section 1.2.6 Webinars - Kickoff Meetings and Expert Reviews. 

The experts were asked to estimate, via probability distributions, specific technology cost 

reductions under three different DOE funding scenarios and three different time periods. In 

order to effectively elicit the inputs or probability distributions from the experts on the range of 

performance measures, technology evaluation input sheets were developed. Once collected from 

the experts, the probability distributions were aggregated and run through @Risk, a probabilistic 

model utilizing Latin Hypercube simulation to perform quantitative risk analysis. 

1.2.1 Risk Analysis Team

The Solar Risk Analysis Team was composed of risk analysts, facilitators, and SETP staff 

advisors. Risk analysts and facilitators were tasked with the following: clearly explaining the 

information needed, providing simple forms to elicit input from the experts, answering questions 

from experts, receiving and aggregating inputs, discussing an expert’s response one-on-one as 

needed, providing initial results to the experts, finalizing results, and preparing the final report. 

The risk analysts and facilitators for the 2009 solar risk assessment were James McVeigh, Mark 

Lausten, Arun Soni, and Ed Eugeni, all from Sentech, Inc. The SETP staff advisors for the 2009 

solar risk assessment were Tex Wilkins (DOE) for CSP, and Scott Stephens (DOE) and Robert 

Margolis (NREL) for PV. Methodology development, guidance, and advice were provided by 

the DOE Risk Working Group members Sam Baldwin (DOE), Thomas Jenkin (NREL), James 

McVeigh (Sentech, Inc.), and Max Henrion (Lumina Decision Systems, Inc.). 

1.2.2 Expert Team Members

Concentrating Solar Power

The Solar Risk Analysis Team contacted 48 CSP experts from more than 20 different 

organizations, based on the following criteria: 

• By expertise: parabolic trough, power tower, dish-engine 

• Global: national and international experts

• Variety: national labs, academia, industry. 

Of these, the Solar Risk Analysis Team received a total of eight (8) expert responses (6 industry 

and 2 lab). 
3 

Photovoltaics 

The Solar Risk Analysis Team contacted 45 PV experts from over 25 different organizations, 

based on the following criteria: 

• By expertise: crystalline silicon, thin film, and concentrating PV

• Global: national and international experts

• Variety: national labs, academia, industry. 

Of these, the Solar Risk Analysis Team received the following results from experts: five (5) 

utility-scale (3 industry, 1 laboratory, 1 academia); nine (9) commercial-scale (6 industry, 2 

laboratory, 1 academia); and four (4) residential-scale (2 industry, 1 laboratory, 1 academia).

1.2.3 Distribution of Expert Briefing Reports and Score Sheets 

Solar experts were provided with a set of “common information” in the form of expert briefing 

documents and detailed instructions regarding how to complete the CSP and PV assessment 

forms, referred to as score sheets. This was done through “Expert Kickoff Meetings” held for 

both CSP and PV. Additionally, the experts were provided a brief report summarizing the 

identified studies, reports, and data (i.e., current status of the technology, planned and potential 

R&D, and projections of future cost and performance improvements) relevant to the risk 

analysis. During these meetings, the Risk Analysis Team identified and reviewed the expert 

briefs and score sheets, and asked experts to provide any content suggestions. Following these 

forums, the materials were emailed to the participants.

The CSP Expert Briefing Report provided to the Expert Team included: 

• DOE Advanced Thermal Energy Storage Development Plan for Parabolic Trough 

Technology. 2007 DOE Study by H. Price of the National Renewable Energy Laboratory 

(NREL), D. Brosseau of Sandia National Laboratories (SNL), D. Kearney (Kearney & 

Associates), and B. Kelly (Nexant), (2007) 

• DOE Solar Program 2007-2011 Multi Year Program Plan, (2007) 

• Arizona Renewable Energy Assessment, Black & Veatch, (9/2007) 

• Economic, Energy, and Environmental Benefits of Concentrating Solar Power in 

California, prepared by L. Stoddard, J. Abiecunas, and R. O'Connell, of Black & Veatch, 

for NREL, Subcontract Report NREL/SR-550-39291, (4/2006) 

• Solar Task Force Report, Western Governor’s Association, , (1/2006) 

• Assessment of Parabolic Trough and Power Tower Technology Cost and Performance 

Forecasts, prepared by Sargent & Lundy, for DOE and NREL, Final Report, SL-5641, 

(5/2003); 

• USA Trough Initiative- Thermal Storage for Rankine Cycle and Combined Cycle Power 

Plants, NREL, presented by Bruce Kelly, Nexant Inc., and Ulf Herrmann, FLABEG Solar 

International GmbH., (2/2006) 

• Evaluating the Carbon Dioxide Abatement Potential of EERE Technologies- Solar Power 

Discussion, McKinsey & Company, presentation made to EERE Programs, (10/7/2008). 

The PV Expert Brief provided to the Expert Team included: 

• Technology Pathway Partnerships, Projections of Cost Improvements, DOE, SETP 

(2006) 
4 

• A Review of Industry and Financial Analysts Projections for Solar Technologies- An 

Analysis of Industry Forecasts including Photon Consulting (2008), Piper Jaffray (2008), 

Goldman Sachs (10/2008), Lazard (11/2008), Prometheus (10/2008), Deutsche Bank 

(05/2008), FBR (11/2008). Documents obtained via personal contact with Scott 

Stephens, DOE, on January 7, 2009 

• PV Cost Projections, Photon Consulting, , Photon Magazine, (January 2008) 

• Arizona Renewable Energy Assessment, prepared by Black & Veatch for Arizona Public 

Service Company, Salt River Project, and Tucson Electric Power Corporation, B&V 

Project Number 145888, (September 2009) 

• Tiered Carbon Impacts Analysis, DOE, EERE, Draft, (October 14, 2008); 

• Evaluating the Carbon Dioxide Abatement Potential of EERE Technologies- Solar Power 

Discussion, Presentation made by McKinsey & Company to EERE Programs, (October 7, 

2008); 

• A Review of PV Inverter Technology Cost and Performance Projections, Navigant 

Consulting, Inc., presentation to NREL, (January 12, 2006) 

• Corporate Overview Q2 2008, First Solar, PowerPoint Presentation, (2008) 

• Opportunities and Challenges for Development of a Mature Concentrating Photovoltaic 

Power Industry, S. Kurtz of NREL, Technical Report, NREL/TP-520-43208, (Revised 

February 2009) 

• Solar Photovoltaic Industry- Looking through the storm, Deutsche Bank, (January 2009). 

Innovative and streamlined technology evaluation input sheets were developed to collect specific 

metrics data from the technology experts, including: the expert’s self rating; the extreme future 

technical or economic limits; learning by doing rates; the probability of advance; and the 

improvement distribution in the form of 10th percentile, most likely, and 90th percentile 

estimates. Figure 1.1, which follows, represents a sample of the 2009 Solar Risk Analysis score 

sheets.
5 

Figure 1.1. Example score sheet for the 2009 Solar Risk Assessment 

1.2.4 Specific Budget and Timeframe Assumptions 

Experts provided estimates of technology improvements based on three funding scenarios: 1) 

baseline industry R&D 2) current planned DOE budget for R&D, and 3) an expanded DOE 

budget for R&D. 

The baseline industry R&D case accounts for improvements over time due to investment in R&D 

by industry and other governments, while assuming zero DOE funding for R&D activities. The 

DOE planned program budget case accounts for improvements over time due to the current 

amount of U.S. federal government R&D funding being held constant through time (inflation 

adjusted). The expanded program, or over-target case, accounts for technology improvements 
6 

caused by a doubling in U.S. federal government R&D funding over the current plan (inflation 

adjusted). Table 1 lists the DOE Solar Program funding levels from 2007 and 2009, along with 

funding that the risk analysis assumed for the years 2010 through 2025. 

Table 1. U.S. Department of Energy Solar Energy Technologies Program Funding Levels

Technology FY 2007 FY2008 FY2009

Assumed FY 

2010-2025

Expanded 

FY 2010-

2025

Concentrating Solar 

Power

$16 million $30 million $30 million Constant at 

$30 million

Constant at 

$60 million

Photovoltaic Energy 

Systems

$138

million

$137 million $145

million

Constant at 

$140 million

Constant at 

$280 million

For baseline industry R&D, both CSP and PV DOE funding were considered to be $0. For the 

current planned DOE R&D budget, funding was considered $30 million and $140 million for 

CSP and PV, respectively. For an expanded DOE R&D budget, funding was considered $60 

million and $280 million for CSP and PV, respectively. 

For each of the funding scenarios, three future goal-years were identified for the two 

technologies so that experts could provide cost projections. The CSP goal-years were 2015, 

2020, and 2025, whereas the PV goal-years were 2010, 2015, and 2020. The difference between 

the two was a result of analyst judgment on the current state of the solar market for both of these 

technologies. 

1.2.5 Technology Performance Measures and Base Case Scenarios

The Solar Program has developed a set of Technology Improvement Opportunities (TIOs) in its 

Multi-Year Program Plan. These TIOs represent the projects and R&D activities (or set of 

activities) that can be undertaken to improve the technology. The quantifiable metrics (e.g., 

capital cost or efficiency) that characterize the technology and show how much improvement 

occurs are called Technology Performance Measures (TPMs). Utilizing the Program’s TPMs in 

R&D planning can create a clearer image of the technology’s future. CSP TPMs are listed in 

Table 2, and PV TPMs are listed in Table 9. 

Experts provided the estimates on the probability of advance (POA), and a distribution (assumed 

to be triangular) of what the advance would be in the form of the 10th percentile, most likely (or 

mode), and 90th percentile values for each TPM. The POA is defined as the probability that 

R&D will improve the technology relative to the current state of the technology. The inverse of 

this probability (1 minus the POA) is the probability of R&D failure (i.e., the likelihood that

R&D will not improve the technology and the TPM will remain at the current value. The 

distributions (10%/Most Likely/90%) represent the range of outcomes that could occur if the 

R&D is successful and some improvement is made.

Concentrating Solar Power 

The 2009 Solar Risk Analysis looked at the TPMs listed below in Table 2 for the various CSP 

technology applications. It should be noted that results for tower without storage and dishengine results are not available, as there were not enough responses provided by the experts.
7 

Table 2. Technology Performance Measures Utilized in the 2009 Solar Program Risk Analysis

CSP Technology Technology Performance Measures (TPMs)

CSP Line Focused (Trough or 

CLFR) with 6 Hr Thermal Storage

1) Solar Field (Reflector, Receiver) System ($/kW)

2) Heat Transfer Fluid (HTF) System ($/kW)

3) Thermal Energy Storage (TES) System ($/kWht)

4) Power Block & Balance Of System (BOS) ($/kWe)

5) Operations and Maintenance (O&M) (($/kW-yr)

CSP Tower With 

6 Hr Thermal Storage

1) Solar Field (Heliostats) ($/kW)

2) Receiver and Tower System($/kW)

3) Thermal Energy Storage (TES) System ($/kWht)

4) Power Block & Balance Of System (BOS) ($/kWe)

5) Operations and Maintenance (O&M) ($/kWe-yr)

CSP Tower With

No Thermal Storage

1) Solar Field (Heliostats) ($/kW)

2) Receiver and Tower System ($/kW)

3) Power Block & Balance Of System (BOS) ($/kWe) 

4) Operations and Maintenance (O&M) (($/kW-yr)

CSP dish-engine

1) Solar Field (Concentrator, Reflector) System ($/kW)

2) Receiver ($/kW)

3) Engine/Generator ($/kW)

4) Operations and Maintenance (O&M) Cost (($/kW-yr)

The base-case model for a CSP trough plant for the 2009 Solar Risk Assessment study is that of 

a 100-megawatt (MW) plant with 6 hours of thermal energy storage as identified in Solar 

Advisor Model- Version 2.5.0.2 February 13, 2007—using Daggett, California resource (950 

W/m2 design point). Costs are expressed in 2009 dollars and are based on historical data of CSP 

plants and previous studies adjusted for inflation and escalation. It should be noted that 2008 

and 2009 have seen significant commodity price swings. All attempts were made to convert 

prior studies’ project costs to current dollars.

Tables 3 and 4 list the base-case CSP trough model plant configuration and plant costs (in 2009 

dollars).
8 

Table 3. Base-Case Model CSP Trough Plant Configuration 

100-MW Plant with 6 hour TES storage

System Size 100 MW

Solar Field 871,936 m2

Solar Field Row Spacing to Aperture Ratio 3:1

Solar Multiple 2 

Solar Field Parasitics (Drives And Electronics) 232 kWe

Solar Field Optical Efficiency 77.6 %

Storage 1,748.80 MWht

HTF and TES Pumping Parasitics 12.3 MWe

Solar Field, HTF And TES Thermal Losses 59.5 MWt

Thermal Energy Storage Round Trip Efficiency 98.5 % 

Power Block & BOP Parasitics 7.7 MWe

Steam Turbine Gross Efficiency 37.74 %

Steam Turbine Inlet Temperature 370 Deg C

Power Block Availability 94 %

Capacity Factor 41 %

Table 4. Base-Case Model CSP Trough Plant Costs in $2009

100 MW Plant with 6 hour TES storage Units Total $2009 $/kWe peak

Direct Installed Costs

Solar Collection Field $350 /m2 $305,177,670 $3,052 

HTF System $150 /kWe $15,000,000 $150 

Storage System $45.00 /kWht $78,696,343 $787 

Site Improvements* $4.50 /m2 $3,923,713 $39 

Power Plant* $1,080 /kWe $108,000,000 $1,080 

Contingency Percent 10 % $51,079,773 $511 

Direct Costs Sub Total $561,877,499 $5,619 

Indirect Costs

Engineering, Procurement, Construct (EPC) 

of Direct 15 % $76,619,659 $766 

PLM Percent of Direct 5 % $25,539,886 $255 

Sales Tax applied to 80% Percent of Direct 7.25 % $29,626,268 $296 

Indirect Costs Subtotal $131,785,813 $1,318 

Total Installed Cost $693,663,312 $6,936 

Operating Costs

Fixed O&M $69.00 /kW-yr

Variable O&M $0.67 /MWh

Annual Variable O&M $2.52 /kW-yr

Annual Total O&M $73.99 /kW-yr

 * Assumed to be part of BOS&PB TPM costs

For CSP Tower plants, the Risk Analysis relied heavily on the data available in the Sargent & 

Lundy study, “Assessment of Parabolic Trough and Power Tower Solar Technology Cost and 

Performance Forecasts” (NREL/SR-550-34440). This is considered the most comprehensive 

study available to date for towers. The following parameters and costs reflect an adjustment to 
9 

those specifications and costs to align with a 40% capacity factor for a plant built in 2015, but 

reflected in 2009 dollars. 

Tables 5 and 6 list the base-case CSP tower model plant configuration and plant costs (in 2009 

dollars).

Table 5. Base-Case Model CSP Tower Configuration 

100 MW Plant with 6-Hour TES storage

System Size 100 MW

Solar Field 960,000 m2

Solar Multiple 1.7

Solar Field and Receiver Optical Efficiency 45 %

Storage 1,571 MWht

Thermal Energy Storage Round Trip Efficiency 99.5 %

Power Block & BOP parasitics 10 MWe

Steam Turbine Gross Efficiency 42 %

Steam Turbine Inlet Temperature 550 Deg C

Power Block Availability 94 %

Capacity Factor 40 %

Table 6. Base-Case Model CSP Tower Plant Costs in $2009. 

100 MW Tower Plant with 6 hour TES storage Units Total $2009 $/kWe peak

Direct Installed Costs

Heliostat Field $208 /m2 $199,490,566 $1,995 

Tower and Receiver $751 /kWe $75,100,000 $751 

Storage System $18 /kWht $27,756,500 $278 

Site Improvements* $4.50 /m2 $4,320,000 $43 

Power Plant* $1,050 /kWe $105,000,000 $1,050 

Contingency Percent 10 % $41,166,707 $412 

Direct Costs Sub Total $452,833,772 $4,528 

Indirect Costs

Engineering, Procurement, Construct (EPC) 

of Direct 15 % $61,750,060 $618 

PLM Percent of Direct 5 % $20,583,353 $206 

Sales Tax applied to 80% Percent of Direct 7.25 % $23,876,690 $239 

Indirect Costs Subtotal $106,210,103 $1,062 

Total Installed Cost $559,043,875 $5,590 

Operating Costs

Fixed O&M $69.00 /kW-yr

Variable O&M $0.67 /MWh

Annual Variable O&M $2.52 /kW-yr

Annual Total O&M $73.87 /kW-yr

 * Assumed to be part of BOS&PB TPM costs
10 

Photovoltaics 

The PV Expert Team evaluated PV systems within the following three market sectors: 

residential, commercial, and utility. Table 7 lists this information, along with the five TPMs 

covered in the risk analysis. A new and unique element was added to the PV Risk Analysis this 

year to gain the experts’ perspectives on which revolutionary technology advances were 

expected to occur in the future. Each expert was asked to rate the likelihood that a specific 

disruptive advancement in PV technologies would occur by certain dates (see Section 2.6 for a 

list of disruptive technology advancements assessed and the results). 

Table 7. PV Market Applications, Technologies, and Performance Measures

PV Market Applications PV Technology Technology Performance Measures (TPMs)

Residential Crystalline Silicon PV Module Cost 

($/kW)

O&M Cost 

($/kW-yr)

Commercial Thin Film Inverter Cost 

($/kW)

Inverter Life (years)

Utility Concentrating PV Total System Installed Cost

($/kW)

Additional TPMs that have been identified and were assessed in the pilot 2008 Solar Program 

Risk Analysis (i.e., jobs; scalability; and water usage for CSP) were excluded from this year’s 

analysis to simplify the process and reduce the number of estimates that the experts had to make. 

1.2.6 Webinars - Kickoff Meetings and Expert Reviews 

The process of eliciting expert input for the 2009 Solar Risk Analysis was conducted through 

multiple online webinars. Through these separate webinar series, CSP and PV experts were

asked to estimate specific technology cost and performance improvements that would occur 

during three different time periods, and with three different DOE funding scenarios. Tables 8 

and 9 summarize the timelines.

Table 8. Schedule for the 2009 CSP Risk Analysis

Activity Date

Webinar kickoff meeting February 25

Webinar kickoff meeting 2 March 3

Score sheet distribution to experts March 23

Score sheet review and Q&A March 30 and 31

Input sheet responses Due from experts: April 18

Submitted to SEDS/NEMS/MARKAL: May 1

Expert review webinar meeting June 22

Input sheets revisions Due from experts: June 29 (no revisions were 

provided, so previous submission to 

SEDS/NEMS/MARKAL was unchanged

Final report Fall 2009
11 

Table 9. Schedule for the 2009 PV Risk Analysis 

Activity Date

Webinar kickoff meeting March 3 and 6

Score sheet review and Q&A March 18 and 19

Input sheet responses due from experts: March 20

Accepted from experts until March 31

Expert review webinar meeting April 2

Input sheets revisions (if needed) Due from experts: April 9

Submitted to SEDS/NEMS/MARKAL: May 1

Final report Fall 2009

Concentrating Solar Power 

The CSP webinar kickoff meetings were held in February 2009 to discuss the process, 

assumptions, and briefing document. As part of the introduction, probability density functions 

were reviewed and an explanation on the estimation input format was provided. A second round 

of webinar kickoff meetings were held in early March to continue the discussion on the risk brief 

and reference values. In addition, the risk analysts and facilitators walked through an example of 

how to complete the score sheets. 

Score sheets were distributed to the experts after the kickoff webinars. Approximately one week

after disseminating the score sheets, the risk analysts and facilitators were available via webinar 

during two 4-hour windows to answer specific questions and help the experts fill in the score 

sheets in real time if necessary. Inputs were due from experts in mid-April, and upon receipt, 

results were aggregated in a probabilistic risk analysis model utilizing the @Risk software. The 

initial results of this model were then provided back to the experts in a final webinar where the 

risk analysts and facilitators presented and explained the results. The experts were given a 

chance to discuss amongst themselves and then provided a chance to revise their inputs if there 

was any confusion or misunderstanding on what was being asked of them, or if new information 

or rationale was discussed that caused them to alter their opinions. None of the CSP experts 

made changes to their initial estimates, so the aggregated results previously submitted remained 

the same.

Photovoltaics

The PV webinars were conducted in a similar manner to those for CSP, with two separate 

webinar kickoff meetings held during the first week of March 2009 to accommodate 

participants’ schedules. Discussion of the process, assumptions, and briefing document 

occurred, and afterwards, score sheets were sent to experts.

Similar to the CSP group, risk analysts and facilitators were available during two 4-hour 

windows in mid-March to answer questions and provide real-time support on filling out score 

sheets. Input sheets were accepted from experts until the end of March, and upon receipt, results 

were aggregated in a similar @Risk model. The results were summarized and provided back to 

the expert teams for discussion. An expert review webinar was then held in April, in which the 

risk analysts and facilitators presented on the results and the experts discussed aggregated results 

with each other. Afterward, experts were given one week to modify their individual projections 

if they deemed necessary. It should be noted that consensus was not forced on the group and no 
12 

expert was asked or suggested to revise his or her estimates simply because their opinion was an 

outlier relative to others in the group. 

1.2.7 Final Aggregation of Expert Inputs

Probability distributions provided by the experts were aggregated and run through @Risk, a 

probabilistic model utilizing Latin Hypercube Simulation (LHS) to perform the quantitative 

technical risk and uncertainty analysis. Once finalized, these results were fed into the Stochastic 

Energy Deployment Systems (SEDS) model, and were also utilized in deterministic models such 

as the National Energy Modeling System (NEMS) and the Market Allocation Model 

(MARKAL), as part of DOE’s Portfolio Development Support (PDS) and Government 

Performance and Results Act (GPRA) benefits processes. These models project future market 

penetration of various technologies, and the associated energy security, economic, and 

environmental benefits (e.g., barrels of oil displaced, consumer savings, and carbon reductions) 

due to Program R&D funding. Results of the 2009 Solar Risk Assessment can be found in 

Section 2.0 Summary of Results.
13 

2 Summary of Results

The Total Installed Cost/Total System Cost results of the 2009 Solar Energy Technologies 

Program’s Technical Risk and Uncertainty Analysis are presented below for CSP and PV. The 

full results of the analysis are provided in Appendices A through G, which include the following: 

details on the fan diagrams for TPMs in each time period and funding scenario; aggregated 

probability distributions; market model inputs; and aggregated PV disruptive technology 

advancements. 

Each figure for Total System Cost includes three projections of future improvements: 

1. Baseline: The aggregated expert team risk distributions, shown for the 10%, 50%, and 

90% scenarios, assuming no DOE R&D funding of the technology; 

2. DOE planned (target funding) or DOE expanded (over-target funding): 

a. DOE planned—The first figure in each set shows the aggregated expert team risk 

distributions, shown for the 10%, 50% and 90% scenarios, assuming the planned 

DOE R&D funding. 

b. DOE expanded—The second figure in each set shows the aggregated expert team 

risk distributions, shown for the 10%, 50% and 90% scenarios, assuming 

expanded DOE R&D funding. 

3. Program goal: A point estimate trajectory of improvements formulated assuming that the 

Program achieves its goals (i.e., this information has typically been provided by EERE 

programs in prior years as inputs into the NEMS and the MARKAL models for market 

penetration modeling and program benefits calculations). 

2.1 Concentrating Solar Power—Trough Risk Analysis Results

CSP- Trough with Storage- Total System Cost 

 Probability Distributions under Different Funding Scenarios

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure 2.1. Total system cost probability distributions for CSP trough with storage 
14 

Figure 2.1 indicates that the planned budget should allow for a relatively pronounced cost 

decrease in troughs when compared to no DOE funding. Similarly, an expanded budget should 

allow for an even more noticeable cost reduction when compared to the other scenarios (resulting 

in $4,597/kW when considering the 50th percentile input). Nonetheless, while significant trough 

improvements can occur with DOE monetary support, the Program goal values are relatively 

unlikely to be achieved according to expert inputs, and therefore may need to be revised. 

2.2 Concentrating Solar Power—Tower Risk Analysis Results

CSP- Power Tower with Storage- Total System Cost 

Probability Distributions under Different Funding Scenarios

3,500

4,000

4,500

5,000

5,500

6,000

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure 2.2. Total system cost probability distributions for CSP tower with storage

Figure 2.2, representing tower total installed probability distributions, shows a gradual cost 

decrease out to 2025 (reaching $4,598/kW based on the 50th percentile expanded funding case). 

Results demonstrate that the Program’s 2015 goal can likely be achieved with planned funding, 

but the 2025 goal is not likely to be realized without expanded funding levels. 

It should be noted for the CSP cost curves (both trough and tower) that the probability of 

achieving a “goal-based” value does not necessarily need to be at or above 50%. Many have 

argued that the role of DOE is to undertake R&D that industry may consider too risky. In fact, 

many DOE programs have been tasked with setting aggressive goals for improving those 

technologies. Furthermore, the likelihood of achieving a particular value may be misleading for 

the following reason: improving the technology, but not quite reaching a deterministic target, 

will still yield benefits. These benefits may be lost if achieving at least the goal value is seen as 

the pass/fail measure.
15 

2.3 Photovoltaics—Utility Risk Analysis Results

PV- Utility Scale- Total System Cost 

Probability Distributions under Different Funding Scenarios

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

$5,500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure 2.3. Total system cost probability distributions for PV utility 

As shown in Figure 2.3, PV experts foresee a noticeable decrease in total system cost at the 

utility level even without DOE funding, achieving $3,094/kW in 2020 when considering the 50th

percentile input. However, they believe the cost would drop to $2,418/kW in 2020 when 

considering the 50th percentile input for the planned funding scenario. This latter amount is 

approaching the Program goal of $2,100/kW. If an expanded DOE budget is provided, the 

experts indicate there is a 50% chance the 2020 objective will be met or exceeded, and a 10% 

chance that Program expectations will be surpassed to the point that TSC will be at or below

$1,505/kW. 
16 

2.4 Photovoltaics–Commercial Risk Analysis Results

PV- Commercial Scale- Total System Cost 

Probability Distributions under Different Funding Scenarios

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure 2.4. Total system cost probability distributions for PV commercial

Similar to utility PV, Figure 2.4 expresses a noticeable decrease in TSC out to 2020 in all 

funding scenarios. A greater amount of cost reduction is projected to occur between 2010 and 

2015, as indicated by the steepness in slopes for the 50th percentile lines. With planned DOE 

funding, it is anticipated that the 2020 Program goal of $2,330/kW will be met, and possibly 

even surpassed, potentially reaching $1,570/kW. When considering the expanded budget, the 

experts reveal more optimism, as is evident by the 50th and 10th percentile lines. 
17 

2.5 Photovoltaics—Residential Risk Analysis Results

PV- Residential Scale- Total System Cost 

Probability Distributions under Different Funding Scenarios

$1,500

$2,500

$3,500

$4,500

$5,500

$6,500

$7,500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure 2.5. Total System Cost Probability Distributions for PV Residential

Figure 2.5 illustrates that without DOE funding experts forecast a steady decline in TSC, with a 

2020 result of $4,228/kW (based on 50th percentile inputs). This is well above the Program goal 

of $3,070/kW. When planned funding occurs, however, experts are more confident that the 2020 

goal will be reality. Expanding the DOE budget may allow for additional cost reductions 

according to expert input (achieving $2,713/kW), but this is not a considerable decrease in cost 

when compared to the planned funding scenario. 

2.6 Photovoltaics—Disruptive Technology Advancements Results

Along with the probability density functions, PV participants were asked to indicate the 

likelihood of specific disruptive PV technology advancements occurring in the future. These 

disruptive technology advancements include improvements across various technologies and 

material types, at the component level up through large scale manufacturing processes, and 

across the different market applications. Again, the experts were asked to give estimates for 

different years (i.e., every 10 years from 2010 to 2050) and under the three funding scenarios. 

Table 10 provides a list of the specific disruptive technology advancements that the experts were 

asked to assess.
18 

Table 10. Disruptive PV Technology Advancements by Category. 

Silicon Modules

1) Kerfless wafering at about 1g/W achieving at least 20% of wafering industry's 

annual production

2) Upgraded metallurgical-grade (UMG) silicon (no Siemens or Fluidized Bed 

Reactor processing) provides greater than 20% of industry's annual cell 

manufacturing

3) ultrathin (≤100 μ) wafer thickness achieved in greater than 20% of annual 

wiresaw wafering production

Thin Films

1) Greater than 15% thin film module efficiency in unconcentrated, terrestrial 

commercial modules

2) Flexible modules make up more than 20% of annual market

3) Organic PV modules make up more than 20% of annual market

4) Copper indium gallium selenide (CIGS) modules make up more than 20% of 

annual market

Other Module 

Advancements

1) Use of III-V devices in non-tracking modules to achieve commercial modules 

with greater than 25% efficiency at a competitive cost

2) Multi-exciton photogeneration or intermediate band structure devices sold in a 

commercial terrestrial PV product

3) Commercial concentrating photovoltaic (CPV) modules at greater than 30% 

efficiency

Inverters and 

Systems

1) Economical 30-year warrantee available on greater than 20% annual inverter 

market

2) Alternating-current PV modules (microinverters) achieve at least a 20% annual 

market share of residential rooftop installations

3) 20% of new inverter installations employ time-of-use pricing operation

4) 20% of grid tied systems incorporating energy storage functionality (i.e., battery 

or plug-in hybrid electric vehicle)

Installations

1) Physical installation of building-integrated PV shingle by non-PV-trained roofer 

achieves greater than 20% of annual residential installations

2) Commercial roofing PV membrane makes up more than 20% of annual 

commercial rooftop installations

3) Highly automated ground installations (~1 MW/year/installer)

4) Concentrating PV (>100x concentration) achieves 20% of annual ground mount 

installations (green)

The following graphs present the aggregated results of the disruptive technology advancements 

analysis in the form of the average likelihood of achieving the advancement by a given time 

period and funding level. In the graphs, the solid line represents no DOE funding for the 

variable being measured. The thicker dotted line represents the planned DOE funding scenario, 

and the thinner dotted line signifies the expanded funding scenario. One of the keys here is to 

gauge how large the gap is between lines of the same color, as this allows one to understand how 

experts perceive different funding levels impact the likelihood of realizing specific disruptive 

technology advancements. 
19 

Silicon Module

0%

10%

20%

30%

40%

50%

60%

70%

80%

2010 2015 2020 2030 2040 2050

Year

Likelihood of Occurrence

No DOE - Kerfless

Planned - Kerfless

Expanded - Kerfless

No DOE - UMG Silicon

Planned - UMG Silicon

Expanded - UMG Silicon

No DOE - ≤100um t

Planned - ≤100um t

Expanded - ≤100um t

Figure 2.6. Disruptive advancements for silicon modules

Figure 2.6 refers to experts’ predictions of disruptive advancements for the following three 

characteristics related to silicon modules: 1) Kerfless wafering at about 1gram per Watt (g/W) 

achieving at least 20% of the wafering industry's annual production (blue lines), 2) UMG silicon 

(no Siemens or FBR processing) provides greater than 20% of the industry's annual cell 

manufacturing (red lines), and 3) ultrathin (≤100um) wafer thickness is achieved in greater than 

20% of the annual wiresaw wafering production (green lines). 

Experts are more confident that Kerfless wafering improvements will be realized by 2050, when 

compared to the other two module characteristics. Furthermore, they predict that all of the 

module traits will have a greater chance of occurring at an earlier time under expanded funding. 

However, although the federal R&D budget is expected to have a more substantial impact on the 

acceleration of achieving these traits, the likelihood of occurrence does not break 80%, even in 

2050. 
20 

Thin Film 

0%

10%

20%

30%

40%

50%

60%

70%

80%

2010 2015 2020 2030 2040 2050

Year

Likelihood of Occurrence

No DOE - ≥15% thinfilm

Planned - ≥15% thinfilm

Expanded - ≥15% thinfilm

No DOE - Flexible modules

Planned - Flexible modules

Expanded - Flexible modules

No DOE - Organic PV 

Planned - Organic PV 

Expanded - Organic PV 

No DOE - CIGS modules

Planned - CIGS modules

Expanded - CIGS modules

Figure 2.7. Disruptive advancements for thin film technologies

Figure 2.7 refers to experts’ predictions of disruptive advancements for the following four 

characteristics related to thin films: 1) Greater than 15% thin film module efficiency in 

unconcentrated, terrestrial commercial modules (blue), 2) Flexible modules make up more than 

20% of the annual market (red), 3) Organic PV modules make up more than 20% of the annual 

market (orange), and 4) CIGS modules make up more than 20% of the annual market (greens). 

Experts believe thin film efficiency of at least 15% is most likely to occur out of the four 

characteristics, even without DOE funding. The flexible modules’ market share will benefit 

noticeably throughout the timeframe when comparing the no-DOE funding to the DOE-planned 

and -expanded funding scenarios. Nonetheless, the experts believe that the ability of flexible 

modules, CIGS, and organics to achieve at least a 20% market share is unlikely to occur by 2050 

under any of the funding scenarios. 
21 

III-V Devices, Multi-exiton & CPV Module Characteristics

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2015 2020 2030 2040 2050

Year

Likelihood of Occurrence

No DOE - III-V devices

Planned - III-V devices

Expanded - III-V devices

No DOE - Multi-exiton

Planned - Multi-exiton

Expanded - Multi-exiton

No DOE - CPV >30%eff

Planned - CPV >30%eff

Expanded - CPV >30%eff

Figure 2.8. Disruptive advancements for modules

Figure 2.8 represents expert predictions of disruptive advancements for the following four 

characteristics related to modules: 1) Use of III-V devices in non-tracking modules to achieve 

commercial modules of at least 25% efficiency at competitive cost (blue), 2) Multi-exciton 

photogeneration or intermediate band structure devices sold in a commercial terrestrial PV 

product (red), and 3) Commercial CPV modules with greater than 30% efficiency (green). 

The results suggest that the experts are very optimistic of commercially available CPV modules 

at greater than 30% efficiency, with a virtual certainty of occurrence by 2050 under planned 

DOE funding. However, experts are much less sure of technology advancements occurring in 

the III-IV and multi-exciton or intermediate band structure devices. 
22 

Inverter 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2015 2020 2030 2040 2050

Year

Likelihood of Occurrence

No DOE - inverter 30y

Planned - inverter 30y

Expanded - inverter 30y

No DOE - microinverters

Planned - microinverters

Expanded - microinverters

No DOE - time-of-use

Planned - time-of-use

Expanded - time-of-use

No DOE - energy storage

Planned - energy storage

Expanded - energy storage

Figure 2.9. Disruptive advancements for inverters/systems

Figure 2.9 represents expert predictions of disruptive advancements for the following four 

characteristics related to inverters/systems: 1) Economical 30-year warrantee available for more

than 20% of the annual inverter market (blue), 2) Alternating-current (AC) PV modules 

(microinverters) achieve at least a 20% annual market share of residential rooftop installations 

(red), 3) 20% of new inverter installations employ time-of-use pricing operation (orange), and 4) 

20% of grid tied systems incorporating energy storage functionality (i.e., battery or PHEV)

(green). 

Experts are confident that all of these disruptive advancements will occur by 2050 even without 

DOE funding. Nonetheless, the impact of DOE funding is seen by advancing the timeframe that 

these advancements are expected to occur by 5 to 15 years in certain cases. Furthermore, the 

experts foresee DOE funding having the greatest impact, in terms of overall likelihood, on timeof-use inverters. In a similar light, they see DOE funding having the greatest impact, in terms of 

timing acceleration, on energy storage technology advancements. 
23 

Installations 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2015 2020 2030 2040 2050

Year

Likelihood of Occurrence

No DOE - BIPV shingle

Planned - BIPV shingle

Expanded - BIPV shingle

No DOE - PV membrane

Planned - PV membrane

Expanded - PV membrane

No DOE - Highly automated

Planned - Highly automated

Expanded - Highly automated

No DOE - CPV >100x

Planned - CPV >100x

Expanded - CPV >100x

Figure 2.10. Disruptive advancements for installations

Figure 2.10 displays expert predictions of disruptive advancements for the following four 

characteristics related to installations: 1) Physical installation of BIPV shingle by non-PVtrained roofer achieves greater than 20% of annual residential installations (blue), 2) Commercial 

Roofing PV membrane makes up more than 20% of annual commercial rooftop installations 

(red), 3) Highly automated ground installations (~1 MW/year/installer) (orange), and 4) CPV 

(>100x concentration) achieves 20% of annual ground mount installations (green).

The opinion gauged from expert input is that highly automated ground installations will be a 

common feature of the industry by 2020. More specifically, they assume close to 100% 

likelihood that it will make up 20% of annual residential installations by 2030, when DOE 

planned or expanded funding is provided. 

In terms of large scale CPV deployment achieving a substantial portion of the ground-mounted 

market, experts believe that while DOE funding can significantly improve the likelihood of this 

occurring, overall they are not confident this will happen (i.e., less than a 70% chance by 2050). 
24 

3 Program Findings on Effectiveness of Methodology

3.1 Experts’ Responses—Questions/Issues 

Out of 48 CSP experts contacted, only 8 provided inputs, resulting in a participation rate of about 

15%. On the PV side, 45 experts were contacted and 13 provided inputs, for a higher 

participation rate of about 30%. It should be noted that some of the PV experts provided inputs 

for more than one capacity category (i.e., utility, commercial, and residential). Although several 

steps were taken to garner inputs from a multitude of individuals, the analysis could likely 

benefit from increased participation, particularly for some of the TPMs or technologies that 

garnered very little input. For PV, most experts gave inputs on the module and system costs, but 

very few addressed the inverter costs and lifetime. On the CSP analysis, there were a number of 

inputs for the trough technology, but fewer for towers and almost no responses for dish-engines. 

A more focused effort to recruit experts in these areas and increase participation (e.g., offering 

payment, stipends, or travel expenses) could be useful to augment the results of this analysis. 

3.2 Experts’ Understanding of Instructions

The 2008 analysis provided insight for better explanations of the process and instructions for 

filling out the forms provided to technical experts. For 2009, separate CSP and PV webinars 

were utilized by the risk analysts and facilitators to introduce the concepts and methodology, and 

walk through an example of filling in a score sheet. This provided experts with additional 

confidence that they were properly inputting their projections. Moreover, a follow-up webinar 

was held, and when requested, individually scheduled appointments occurred. These support 

features were provided to enable better understanding of the instructions. 

3.3 Reference Technology Values 

Through lessons learned from the 2008 analysis, the CSP portion added tower and dish-engine 

technologies to the assessment. Although dish-engine expert participation was too low to allow 

for a statistically relevant analysis, participation levels for towers with storage were sufficient. 

The tower results provide greater breadth to the overall analysis, making it more applicable to 

current market conditions and also to the Program’s R&D decision-making process. At the time 

of this analysis, a significant and important effort was simultaneously being performed in 

updating and revising the Sargent & Lundy CSP cost and technology forecast report. However, 

since this was not available to use, either as a basis for the current reference values or to 

supplement the cost and performance projections in the expert briefing, it is suggested that any 

future CSP risk analysis effort incorporate the Sargent & Lundy data, once completed. 

In 2008’s PV assessment, estimates were provided for crystalline silicon, thin film, and CPV. 

Each of these technology types has a different reference value, making it more difficult to 

compare results and evaluate the expected improvements. With this in mind, the 2009 

investigation made PV more agnostic by starting with a current reference value defined by the 

dominant technologies in the market, but then letting experts predict cost decreases on the 

technology as a whole, while still prescribing the utility, commercial, and residential market 

breakdown. 
25 

3.4 Confidence in Results

The 2009 risk assessment is the second such analysis conducted by the Solar Program. Lessons 

learned from the 2008 assessment were implemented to improve confidence in the data provided. 

For example, additional time and effort was made to improve participation, resulting in greater 

breadth of technical knowledge. With respect to CSP, tower technology was added to the 2009 

analysis. Furthermore, greater emphasis was placed on explaining the process of completing 

score sheets, helping to ensure experts were properly inputting their projections. With these 

changes instituted, the risk team is more confident that 2009 results paint a helpful picture of 

future technology costs. On the PV side, the lack of participation and estimates from enough 

experts on inverter costs and lifetime leads the risk team to not be confident in the results for 

these metrics, and to suggest future analyses focus more heavily on these areas.
A-1 

Appendix A: Concentrating Solar Power (Trough) Risk Analysis, 

Summary of @Risk Results—Fan Diagrams

The following figures include projections of future improvement between 2009 and 2025: 

1) Baseline: The aggregated expert team risk distributions, shown for the 10%, 50%, and 

90% scenarios, assuming no DOE R&D funding of the technology 

2) DOE or Expanded: 

a) DOE planned―The first figure in each set shows the aggregated expert team risk 

distributions, shown for the 10%, 50%, and 90% scenarios, assuming the planned 

DOE R&D funding. 

b) DOE expanded―The second figure in each set shows the aggregated expert team risk 

distributions, shown for the 10%, 50%, and 90% scenarios, assuming expanded DOE 

R&D funding. 

In some cases the following is provided: 

1) Program goal―In some (but not all) figures, a point estimate trajectory of improvements 

formulated assuming that the Program achieves its goals (i.e., this information has 

typically been provided by the U.S. Department of Energy’s Office of Energy Efficiency 

and Renewable Energy (EERE) programs in prior years, and is input into SEDS, NEMS, 

and MARKAL for market penetration modeling and program benefits calculations). 

A.1 CSP Trough—Solar Field Curves

CSP- Trough with Storage- Solar Field Cost 

Probability Distributions under Different Funding Scenarios

1,500

1,700

1,900

2,100

2,300

2,500

2,700

2,900

3,100

3,300

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure A1. Solar field cost-probability distributions for CSP trough with storage

In Figure A1, the no DOE budget does not diverge greatly from the DOE Planned Budget, 

implying that experts believe noticeable solar field cost reductions will occur from industry 

activity alone. When expanding the budget, experts envisage an additional cost reduction of 

more than 10% in 2025 (based on the 50th percentile) relative to the planned funding level (i.e., 

$2285/kW to $2038/kW). 
A-2 

A.2 CSP Trough—Heat Transfer Fluid Curves

CSP- Trough with Storage- HTF Cost 

Probability Distributions under Different Funding Scenarios

40

60

80

100

120

140

160

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure A2. Heat transfer fluid cost-probability distributions for CSP trough with storage

Based on the 50th percentile planned and expanded funding scenarios in Figure A2, experts 

indicate that HTF cost reduction will be minimal between 2010 and 2015, become more 

prominent between 2015 and 2020, and then decelerate, but continue its downward trend 

between 2020 and 2025. The 10th percentile trajectories show that, though not certain to occur, 

even more significant improvements could be realized by 2025 with planned or expanded DOE 

funding levels (i.e., a reduction of nearly 70% from the 2009 reference value). 

A.3 CSP Trough—Thermal Energy Storage Curves

CSP- Trough with Storage- TES Cost 

Probability Distributions under Different Funding Scenarios

10

15

20

25

30

35

40

45

50

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50% DOE Planned 90% DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure A3. Thermal energy storage—probability distributions for CSP trough with storage
A-3 

Based on Figure A3, the experts suggest almost no to very little cost reduction would occur 

under the no DOE budget case. However, the experts predict a substantial reduction in TES cost 

will occur due to R&D funding, with the greatest impact between 2020 and 2025 under planned 

DOE funding, and accelerated five years sooner with the expanded budget. By 2025, the 

difference between the no DOE and planned funding scenario is almost $8/kWht ($36.4/kWht to 

$28.7kWht based on the 50th percentile), with the expanded budget resulting in even greater 

reductions to $22.5/kWht, or ~40% below the no DOE funding scenario. 

A.4 CSP Trough—Power Block & Balance of System Curves

CSP- Trough with Storage- PB&BOS Cost 

Probability Distributions under Different Funding Scenarios

600

700

800

900

1,000

1,100

1,200

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure A4. Power block & balance of system—probability distributions for CSP trough with 

storage 

Figure A4 reveals the experts’ viewpoint that very little PB&BOS improvements can occur 

without DOE funding (i.e., less than 10% at the 50th percentile). Furthermore, the planned and 

expanded funding levels will allow for only slightly greater cost reductions (i.e., 15% and 20%, 

respectively, at the 50th percentile). 
A-4 

A.5 CSP Trough—Operations and Maintenance Curves

CSP- Trough with Storage- O&M Cost 

Probability Distributions under Different Funding Scenarios

30.0

35.0

40.0

45.0

50.0

55.0

60.0

65.0

70.0

75.0

80.0

2005 2010 2015 2020 2025 2030

$/kW-yr

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure A5. O&M—Probability distributions for CSP trough with storage

Although a noticeable O&M cost reduction is anticipated when viewing Figure A5, expert input 

reveals that the Program goal is an aggressive target. The experts suggest that there is only about 

a 20% chance that the 2015 and 2025 Program goals for O&M will be achieved under the DOE 

planned funding scenario. Under the expanded case, these percent likelihoods increase to 30% 

for both 2015 and 2025 (see appendix F for details). 
B-1 

Appendix B: Concentrating Solar Power (Tower) Risk Analysis, 

Summary of @Risk Results—Fan Diagrams

The figures below include projections of future improvement between 2009 and 2025: 

1) Baseline: The aggregated Expert Team risk distributions, shown for the 10%, 50%, and 

90% scenarios, assuming no DOE R&D funding of the technology; 

2) DOE or Expanded: 

a. DOE planned: The first figure in each set shows the aggregated Expert Team risk 

distributions, shown for the 10%, 50% and 90% scenarios, assuming the planned 

DOE R&D funding. 

b. DOE expanded- the second figure in each set shows the aggregated Expert Team 

risk distributions, shown for the 10%, 50% and 90% scenarios, assuming 

expanded DOE R&D funding. 

3) Program goal: In some (but not all) figures, a point estimate trajectory of improvements 

formulated assuming that the Program achieves its goals (i.e., this information has 

typically been provided by the U.S. Department of Energy’s Office of Energy Efficiency 

and Renewable Energy (EERE) programs in prior years, and is input into SEDS, NEMS, 

and MARKAL for market penetration modeling and program benefits calculations).

B.1 CSP Tower—Solar Field Curves

CSP- Power Tower with Storage- Solar Field Cost 

Probability Distributions under Different Funding Scenarios

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure B1. Solar field cost-probability distributions for CSP tower with storage

The 50th percentile slopes representing tower solar field cost are not overly steep, indicating a 

gradual decline in cost out to 2025. Under the planned DOE budget, experts foresee at least a 

50% chance of reducing the cost below $1,700/kW and a 10% chance of reaching $1500/kW. 

Additional improvements with an expanded budget can be shown in two ways: 1) the increased 

likelihood of achieving those same costs (i.e., 63% and 38%, respectively), or 2) the additional 

cost reductions at the same probability levels (i.e. $1623/kW and $1287/kW, respectively). 
B-2 

B.2 CSP Tower—Receiver Curves

CSP- Power Tower with Storage- Receiver Cost 

Probability Distributions under Different Funding Scenarios

550

600

650

700

750

800

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure B2. Receiver cost-probability distributions for CSP tower with storage

Although a lower receiver cost is believed to be achievable in 2015 and 2020 when comparing 

the 50th percentile planned budget and no budget scenarios, by 2025 the two scenarios will result 

in roughly the same cost (~700$/kW). On the other hand, an expanded budget is expected to 

have a bigger impact on lowering receiver costs throughout the timeframe of this analysis. 

B.3 CSP Tower—Thermal Energy Storage Curves

CSP- Power Tower with Storage- TES Cost 

Probability Distributions under Different Funding Scenarios

10

11

12

13

14

15

16

17

18

19

20

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure B3. Thermal energy storage-probability distributions for CSP tower with storage
B-3 

Experts are not under the impression that tower thermal energy storage costs will decrease much 

over time, as signified by the relatively flat 50th percentile lines. This seems to be the case even 

with an expanded budget. 

B.4 CSP Tower—Power Block & Balance of System Curves

CSP- Power Tower with Storage- PB&BOS Cost 

Probability Distributions under Different Funding Scenarios

800

850

900

950

1,000

1,050

1,100

1,150

1,200

2005 2010 2015 2020 2025 2030

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure B4. Power block & balance of system-probability distributions for CSP tower with storage

The tower PB&BOS no funding and planned funding cases do not differ much when viewing the 

50th percentile inputs. This is also the case when comparing the planned and expanded cases. 

Cost reductions for the three funding scenarios are modest, except when considering the 10th

percentile. In other words, experts believe there is a relatively low likelihood that PB&BOS 

costs will decrease substantially throughout the timeframe.
B-4 

B.5 CSP Tower—Operations & Maintenance Curves

CSP- Power Tower with Storage- O&M Cost 

Probability Distributions under Different Funding Scenarios

40

45

50

55

60

65

70

75

80

2005 2010 2015 2020 2025 2030

$/kW-yr

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure B5. O&M-probability distributions for CSP tower with storage

The results of the expert elicitation suggest that the Program’s O&M goal is very aggressive, as 

the goal trajectory (light blue line) falls around the 10-20% probability levels from 2015-2025. 
C-1 

Appendix C: Photovoltaic (PV) Risk Analysis, Summary of @Risk 

Results—Fan Diagrams

1) The figures below include projections of future improvement between 2009 and 2020: 

2) Baseline: The aggregated Expert Team risk distributions, shown for the 10%, 50%, and 

90% scenarios, assuming no DOE R&D funding of the technology; 

3) DOE or Expandeda. DOE planned – The first figure in each set shows the aggregated Expert Team 

risk distributions, shown for the 10%, 50%, and 90% scenarios, assuming the 

planned DOE R&D funding; 

b. Expanded – The second figure in each set shows the aggregated Expert Team risk 

distributions, shown for the 10%, 50%, and 90% scenarios, assuming expanded 

DOE R&D funding. 

In some cases the following is provided: 

4. Program goal: In some (but not all) figures, a point estimate trajectory of improvements 

formulated assuming that the Program achieves its goals (i.e., this information has 

typically been provided by the U.S. Department of Energy’s Office of Energy Efficiency 

and Renewable Energy (EERE) programs in prior years, and is input into SEDS, NEMS, 

and MARKAL for market penetration modeling and program benefits calculations).

C.1 Photovoltaic—Inverter Lifetime Curves 

PV - Utility Scale - Inverter Lifetime

Probability Distributions under Different Funding Scenarios

5

10

15

20

25

30

2005 2010 2015 2020 2025

Years

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C1. Inverter lifetime-probability distributions for PV utility

Figure C1 shows that technology experts believe improvements in utility scale inverter lifetime 

have a low probability of achieving or exceeding the Program goal value of 20 years by 2020 

(i.e., 15% chance with no DOE funding, 20% chance with planned DOE funding, and a 33% 

chance with expanded DOE funding). Another noticeable trend is that only minor improvements 
C-2 

are anticipated over time between the three funding scenarios, as the experts noted little DOE 

R&D activities in this area. 

Furthermore, for all of the aggregated 10th percentile cases, the inverter lifetimes are held 

constant at the current (2009) reference value of 10 years. This is partly because in some cases 

the experts actually provided distributions that resulted in a decrease in inverter lifetime from the 

current reference case. For the 2009 Solar Risk Assessment, the @Risk model was designed to 

truncate a “negative improvement or “worst case” and refer to the current reference value when 

aggregating all expert distributions, unless a specific reason for a performance decrease or cost 

increase was cited by the expert (i.e., R&D funding should not result in a worse technology over 

time, unless tradeoffs between metrics, such as a lower lifetime to achieve a much lower costs 

are considered). 

PV - Commercial Scale - Inverter Lifetime

Probability Distributions under Different Funding Scenarios

5

10

15

20

25

30

2005 2010 2015 2020 2025

Years

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10%

DOE Planned 50% DOE Planned 90% Program Goal DOE Expanded 10%

DOE Expanded 50% DOE Expanded 90%

Figure C2. Inverter lifetime-probability distributions for PV commercial

As shown in Figure C2, again the experts suggest that the Program goals for commercial scale 

inverter lifetime are very aggressive (i.e., 2% chance with no DOE funding, 5% chance with 

planned DOE funding, and a 28% chance with expanded DOE funding). Additionally, only 

minor improvements are anticipated over time between the no DOE case and the DOE planned 

case, again reflecting the lack of a large dedicated DOE R&D program focused on inverters. As 

in the Utility scale analysis, the 10th percentile distributions for inverter lifetimes are held 

constant at ten years under the three funding conditions. Similar trends can be seen in the 

Residential Scale inverter lifetime analysis in Figure C3. 
C-3 

PV - Residential Scale - Inverter Lifetime

Probability Distributions under Different Funding Scenarios

0.0

5.0

10.0

15.0

20.0

25.0

2005 2010 2015 2020 2025

Years

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C3. Inverter lifetime-probability distributions for PV residential 

C.2 Photovoltaic—Inverter Replacement Cost Curves 

PV - Utility Scale - Inverter Replacement Cost

Probability Distributions under Different Funding Scenarios

$100

$150

$200

$250

$300

$350

$400

$450

$500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C4. Inverter replacement cost-probability distributions for PV utility

Figure C4 expresses utility scale PV inverter replacement costs decreasing as funding levels are 

increased and over time. Even though expanded funding should allow for deeper cost 

reductions, it will unlikely be enough to achieve the 2015 or 2020 Program goals. Similar trends 

can be seen in Figure C5 for commercial scale PV inverter replacement costs. 
C-4 

PV - Commercial Scale - Inverter Replacement Cost

Probability Distributions under Different Funding Scenarios

$100

$150

$200

$250

$300

$350

$400

$450

$500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C5. Inverter replacement cost-probability distributions for PV commercial

PV - Residential Scale - Inverter Replacement Cost

Probability Distributions under Different Funding Scenarios

$100

$200

$300

$400

$500

$600

$700

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C6. Inverter replacement cost-probability distributions for PV residential

Figure C6 exhibits a gradual reduction in residential inverter replacement costs through time. 

Expanded funding does not show a noticeable difference when compared to the no DOE funding 

scenario, and while all three funding cases are more than likely to exceed the 2020 Program goal 

value, only the expanded DOE funding case has a greater than 50% chance of exceeding the 

2015 Program goal value. 
C-5 

C.3 Photovoltaic—Module Cost Curves

Figures C7 through C9, representing utility, commercial and residential module cost 

distributions, respectively, show noticeable cost reductions through time, and as funding levels 

are increased. One interesting note is that module costs for all three market sectors are forecast 

to be quite similar by 2020, suggesting the higher margins in the residential and commercial 

sectors will start to come more in line with the utility sector. 

Though no specific Program goal trajectory is plotted on these graphs, since these trajectories are 

forecast at the system level and not for modules, an oft cited target for modules is $1/W (i.e., 

$1000/kW). As can be seen in the Figures C7 through C9, the likelihoods of module costs 

hitting this target are: 

1) Utility market- 17% with no DOE funding, 33% with planned DOE funding and 53% 

with expanded DOE funding; 

2) Commercial market- 17% with no DOE funding, 28% with planned DOE funding and 

47% with expanded DOE funding; and 

3) Residential market- 12% with no DOE funding, 19% with planned DOE funding and 

40% with expanded DOE funding. 

PV- Utility Scale- Module Cost 

Probability Distributions under Different Funding Scenarios

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C7. Module cost-probability distributions for PV utility
C-6 

PV- Commercial Scale- Module Cost 

Probability Distributions under Different Funding Scenarios

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C8. Module Cost-Probability Distributions for PV Commercial

PV- Residential Scale- Module Cost 

Probability Distributions under Different Funding Scenarios

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

2005 2010 2015 2020 2025

$/kW

No DOE 10% No DOE 50% No DOE 90%

DOE Planned 10% DOE Planned 50% DOE Planned 90%

DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C9. Module cost-probability distributions for PV residential

C.4 Photovoltaic—Operations and Maintenance Cost Curves

Figures C10 through C12 illustrate that significant reductions in PV O&M costs are likely for the 

Utility, Commercial, and Residential market sectors. However, without DOE funding, the 2015 

and 2020 Program goals have a low probability of success. Furthermore, experts do not foresee 

substantial differences in O&M cost when going from planned to expanded DOE funding levels, 

indicating that expanded budget activities focusing on O&M improvements might not provide an 

optimal return on investment. 
C-7 

PV - Utility Scale - O&M Cost

Probability Distributions under Different Funding Scenarios

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2005 2010 2015 2020 2025

$/kW-yr

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C10. O&M cost-probability distributions for PV utility

PV - Commercial Scale - O&M Cost

Probability Distributions under Different Funding Scenarios

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

2005 2010 2015 2020 2025

$/kW-yr

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C11. O&M cost-probability distributions for PV commercial
C-8 

PV - Residential Scale - O&M Cost

Probability Distributions under Different Funding Scenarios

0.0

10.0

20.0

30.0

40.0

50.0

60.0

2005 2010 2015 2020 2025

$/kW-yr

No DOE 10% No DOE 50% No DOE 90% DOE Planned 10% DOE Planned 50%

DOE Planned 90% Program Goal DOE Expanded 10% DOE Expanded 50% DOE Expanded 90%

Figure C12. O&M cost-probability distributions for PV residential
D-1 

Appendix D: Concentrating Solar Power (CSP) Risk Analysis, 

Summary of @Risk Results—Aggregated Probability 

Distributions 

D.1 Technical Risk and Uncertainty Analysis—Solar Utility CSP Trough 

The following figures represent the aggregated total system costs provided by the experts in the 

three budget scenarios for CSP Utility - Trough with Storage ($0, $30M, and $60M). 

 

The three colored lines in each of these graphs represent the aggregated expert inputs for the 

three time periods for CSP Utility—Trough with Storage (2015, 2020, and 2025). In each of the 

graphs, the 2009 reference values are represented by the black line on the right of the graphs, and 

the FY10 GPRA Program goal-based input value for 2015 is represented by the delimiter (i.e., 

thin black vertical lines) on the left of each graph. The percentages to the left side of the 

delimiter represent the likelihood of at least achieving the “goal-based” value. The percentages 

between the delimiters represent the likelihood of improving to somewhere between the “goalbased” value and reference value. Furthermore, the key to the right of each graph also lists the 

minimum, maximum, and mean for each aggregated distribution. 
D-2 

Total System Cost-by Funding Level 

0.0% 5.0%

0.0% 72.9%

7.1% 87.1%

34.4% 64.5%

5.025 6.443

3.54.04.55.05.56.06.5

Values in Thousands

0.000

0.002

0.004

0.006

0.008

0.010

0.012

Total System Cost ($/kW) - Trough Only

Reference Total System 

Cost ($/kW)

Minimum 6443.0000

Maximum 6443.0000

Mean 6443.0000

Aggregated Experts- 2015- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 5044.1272

Maximum 6443.9213

Mean 6136.4611

Aggregated Experts- 2020- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 4321.0003

Maximum 6443.9213

Mean 5793.7204

Aggregated Experts- 2025- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 3677.9169

Maximum 6443.9213

Mean 5385.8874

3.03.54.04.55.05.56.06.5
D-3 

2.53.03.54.04.55.05.56.06.5
D-4 

0.0% 5.0% 95.0%

1.5% 98.5% 0.0%

16.3% 83.7% 0.0%

32.9% 67.1% 0.0%

2.250 3.052

Values in Thousands

0.000

0.005

0.010

0.015

0.020

0.025

Solar Field Cost ($/kW) - Trough Only

Reference Solar Field Cost 

($/kW)

Minimum 3052.0000

Maximum 3052.0000

Mean 3052.0000

Aggregated Experts- 2015- 

No DOE R&D- Solar Field 

Cost ($/kW)- T

Minimum 2177.0652

Maximum 3052.0000

Mean 2871.0526

Aggregated Experts- 2020- 

No DOE R&D- Solar Field 

Cost ($/kW)- T

Minimum 1790.8615

Maximum 3052.0000

Mean 2669.2521

Aggregated Experts- 2025- 

No DOE R&D- Solar Field 

Cost ($/kW)- T

Minimum 1522.5698

Maximum 3052.0000

Mean 2463.4298

0.0% 5.0% 95.0%

12.9% 87.1% 0.0%

28.3% 71.7% 0.0%

47.9% 52.1% 0.0%

2.250 3.052

Values in Thousands

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

Solar Field Cost ($/kW) - Trough Only

Reference Solar Field Cost 

($/kW)

Minimum 3052.0000

Maximum 3052.0000

Mean 3052.0000

Aggregated Experts- 2015- 

Planned DOE R&D- Solar 

Field Cost ($/k

Minimum 1950.9940

Maximum 3052.0000

Mean 2775.3234

Aggregated Experts- 2020- 

Planned DOE R&D- Solar 

Field Cost ($/k

Minimum 1688.9454

Maximum 3052.0000

Mean 2508.1931

Aggregated Experts- 2025- 

Planned DOE R&D- Solar 

Field Cost ($/k

Minimum 1466.3834

Maximum 3052.0000

Mean 2270.8305

Solar Field Cost-by Funding Level 
D-5 
D-6 

708090

100110120130140150160

406080

100120140160

HTF/Receiver Cost-by Funding Level 
D-7 
D-8 

TES Cost-by Funding Level 
D-9 
D-10 

PB&BOS Cost-by Funding Level 
D-11 

0.600.650.700.750.800.850.900.951.001.051.101.15

0.10.20.30.40.50.60.70.80.91.01.11.2
D-12 

0.0% 5.0% 95.0%

19.7% 80.3% 0.0%

49.8% 50.2% 0.0%

75.7% 24.3% 0.0%

62.3 74.0

0.0

0.1

0.2

0.3

0.4

0.5

0.6

O&M ($/kW-yr) - Trough Only

Reference O&M ($/kW-yr)

Minimum 74.0000

Maximum 74.0000

Mean 74.0000

Aggregated Experts- 2015- 

Planned DOE R&D- O&M 

($/kW-yr)- Trough

Minimum 43.7480

Maximum 74.0000

Mean 68.2752

Aggregated Experts- 2020- 

Planned DOE R&D- O&M 

($/kW-yr)- Trough

Minimum 10.6043

Maximum 74.0000

Mean 60.0781

Aggregated Experts- 2025- 

Planned DOE R&D- O&M 

($/kW-yr)- Trough

Minimum 10.4454

Maximum 74.0000

Mean 53.3231

0.0% 5.0% 95.0%

28.7% 71.3% 0.0%

70.0% 30.0% 0.0%

84.8% 15.2% 0.0%

62.3 74.0

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

O&M ($/kW-yr) - Trough Only

Reference O&M ($/kW-yr)

Minimum 74.0000

Maximum 74.0000

Mean 74.0000

Aggregated Experts- 2015- 

Expanded DOE R&D- O&M 

($/kW-yr)- Troug

Minimum 29.9813

Maximum 74.0000

Mean 66.1139

Aggregated Experts- 2020- 

Expanded DOE R&D- O&M 

($/kW-yr)- Troug

Minimum 10.6083

Maximum 74.0000

Mean 56.4426

Aggregated Experts- 2025- 

Expanded DOE R&D- O&M 

($/kW-yr)- Troug

Minimum 10.4579

Maximum 74.0000

Mean 49.3678

O&M System Cost-by Funding Level 
D-13 

D.2 Technical Risk and Uncertainty Analysis-Solar Utility CSP Tower 

The following figures represent the aggregated total system costs provided by the experts in the 

three budget scenarios for CSP Utility - Tower with Storage ($0, $30M, and $60M). 

 

The three colored lines in each of these graphs represent the aggregated expert inputs for the 

three time periods for CSP Utility—Tower with Storage (2015, 2020, and 2025). In each of the 

graphs, the 2009 reference values are represented by the black line on the right of the graphs, and 

the FY10 GPRA Program goal-based input value for 2015 is represented by the delimiter (i.e., 

thin black vertical lines) on the left of each graph. The percentages to the left side of the 

delimiter represent the likelihood of at least achieving the “goal-based” value. The percentages 

between the delimiters represent the likelihood of improving to somewhere between the “goalbased” value and reference value. Furthermore, the key to the right of each graph also lists the 

minimum, maximum, and mean for each aggregated distribution. 
D-14 

Total System Cost-by Funding Level 

0.0% 5.0% 95.0%

17.8% 82.2% 0.0%

50.4% 49.6% 0.0%

73.5% 26.5% 0.0%

5.025 5.644

3.84.04.24.44.64.85.05.25.45.65.8

Values in Thousands

0.000

0.002

0.004

0.006

0.008

0.010

0.012

Total System Cost ($/kW) - Tower Only

Reference Total System 

Cost ($/kW)

Minimum 5644.0000

Maximum 5644.0000

Mean 5644.0000

Aggregated Experts- 2015- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 4584.1368

Maximum 5313.7931

Mean 5141.5380

Aggregated Experts- 2020- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 4342.1433

Maximum 5313.7931

Mean 5018.0592

Aggregated Experts- 2025- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 3951.8203

Maximum 5313.7931

Mean 4826.5672

 

0.0% 5.0% 95.0%

42.2% 57.8% 0.0%

70.8% 29.2% 0.0%

88.4% 11.6% 0.0%

5.025 5.644

3.84.04.24.44.64.85.05.25.45.65.8

Values in Thousands

0.0000

0.0005

0.0010

0.0015

0.0020

0.0025

0.0030

0.0035

Total System Cost ($/kW) - Tower Only

Reference Total System 

Cost ($/kW)

Minimum 5644.0000

Maximum 5644.0000

Mean 5644.0000

Aggregated Experts- 2015- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 4435.5731

Maximum 5313.7931

Mean 5048.0368

Aggregated Experts- 2020- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 4191.2171

Maximum 5313.7931

Mean 4888.5655

Aggregated Experts- 2025- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 3812.8213

Maximum 5313.7931

Mean 4684.3237
D-15 
D-16 

Solar Field Cost-by Funding Level 
D-17 

1.11.21.31.41.51.61.71.81.92.0
D-18 

5.0% 95.0%

100.0% 0.0%

100.0% 0.0%

100.0% 0.0%

110.0 780.0

0.00

0.02

0.04

0.06

0.08

0.10

0.12

Receiver Cost ($/kW) - Tower Only

Reference HTF Cost ($/kW)

Minimum 780.0000

Maximum 780.0000

Mean 780.0000

Aggregated Experts- 2015- 

No DOE R&D- HTF Cost 

($/kW)- Tower wit

Minimum 534.4842

Maximum 780.0000

Mean 761.9947

Aggregated Experts- 2020- 

No DOE R&D- HTF Cost 

($/kW)- Tower wit

Minimum 536.0302

Maximum 780.0000

Mean 742.8579

Aggregated Experts- 2025- 

No DOE R&D- HTF Cost 

($/kW)- Tower wit

Minimum 535.5883

Maximum 780.0000

Mean 709.1344

HTF/Receiver Cost-by Funding Level 500 550 600 650

700750800
D-19 
D-20 

TES Cost-by Funding Level 

5.0% 0.0%

100.0% 0.0%

100.0% 0.0%

100.0% 0.0%

16.000

14.414.614.815.015.215.415.615.816.016.2

0

5

10

15

20

25

30

TES Cost ($/kWt) - Tower Only

Reference TES Cost ($/kWt)

Minimum 16.0000

Maximum 16.0000

Mean 16.0000

Aggregated Experts- 2015- 

No DOE R&D- TES Cost 

($/kWt)- Tower wi

Minimum 14.6361

Maximum 16.0000

Mean 15.9285

Aggregated Experts- 2020- 

No DOE R&D- TES Cost 

($/kWt)- Tower wi

Minimum 14.6251

Maximum 16.0000

Mean 15.8954

Aggregated Experts- 2025- 

No DOE R&D- TES Cost 

($/kWt)- Tower wi

Minimum 14.4369

Maximum 16.0000

Mean 15.8375

5.0% 0.0%

100.0% 0.0%

100.0% 0.0%

100.0% 0.0%

16.000

14.214.414.614.815.015.215.415.615.816.016.2

0

2

4

6

8

10

12

14

16

18

TES Cost ($/kWt) - Tower Only

Reference TES Cost ($/kWt)

Minimum 16.0000

Maximum 16.0000

Mean 16.0000

Aggregated Experts- 2015- 

Planned DOE R&D- TES 

Cost ($/kWt)- Tow

Minimum 14.2332

Maximum 16.0000

Mean 15.8435

Aggregated Experts- 2020- 

Planned DOE R&D- TES 

Cost ($/kWt)- Tow

Minimum 14.2441

Maximum 16.0000

Mean 15.7884

Aggregated Experts- 2025- 

Planned DOE R&D- TES 

Cost ($/kWt)- Tow

Minimum 14.2470

Maximum 16.0000

Mean 15.7335
D-21 

5.0% 0.0%

100.0% 0.0%

100.0% 0.0%

100.0% 0.0%

16.00

89

1011121314151617

0

2

4

6

8

10

12

14

16

TES Cost ($/kWt) - Tower Only

Reference TES Cost ($/kWt)

Minimum 16.0000

Maximum 16.0000

Mean 16.0000

Aggregated Experts- 2015- 

Expanded DOE R&D- TES 

Cost ($/kWt)- To

Minimum 13.9081

Maximum 16.0000

Mean 15.7937

Aggregated Experts- 2020- 

Expanded DOE R&D- TES 

Cost ($/kWt)- To

Minimum 12.2387

Maximum 16.0000

Mean 15.6869

Aggregated Experts- 2025- 

Expanded DOE R&D- TES 

Cost ($/kWt)- To

Minimum 8.7652

Maximum 16.0000

Mean 15.2536
D-22 

PB&BOS Cost-by Funding Level 

0.0% 5.0%

2.8% 97.2%

7.7% 92.3%

17.5% 82.6%

1.0000 1.1360

0.800.850.900.951.001.051.101.15

Values in Thousands

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

PB&BOS Cost ($/kW) - Tower Only

Reference PB&BOS Cost 

($/kW)

Minimum 1136.0000

Maximum 1136.0000

Mean 1136.0000

Aggregated Experts- 2015- 

No DOE R&D- PB&BOS Cost 

($/kW)- Tower 

Minimum 879.8534

Maximum 1136.0000

Mean 1109.6565

Aggregated Experts- 2020- 

No DOE R&D- PB&BOS Cost 

($/kW)- Tower 

Minimum 826.1622

Maximum 1136.0000

Mean 1091.0086

Aggregated Experts- 2025- 

No DOE R&D- PB&BOS Cost 

($/kW)- Tower 

Minimum 804.9251

Maximum 1136.0000

Mean 1068.2468

0.0% 5.0%

6.1% 93.9%

14.1% 85.9%

29.8% 70.2%

1.0000 1.1360

0.750.800.850.900.951.001.051.101.15

Values in Thousands

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.045

PB&BOS Cost ($/kW) - Tower Only

Reference PB&BOS Cost 

($/kW)

Minimum 1136.0000

Maximum 1136.0000

Mean 1136.0000

Aggregated Experts- 2015- 

Planned DOE R&D- PB&BOS 

Cost ($/kW)- T

Minimum 797.2242

Maximum 1136.0000

Mean 1096.7517

Aggregated Experts- 2020- 

Planned DOE R&D- PB&BOS 

Cost ($/kW)- T

Minimum 774.9171

Maximum 1136.0000

Mean 1075.3256

Aggregated Experts- 2025- 

Planned DOE R&D- PB&BOS 

Cost ($/kW)- T

Minimum 750.6203

Maximum 1136.0000

Mean 1042.7736
D-23 

0.0% 5.0%

12.5% 87.5%

26.9% 73.1%

41.1% 58.9%

1.0000 1.1360

0.650.700.750.800.850.900.951.001.051.101.15

Values in Thousands

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.045

0.050

PB&BOS Cost ($/kW) - Tower Only

Reference PB&BOS Cost 

($/kW)

Minimum 1136.0000

Maximum 1136.0000

Mean 1136.0000

Aggregated Experts- 2015- 

Expanded DOE R&DPB&BOS Cost ($/kW)- 

Minimum 841.0408

Maximum 1136.0000

Mean 1085.4926

Aggregated Experts- 2020- 

Expanded DOE R&DPB&BOS Cost ($/kW)- 

Minimum 758.2313

Maximum 1136.0000

Mean 1048.6277

Aggregated Experts- 2025- 

Expanded DOE R&DPB&BOS Cost ($/kW)- 

Minimum 679.9759

Maximum 1136.0000

Mean 1002.9171
D-24 

O&M System Cost-by Funding Level 

0.0% 5.0% 95.0%

6.0% 94.0% 0.0%

15.5% 84.5% 0.0%

32.6% 67.4% 0.0%

62.30 77.00

3035404550556065707580

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

O&M ($/kW-yr) - Tower Only

Reference O&M ($/kW-yr)

Minimum 77.0000

Maximum 77.0000

Mean 77.0000

Aggregated Experts- 2015- 

No DOE R&D- O&M ($/kWyr)- Tower with 

Minimum 44.8397

Maximum 76.9000

Mean 74.2134

Aggregated Experts- 2020- 

No DOE R&D- O&M ($/kWyr)- Tower with 

Minimum 41.9406

Maximum 76.9000

Mean 71.1892

Aggregated Experts- 2025- 

No DOE R&D- O&M ($/kWyr)- Tower with 

Minimum 32.6033

Maximum 76.9000

Mean 67.2807

0.0% 5.0% 95.0%

13.6% 86.4% 0.0%

25.9% 74.1% 0.0%

46.6% 53.4% 0.0%

62.30 77.00

3035404550556065707580

0.0

0.1

0.2

0.3

0.4

0.5

0.6

O&M ($/kW-yr) - Tower Only

Reference O&M ($/kW-yr)

Minimum 77.0000

Maximum 77.0000

Mean 77.0000

Aggregated Experts- 2015- 

Planned DOE R&D- O&M 

($/kW-yr)- Tower 

Minimum 34.4348

Maximum 76.9000

Mean 71.4756

Aggregated Experts- 2020- 

Planned DOE R&D- O&M 

($/kW-yr)- Tower 

Minimum 35.2166

Maximum 76.9000

Mean 67.7895

Aggregated Experts- 2025- 

Planned DOE R&D- O&M 

($/kW-yr)- Tower 

Minimum 33.4258

Maximum 76.9000

Mean 63.4135

 
D-25 

0.0% 5.0% 95.0%

17.5% 82.6% 0.0%

37.8% 62.2% 0.0%

57.0% 43.0% 0.0%

62.30 77.00

3035404550556065707580

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

0.50

O&M ($/kW-yr) - Tower Only

Reference O&M ($/kW-yr)

Minimum 77.0000

Maximum 77.0000

Mean 77.0000

Aggregated Experts- 2015- 

Expanded DOE R&D- O&M 

($/kW-yr)- Tower

Minimum 32.3568

Maximum 76.9000

Mean 70.1418

Aggregated Experts- 2020- 

Expanded DOE R&D- O&M 

($/kW-yr)- Tower

Minimum 34.3677

Maximum 76.9000

Mean 66.0572

Aggregated Experts- 2025- 

Expanded DOE R&D- O&M 

($/kW-yr)- Tower

Minimum 34.4295

Maximum 76.9000

Mean 61.2551
E-1 

Appendix E: Photovoltaic (PV) Risk Analysis, Summary of @Risk 

Results—Aggregated Probability Distributions 

E.1 Technical Risk and Uncertainty Analysis: Solar PV - Utility 

The following figures represent the aggregated module costs, inverter costs, total system cost, 

O&M costs, inverter lifetimes, and learning by doing (LBD) ranges provided by the experts in 

the three budget scenarios for PV Utility ($0, $140M, and $280M). 

 

The three colored lines in each of these graphs represent the aggregated expert inputs for the 

three time periods for PV Utility (2010, 2015, and 2020). In each of the graphs, the 2009 

reference values are represented by the black line on the right of the graphs, and the FY10 GPRA 

Program goal-based input value for 2015 is represented by the delimiter (i.e., thin black vertical 

lines) on the left of each graph. The percentages to the left side of the delimiter represent the 

likelihood of at least achieving the “goal-based” value. The percentages between the delimiters 

represent the likelihood of improving to somewhere between the “goal-based” value and 

reference value. Furthermore, the key to the right of each graph also lists the minimum, 

maximum, and mean for each aggregated distribution. 
E-2 

Module Cost—by Funding Level 

0.0% 5.0% 95.0%

9.8% 83.6% 6.7%

29.8% 67.6% 2.6%

49.3% 49.0% 1.7%

1.500 3.000

0.00.51.01.52.02.53.03.54.04.55.0

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

0.0016

0.0018

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3000.0000

Maximum 3000.0000

Mean 3000.0000

Aggregated Experts- 2010- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 504.4298

Maximum 4547.3309

Mean 2341.7122

Aggregated Experts- 2015- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 500.9252

Maximum 4430.6032

Mean 1845.2217

Aggregated Experts- 2020- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 300.4912

Maximum 4487.2472

Mean 1546.1258

0.0% 5.0% 95.0%

12.0% 85.5% 2.5%

52.0% 46.9% 1.1%

82.4% 17.4% 0.3%

1.500 3.000

0.00.51.01.52.02.53.03.54.04.55.0

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3000.0000

Maximum 3000.0000

Mean 3000.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 503.5110

Maximum 4462.8229

Mean 2110.7107

Aggregated Experts- 2015- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 505.6338

Maximum 4536.7084

Mean 1577.6312

Aggregated Experts- 2020- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 301.6360

Maximum 4177.8940

Mean 1187.4972
E-3 

0.0% 5.0% 95.0%

14.7% 83.0% 2.3%

73.7% 25.9% 0.4%

89.3% 10.7% 0.1%

1.500 3.000

0.00.51.01.52.02.53.03.54.04.5

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3000.0000

Maximum 3000.0000

Mean 3000.0000

Aggregated Experts- 2010- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 500.1604

Maximum 4490.4741

Mean 2009.6234

Aggregated Experts- 2015- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 507.0754

Maximum 4240.7358

Mean 1337.5773

Aggregated Experts- 2020- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 300.2549

Maximum 3594.0053

Mean 1018.5076
E-4 

Inverter Cost—by Funding Level 

0.0% 5.0% 95.0%

5.2% 94.6% 0.2%

12.7% 87.3% 0.0%

21.9% 78.1% 0.0%

182.5 470.0

0

50

100150200250300350400450500550

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 50.0340

Maximum 500.0614

Mean 341.1887

Aggregated Experts- 2015- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 50.6107

Maximum 491.7145

Mean 289.3685

Aggregated Experts- 2020- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 50.5316

Maximum 470.0000

Mean 257.2001

0.0% 5.0%

7.1% 92.7% 0.3%

16.8% 83.1% 0.1%

30.9% 69.1% 0.0%

182.5 470.0

0

50

100150200250300350400450500

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 50.1498

Maximum 498.3222

Mean 316.3384

Aggregated Experts- 2015- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 51.3146

Maximum 498.3222

Mean 254.1160

Aggregated Experts- 2020- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 50.1498

Maximum 470.0000

Mean 222.1987
E-5 

0.0% 5.0% 95.0%

8.5% 91.2% 0.3%

28.9% 71.1% 0.0%

48.7% 51.3% 0.0%

182.5 470.0

0

50

100150200250300350400450500550

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 51.2520

Maximum 502.6067

Mean 310.5025

Aggregated Experts- 2015- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 50.1469

Maximum 470.0000

Mean 216.5942

Aggregated Experts- 2020- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 50.2262

Maximum 470.0000

Mean 185.7143
E-6 

Total System Cost—by Funding Level 1000 1500 2000 2500 3000 3500

40004500500055006000

0.0% 5.0% 95.0%

4.5% 82.6% 12.9%

15.4% 78.5% 6.1%

32.2% 64.4% 3.5%

2750 5000

10001500200025003000350040004500500055006000

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

0.0016

0.0018

Reference Total System Cost ($/kW)

Reference Total System 

Cost ($/kW)

Minimum 5000.0000

Maximum 5000.0000

Mean 5000.0000

Aggregated Experts- 2010- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 1892.0689

Maximum 8860.9844

Mean 4449.7170

Aggregated Experts- 2015- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 1668.1757

Maximum 9055.6908

Mean 3707.0744

Aggregated Experts- 2020- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 1367.2980

Maximum 8860.9844

Mean 3242.8167
E-7 

10001500200025003000350040004500500055006000
E-8 

O&M System Cost—by Funding Level 

0.0% 5.0% 95.0%

0.1% 83.5% 16.4%

0.0% 90.5% 9.5%

0.2% 94.4% 5.4%

5.5 30.0

0

1020304050607080

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 30.0000

Maximum 30.0000

Mean 30.0000

Aggregated Experts- 2010- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 4.0133

Maximum 73.9824

Mean 28.4775

Aggregated Experts- 2015- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 5.9435

Maximum 71.7569

Mean 23.8860

Aggregated Experts- 2020- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 4.1644

Maximum 70.3191

Mean 18.9998

0.0% 5.0% 95.0%

0.1% 84.2% 15.7%

0.0% 91.8% 8.2%

2.2% 94.6% 3.2%

5.5 30.0

0

1020304050607080

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 30.0000

Maximum 30.0000

Mean 30.0000

Aggregated Experts- 2010- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 4.5346

Maximum 73.5437

Mean 27.5436

Aggregated Experts- 2015- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 5.0577

Maximum 69.3151

Mean 21.0708

Aggregated Experts- 2020- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 3.0148

Maximum 69.9650

Mean 15.0494
E-9 

0.0% 5.0% 95.0%

0.1% 87.5% 12.5%

1.3% 91.8% 6.9%

6.9% 91.0% 2.1%

5.5 30.0

0

1020304050607080

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 30.0000

Maximum 30.0000

Mean 30.0000

Aggregated Experts- 2010- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0860

Maximum 74.0957

Mean 27.0527

Aggregated Experts- 2015- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 3.0003

Maximum 66.4261

Mean 18.4177

Aggregated Experts- 2020- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 3.0034

Maximum 64.2887

Mean 13.2801
E-10 

Inverter Life—by Funding Level 

5.0% 95.0% 0.0%

57.1% 41.0% 1.9%

40.0% 48.5% 11.5%

34.2% 51.0% 14.8%

10.00 20.00

5

1015202530

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 8.8334

Maximum 23.8605

Mean 11.5894

Aggregated Experts- 2015- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 9.5615

Maximum 29.8290

Mean 13.7347

Aggregated Experts- 2020- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 10.0000

Maximum 29.7929

Mean 14.7993

5.0% 95.0% 0.0%

43.1% 53.8% 3.0%

36.0% 52.6% 11.5%

33.9% 48.2% 17.9%

10.00 20.00

5

101520253035

0.0

0.2

0.4

0.6

0.8

1.0

1.2

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 8.5763

Maximum 23.9632

Mean 12.2680

Aggregated Experts- 2015- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 9.2811

Maximum 29.8536

Mean 14.0699

Aggregated Experts- 2020- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 10.0000

Maximum 29.9997

Mean 15.2674
E-11 

5.0% 95.0% 0.0%

40.0% 56.8% 3.2%

34.6% 43.4% 22.0%

33.4% 33.9% 32.7%

10.00 20.00

5

101520253035

0.0

0.2

0.4

0.6

0.8

1.0

1.2

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

Expanded DOE R&DInverter Lifetime (y

Minimum 9.1258

Maximum 23.8408

Mean 12.6492

Aggregated Experts- 2015- 

Expanded DOE R&DInverter Lifetime (y

Minimum 10.0000

Maximum 29.8892

Mean 15.1478

Aggregated Experts- 2020- 

Expanded DOE R&DInverter Lifetime (y

Minimum 10.0000

Maximum 29.9927

Mean 16.5931
E-12 

LBD—All TPMs 

16.2% 51.2% 32.6%

10.9% 59.1% 30.0%

6.5% 49.1% 44.5%

7.0% 49.6% 43.4%

23.6% 69.9% 6.5%

0.0500 0.1500

0.0000.0750.1500.2250.300

0

2

4

6

8

10

12

14

Aggregated Experts- LBD- All TPMs

Aggregated Experts- LBDModule Cost ($/kW)- All 

Technologies

Minimum 0.000384

Maximum 0.2565

Mean 0.1154

Aggregated Experts- LBDInverter Cost ($/kW)- All 

Technologies

Minimum 0.0105

Maximum 0.1959

Mean 0.1145

Aggregated Experts- LBDTotal System Cost ($/kW)- 

All Technolog

Minimum 0.0000

Maximum 0.2624

Mean 0.1344

Aggregated Experts- LBDO&M Cost ($/kW-yr)- All 

Technologies

Minimum 0.0000

Maximum 0.2668

Mean 0.1322

Aggregated Experts- LBDInverter Lifetime (yrs)- All 

Technologi

Minimum 0.0105

Maximum 0.1894

Mean 0.0833
E-13 

E.2 Technical Risk and Uncertainty Analysis, Solar PV—Commercial 

The following figures represent the aggregated module costs, inverter costs, total system cost, 

O&M costs, inverter lifetimes, and learning by doing (LBD) ranges provided by the experts in 

the three budget scenarios for PV Commercial ($0, $140M, and $280M). 

 

The three colored lines in each of these graphs represent the aggregated expert inputs for the 

three time periods for PV Commercial (2010, 2015, and 2020). In each of the graphs, the 2009 

reference values are represented by the black line on the right of the graphs, and the FY10 GPRA 

Program goal-based input value for 2015 is represented by the delimiter (i.e., thin black vertical 

lines) on the left of each graph. The percentages to the left side of the delimiter represent the 

likelihood of at least achieving the “goal-based” value. The percentages between the delimiters 

represent the likelihood of improving to somewhere between the “goal-based” value and 

reference value. Furthermore, the key to the right of each graph also lists the minimum, 

maximum, and mean for each aggregated distribution. 
E-14 

Module Cost—by Funding Level 

0.0% 5.0% 95.0%

0.5% 95.3% 4.3%

20.4% 78.6% 1.0%

49.4% 50.1% 0.6%

1.500 3.500

0.00.51.01.52.02.53.03.54.04.55.0

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

0.0016

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3500.0000

Maximum 3500.0000

Mean 3500.0000

Aggregated Experts- 2010- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 1238.8582

Maximum 4676.3743

Mean 2706.7189

Aggregated Experts- 2015- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 699.3484

Maximum 4747.1366

Mean 2047.1185

Aggregated Experts- 2020- 

No DOE R&D- Module Cost 

($/kW)- All Te

Minimum 242.8814

Maximum 4105.5388

Mean 1526.5254

0.0% 5.0% 95.0%

0.4% 97.9% 1.7%

36.2% 63.7% 0.1%

70.9% 29.1% 0.0%

1.500 3.500

0.00.51.01.52.02.53.03.54.04.55.0

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3500.0000

Maximum 3500.0000

Mean 3500.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 1319.1059

Maximum 4583.6271

Mean 2463.5568

Aggregated Experts- 2015- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 583.1625

Maximum 4345.5334

Mean 1772.4198

Aggregated Experts- 2020- 

Planned DOE R&D- Module 

Cost ($/kW)- A

Minimum 160.1074

Maximum 3762.6790

Mean 1269.2502
E-15 

0.0% 5.0% 95.0%

1.0% 98.8% 0.1%

56.9% 43.0% 0.1%

85.5% 14.5% 0.0%

1.500 3.500

0.00.51.01.52.02.53.03.54.04.5

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

Reference Module Cost ($/kW)

Reference Module Cost 

($/kW)

Minimum 3500.0000

Maximum 3500.0000

Mean 3500.0000

Aggregated Experts- 2010- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 1348.0883

Maximum 4069.0339

Mean 2314.0559

Aggregated Experts- 2015- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 105.8857

Maximum 3832.3108

Mean 1499.8045

Aggregated Experts- 2020- 

Expanded DOE R&DModule Cost ($/kW)- 

Minimum 107.5775

Maximum 3724.3586

Mean 1072.3973
E-16 

Inverter Cost—by Funding Level 

0.0% 5.0%

0.0% 100.0% 0.0%

3.1% 96.9% 0.0%

9.4% 90.6% 0.0%

170.0 470.0

100150200250300350400450500

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 200.1249

Maximum 470.0000

Mean 382.9476

Aggregated Experts- 2015- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 137.0813

Maximum 470.0000

Mean 329.4564

Aggregated Experts- 2020- 

No DOE R&D- Inverter Cost 

($/kW)- All 

Minimum 127.6645

Maximum 470.0000

Mean 297.8119

0.0% 5.0%

0.0% 100.0% 0.0%

4.1% 95.9% 0.0%

15.0% 85.0% 0.0%

170.0 470.0

100150200250300350400450500

0.000

0.005

0.010

0.015

0.020

0.025

0.030

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 200.3258

Maximum 470.0000

Mean 362.4729

Aggregated Experts- 2015- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 133.6542

Maximum 470.0000

Mean 306.6765

Aggregated Experts- 2020- 

Planned DOE R&D- Inverter 

Cost ($/kW)-

Minimum 119.8689

Maximum 470.0000

Mean 277.6457
E-17 

0.0% 5.0%

0.0% 100.0% 0.0%

7.5% 92.5% 0.0%

20.3% 79.7% 0.0%

170.0 470.0

100150200250300350400450500

0.000

0.005

0.010

0.015

0.020

0.025

0.030

Reference Inverter Cost ($/kW)

Reference Inverter Cost 

($/kW)

Minimum 470.0000

Maximum 470.0000

Mean 470.0000

Aggregated Experts- 2010- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 200.0694

Maximum 470.0000

Mean 355.6073

Aggregated Experts- 2015- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 124.5660

Maximum 470.0000

Mean 280.3166

Aggregated Experts- 2020- 

Expanded DOE R&DInverter Cost ($/kW)

Minimum 110.1017

Maximum 470.0000

Mean 252.0893
E-18 

Total System Cost—by Funding Level 

0.0% 5.0% 95.0%

0.1% 87.6% 12.4%

6.8% 89.4% 3.8%

28.5% 69.4% 2.1%

2.40 5.50

012345678

Values in Thousands

0.0000

0.0002

0.0004

0.0006

0.0008

0.0010

0.0012

0.0014

Reference Total System Cost ($/kW)

Reference Total System 

Cost ($/kW)

Minimum 5500.0000

Maximum 5500.0000

Mean 5500.0000

Aggregated Experts- 2010- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 2335.7552

Maximum 7038.8772

Mean 4785.4175

Aggregated Experts- 2015- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 1499.0299

Maximum 7014.3420

Mean 3727.2649

Aggregated Experts- 2020- 

No DOE R&D- Total System 

Cost ($/kW)- 

Minimum 618.4827

Maximum 6975.5056

Mean 3026.3769

0.0% 5.0% 95.0%

0.5% 96.2% 3.3%

16.3% 83.2% 0.5%

54.0% 45.9% 0.1%

2.40 5.50

01234567

Values in Thousands

0.0000

0.0001

0.0002

0.0003

0.0004

0.0005

0.0006

0.0007

0.0008

0.0009

0.0010

Reference Total System Cost ($/kW)

Reference Total System 

Cost ($/kW)

Minimum 5500.0000

Maximum 5500.0000

Mean 5500.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 2126.0588

Maximum 6945.6824

Mean 4443.7286

Aggregated Experts- 2015- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 851.8119

Maximum 6962.8978

Mean 3214.7435

Aggregated Experts- 2020- 

Planned DOE R&D- Total 

System Cost ($/

Minimum 504.9096

Maximum 5948.2541

Mean 2401.4138
E-19 

0.0% 5.0% 95.0%

0.6% 98.1% 1.3%

25.6% 74.0% 0.3%

64.1% 35.9% 0.0%

2.40 5.50

01234567

Values in Thousands

0

1

2

3

4

5

6

7

8

9

Values x 10^-4

Reference Total System Cost ($/kW)

Reference Total System 

Cost ($/kW)

Minimum 5500.0000

Maximum 5500.0000

Mean 5500.0000

Aggregated Experts- 2010- 

Expanded DOE R&D- Total 

System Cost ($

Minimum 2119.1702

Maximum 6959.5392

Mean 4252.1480

Aggregated Experts- 2015- 

Expanded DOE R&D- Total 

System Cost ($

Minimum 783.4670

Maximum 6827.0843

Mean 2891.4795

Aggregated Experts- 2020- 

Expanded DOE R&D- Total 

System Cost ($

Minimum 500.8113

Maximum 6356.4790

Mean 2127.9490
E-20 

O&M System Cost—by Funding Level 

0.0% 5.0% 95.0%

0.0% 88.1% 11.9%

0.0% 97.1% 2.9%

0.0% 98.5% 1.5%

4.75 35.00

05

10152025303540

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 35.0000

Maximum 35.0000

Mean 35.0000

Aggregated Experts- 2010- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 4.2821

Maximum 38.9951

Mean 31.3554

Aggregated Experts- 2015- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 4.8849

Maximum 38.9244

Mean 24.3436

Aggregated Experts- 2020- 

No DOE R&D- O&M Cost 

($/kW-yr)- All Te

Minimum 5.5029

Maximum 38.7844

Mean 18.3276

0.0% 5.0% 95.0%

0.0% 90.5% 9.5%

0.0% 97.8% 2.2%

0.6% 98.6% 0.8%

4.75 35.00

05

10152025303540

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 35.0000

Maximum 35.0000

Mean 35.0000

Aggregated Experts- 2010- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 4.3896

Maximum 38.9982

Mean 30.1387

Aggregated Experts- 2015- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 4.6986

Maximum 38.9877

Mean 19.2869

Aggregated Experts- 2020- 

Planned DOE R&D- O&M 

Cost ($/kW-yr)- A

Minimum 4.0080

Maximum 38.9885

Mean 12.1268
E-21 

0.0% 5.0% 95.0%

0.1% 94.5% 5.4%

0.0% 99.4% 0.6%

2.1% 97.8% 0.2%

4.75 35.00

05

10152025303540

0.00

0.05

0.10

0.15

0.20

0.25

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 35.0000

Maximum 35.0000

Mean 35.0000

Aggregated Experts- 2010- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0651

Maximum 38.9856

Mean 28.7939

Aggregated Experts- 2015- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 5.3586

Maximum 38.8850

Mean 15.3462

Aggregated Experts- 2020- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0153

Maximum 38.9131

Mean 9.6745
E-22 

Inverter Life—by Funding Level 

5.0% 95.0% 0.0%

70.8% 29.2% 0.0%

62.7% 35.5% 1.8%

60.6% 37.4% 2.0%

10.00 20.00

468

1012141618202224

0.0

0.5

1.0

1.5

2.0

2.5

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 5.7853

Maximum 17.7840

Mean 10.6054

Aggregated Experts- 2015- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 6.0887

Maximum 23.9654

Mean 11.6865

Aggregated Experts- 2020- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 6.7273

Maximum 23.2201

Mean 12.4674

5.0% 95.0% 0.0%

69.4% 30.6% 0.0%

63.3% 35.2% 1.5%

61.5% 34.8% 3.7%

10.00 20.00

468

1012141618202224

0.0

0.5

1.0

1.5

2.0

2.5

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 5.8179

Maximum 17.9697

Mean 10.6439

Aggregated Experts- 2015- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 6.1710

Maximum 23.8043

Mean 11.9703

Aggregated Experts- 2020- 

Planned DOE R&D- Inverter 

Lifetime (yr

Minimum 6.3017

Maximum 23.3998

Mean 12.7147
E-23 

5.0% 95.0% 0.0%

67.9% 32.1% 0.0%

62.1% 23.7% 14.2%

60.8% 10.8% 28.4%

10.00 20.00

05

1015202530

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 10.0000

Maximum 10.0000

Mean 10.0000

Aggregated Experts- 2010- 

Expanded DOE R&DInverter Lifetime (y

Minimum 5.7853

Maximum 18.6456

Mean 11.1562

Aggregated Experts- 2015- 

Expanded DOE R&DInverter Lifetime (y

Minimum 4.8357

Maximum 29.9118

Mean 13.2097

Aggregated Experts- 2020- 

Expanded DOE R&DInverter Lifetime (y

Minimum 5.5925

Maximum 29.9725

Mean 14.7936
E-24 

LBD—All TPMs 
E-25 

E.3 Technical Risk and Uncertainty Analysis, Solar PV—Residential 

The following figures represent the aggregated module costs, inverter costs, total system cost, 

O&M costs, inverter lifetimes, and learning by doing (LBD) ranges provided by the experts in 

the three budget scenarios for PV Residential ($0, $140M, and $280M). 

 

The three colored lines in each of these graphs represent the aggregated expert inputs for the 

three time periods for PV Residential (2010, 2015, and 2020). In each of the graphs, the 2009 

reference values are represented by the black line on the right of the graphs, and the FY10 GPRA 

Program goal-based input value for 2015 is represented by the delimiter (i.e., thin black vertical 

lines) on the left of each graph. The percentages to the left side of the delimiter represent the 

likelihood of at least achieving the “goal-based” value. The percentages between the delimiters 

represent the likelihood of improving to somewhere between the “goal-based” value and 

reference value. Furthermore, the key to the right of each graph also lists the minimum, 

maximum, and mean for each aggregated distribution. 
E-26 

Module Cost—by Funding Level 0.0 0.5 1.0 1.5 2.0

2.53.03.54.04.5

0.00.51.01.52.02.53.03.54.04.5
E-27 

0.00.51.01.52.02.53.03.54.04.5
E-28 

Inverter Cost—by Funding Level 100 150 200 250 300 350

400450500550600650

100150200250300350400450500550600650
E-29 

100150200250300350400450500550600650
E-30 

Total System Cost—by Funding Level 

12345678

12345678

Values x 10^-4
E-31 

12345678
E-32 

O&M System Cost—by Funding Level 

05

10152025303540455055

05

10152025303540455055
E-33 

0.0% 5.0%

1.4% 98.6%

3.9% 96.1%

13.8% 86.2%

7.50 52.00

05

10152025303540455055

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

Reference O&M Cost ($/kW-yr)

Reference O&M Cost ($/kWyr)

Minimum 52.0000

Maximum 52.0000

Mean 52.0000

Aggregated Experts- 2010- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0114

Maximum 52.0000

Mean 34.2138

Aggregated Experts- 2015- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0119

Maximum 52.0000

Mean 19.8714

Aggregated Experts- 2020- 

Expanded DOE R&D- O&M 

Cost ($/kW-yr)- 

Minimum 4.0011

Maximum 52.0000

Mean 15.7112
E-34 

Inverter Life—by Funding Level 

5.0% 95.0% 0.0%

6.5% 88.4% 5.2%

0.5% 83.9% 15.6%

0.0% 78.7% 21.2%

5.00 15.00

05

1015202530

0.00

0.05

0.10

0.15

0.20

0.25

0.30

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 5.0000

Maximum 5.0000

Mean 5.0000

Aggregated Experts- 2010- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 5.0000

Maximum 18.8154

Mean 8.9096

Aggregated Experts- 2015- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 5.0000

Maximum 26.2770

Mean 11.3485

Aggregated Experts- 2020- 

No DOE R&D- Inverter 

Lifetime (yrs)- A

Minimum 5.0000

Maximum 26.6984

Mean 12.7295

468

101214161820222426
E-35 

5.0% 95.0% 0.0%

1.2% 60.3% 38.5%

0.2% 30.7% 69.1%

0.1% 13.1% 86.8%

5.00 15.00

05

101520253035

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

Reference Inverter Lifetime (yrs)

Reference Inverter Lifetime 

(yrs)

Minimum 5.0000

Maximum 5.0000

Mean 5.0000

Aggregated Experts- 2010- 

Expanded DOE R&DInverter Lifetime (y

Minimum 5.0000

Maximum 25.0899

Mean 13.6670

Aggregated Experts- 2015- 

Expanded DOE R&DInverter Lifetime (y

Minimum 5.0000

Maximum 29.9931

Mean 16.2088

Aggregated Experts- 2020- 

Expanded DOE R&DInverter Lifetime (y

Minimum 5.0000

Maximum 29.9982

Mean 19.4297
E-36 

LBD—All TPMs 

22.2% 63.3% 14.5%

20.1% 79.9% 0.0%

20.1% 59.4% 20.5%

50.1% 49.9% 0.0%

49.6% 50.5% 0.0%

0.1000 0.2000

0.000.050.100.150.200.250.30

0

2

4

6

8

10

12

14

16

18

Aggregated Experts- LBDs for All TPMs

Aggregated Experts- LBDModule Cost ($/kW)- All 

Technologies

Minimum 0.0110

Maximum 0.2695

Mean 0.1436

Aggregated Experts- LBDInverter Cost ($/kW)- All 

Technologies

Minimum 0.0109

Maximum 0.1959

Mean 0.1360

Aggregated Experts- LBDTotal System Cost ($/kW)- 

All Technolog

Minimum 0.0117

Maximum 0.2356

Mean 0.1511

Aggregated Experts- LBDO&M Cost ($/kW-yr)- All 

Technologies

Minimum 0.00990

Maximum 0.1896

Mean 0.1001

Aggregated Experts- LBDInverter Lifetime (yrs)- All 

Technologi

Minimum 0.00998

Maximum 0.1895

Mean 0.1003
F-1 

2009 Risk Analysis for Concentrating Solar Power (CSP) Technologies

Technology: Power Tower

Plant Size: 100 MW with 6 hours Thermal Energy Storage

Total System Cost 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644 5,644

2015 No DOE 4,584 4,929 4,981 5,012 5,035 5,053 5,070 5,087 5,105 5,123 5,141 5,162 5,182 5,202 5,220 5,250 5,288 5,314 5,314 5,314 5,314

2020 No DOE 4,342 4,714 4,790 4,840 4,876 4,905 4,930 4,953 4,977 5,001 5,024 5,044 5,067 5,090 5,113 5,140 5,171 5,209 5,261 5,314 5,314

2025 No DOE 3,952 4,345 4,435 4,499 4,556 4,610 4,666 4,725 4,783 4,834 4,880 4,916 4,947 4,976 5,004 5,034 5,067 5,107 5,161 5,235 5,314

2015 DOE Planned 4,436 4,789 4,842 4,880 4,917 4,946 4,971 4,994 5,016 5,036 5,054 5,073 5,091 5,110 5,129 5,152 5,181 5,212 5,264 5,314 5,314

2020 DOE Planned 4,191 4,499 4,569 4,626 4,674 4,725 4,773 4,821 4,859 4,897 4,927 4,953 4,977 5,000 5,021 5,045 5,071 5,101 5,152 5,242 5,314

2025 DOE Planned 3,813 4,195 4,273 4,334 4,389 4,437 4,484 4,530 4,584 4,647 4,718 4,786 4,836 4,876 4,910 4,937 4,965 4,998 5,038 5,099 5,314

2015 DOE Expanded 4,174 4,574 4,690 4,765 4,807 4,840 4,869 4,898 4,929 4,956 4,983 5,007 5,027 5,048 5,070 5,095 5,125 5,167 5,230 5,297 5,314

2020 DOE Expanded 3,725 4,188 4,295 4,373 4,436 4,500 4,568 4,658 4,735 4,787 4,825 4,860 4,888 4,918 4,947 4,977 5,010 5,047 5,098 5,186 5,314

2025 DOE Expanded 3,411 3,765 3,860 3,943 4,033 4,129 4,228 4,318 4,406 4,507 4,598 4,672 4,727 4,771 4,813 4,853 4,893 4,933 4,977 5,039 5,314

Solar Field 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995 1,995

2015 No DOE 1,555 1,751 1,779 1,799 1,819 1,839 1,858 1,876 1,896 1,913 1,920 1,920 1,920 1,965 1,995 1,995 1,995 1,995 1,995 1,995 1,995

2020 No DOE 1,482 1,651 1,682 1,706 1,728 1,753 1,779 1,801 1,822 1,840 1,857 1,873 1,891 1,909 1,920 1,925 1,973 1,995 1,995 1,995 1,995

2025 No DOE 1,255 1,429 1,488 1,537 1,582 1,629 1,664 1,695 1,728 1,762 1,790 1,812 1,831 1,847 1,863 1,880 1,901 1,920 1,964 1,995 1,995

2015 DOE Planned 1,542 1,643 1,684 1,717 1,746 1,772 1,798 1,821 1,843 1,862 1,877 1,891 1,904 1,915 1,920 1,930 1,973 1,995 1,995 1,995 1,995

2020 DOE Planned 1,341 1,459 1,511 1,567 1,633 1,679 1,710 1,736 1,761 1,785 1,805 1,823 1,841 1,858 1,875 1,892 1,909 1,920 1,986 1,995 1,995

2025 DOE Planned 1,252 1,356 1,398 1,436 1,479 1,514 1,552 1,591 1,633 1,667 1,696 1,726 1,758 1,788 1,814 1,835 1,854 1,874 1,899 1,920 1,995

2015 DOE Expanded 1,410 1,591 1,632 1,658 1,684 1,706 1,729 1,749 1,767 1,785 1,804 1,823 1,846 1,870 1,892 1,913 1,920 1,975 1,995 1,995 1,995

2020 DOE Expanded 1,248 1,357 1,406 1,457 1,524 1,585 1,629 1,659 1,683 1,701 1,721 1,742 1,766 1,796 1,826 1,852 1,876 1,904 1,920 1,995 1,995

2025 DOE Expanded 1,128 1,244 1,287 1,325 1,359 1,391 1,429 1,473 1,525 1,579 1,623 1,653 1,680 1,704 1,731 1,766 1,806 1,840 1,874 1,919 1,995

HTF/Receiver 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780 780

2015 No DOE 534 691 714 730 744 755 767 776 780 780 780 780 780 780 780 780 780 780 780 780 780

2020 No DOE 536 652 674 690 703 714 723 732 741 751 765 778 780 780 780 780 780 780 780 780 780

2025 No DOE 536 604 626 642 654 666 677 686 695 703 712 723 734 745 757 769 780 780 780 780 780

2015 DOE Planned 538 678 695 709 720 731 739 749 756 763 767 771 774 777 779 780 780 780 780 780 780

2020 DOE Planned 538 643 663 678 690 700 709 717 724 732 741 748 756 763 768 772 776 780 780 780 780

2025 DOE Planned 523 591 615 630 642 653 664 674 683 692 704 715 725 736 746 756 765 771 777 780 780

2015 DOE Expanded 539 658 681 696 708 719 728 738 748 756 764 769 773 777 780 780 780 780 780 780 780

2020 DOE Expanded 535 610 635 650 664 676 687 697 707 716 724 733 742 753 764 774 780 780 780 780 780

2025 DOE Expanded 480 545 570 591 609 623 638 651 663 674 684 694 708 720 733 746 760 773 780 780 780

Appendix F: Summary of @Risk Results—Aggregated Probability Distribution Tables 

F.1 Concentrating Solar Power—Tower with Storage
F-2 

TES 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2015 No DOE 14.6 15.4 15.7 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2020 No DOE 14.6 15.2 15.5 15.7 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2025 No DOE 14.4 15.1 15.3 15.5 15.7 15.8 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2015 DOE Planned 14.2 15.0 15.2 15.5 15.9 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2020 DOE Planned 14.2 14.9 15.1 15.3 15.5 15.8 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2025 DOE Planned 14.2 14.8 15.0 15.2 15.3 15.5 15.7 15.9 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2015 DOE Expanded 13.9 14.6 15.0 15.3 15.8 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2020 DOE Expanded 12.2 14.3 14.7 15.0 15.3 15.7 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

2025 DOE Expanded 8.8 12.2 14.1 14.5 14.8 15.0 15.1 15.3 15.5 15.7 15.9 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0

PB&BOS 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2015 No DOE 879.9 1,021.2 1,052.1 1,072.1 1,085.8 1,096.1 1,104.9 1,112.1 1,119.0 1,124.8 1,130.5 1,135.4 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2020 No DOE 826.2 981.7 1,012.6 1,033.4 1,049.5 1,064.0 1,075.3 1,085.2 1,093.9 1,101.8 1,109.2 1,116.3 1,123.0 1,129.3 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2025 No DOE 804.9 927.7 962.0 988.2 1,009.7 1,026.3 1,041.4 1,054.4 1,066.8 1,077.8 1,087.9 1,097.5 1,106.5 1,115.1 1,123.4 1,131.7 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2015 DOE Planned 797.2 990.5 1,026.3 1,048.2 1,065.5 1,078.1 1,087.4 1,095.3 1,102.4 1,108.6 1,114.6 1,119.8 1,124.7 1,129.2 1,133.5 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2020 DOE Planned 774.9 945.5 978.5 1,004.2 1,025.0 1,042.1 1,055.3 1,066.4 1,077.0 1,086.7 1,095.2 1,102.4 1,109.7 1,116.8 1,123.7 1,130.2 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2025 DOE Planned 750.6 876.3 912.2 938.6 961.7 982.1 1,000.9 1,019.9 1,036.5 1,050.7 1,065.2 1,078.0 1,089.4 1,099.9 1,109.6 1,119.1 1,127.6 1,136.0 1,136.0 1,136.0 1,136.0

2015 DOE Expanded 841.0 940.8 980.9 1,016.5 1,040.4 1,063.4 1,077.1 1,087.9 1,096.5 1,104.0 1,110.8 1,116.5 1,122.4 1,127.9 1,133.5 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2020 DOE Expanded 758.2 863.8 902.3 929.1 959.1 987.8 1,015.3 1,036.4 1,053.2 1,068.5 1,081.2 1,092.8 1,103.1 1,112.6 1,122.1 1,130.0 1,136.0 1,136.0 1,136.0 1,136.0 1,136.0

2025 DOE Expanded 680.0 776.6 813.2 840.3 865.4 890.7 918.7 949.7 990.7 1,024.8 1,048.5 1,067.5 1,082.4 1,096.1 1,107.9 1,118.8 1,129.6 1,136.0 1,136.0 1,136.0 1,136.0

O&M 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0 77.0

2015 No DOE 44.8 60.8 66.2 69.6 72.2 74.4 76.3 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2020 No DOE 41.9 51.4 58.4 62.1 64.7 66.9 68.9 71.2 73.7 76.7 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2025 No DOE 32.6 43.4 50.6 54.7 57.5 59.6 61.3 63.2 65.3 68.2 72.6 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2015 DOE Planned 34.4 49.7 58.2 63.5 66.7 69.0 71.0 72.8 74.4 76.1 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2020 DOE Planned 35.2 43.3 47.3 55.5 59.3 61.8 64.1 66.0 67.8 70.0 72.4 75.8 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2025 DOE Planned 33.4 40.6 43.6 46.5 51.7 54.8 56.7 58.5 60.0 61.8 63.6 65.9 69.5 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2015 DOE Expanded 32.4 48.0 57.7 61.2 63.4 65.3 67.0 68.8 71.0 73.8 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2020 DOE Expanded 34.4 43.5 47.9 52.5 55.6 57.9 59.7 61.3 63.1 65.2 67.9 73.6 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

2025 DOE Expanded 34.4 39.7 42.3 45.3 48.4 50.8 52.7 54.2 55.7 57.1 58.9 61.3 65.1 76.9 76.9 76.9 76.9 76.9 76.9 76.9 76.9

LBD 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Solar Field 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

HTF/Receiver 0.00 0.03 0.05 0.06 0.07 0.07 0.08 0.08 0.09 0.10 0.10 0.12 0.14 0.16 0.18 0.24 0.47 0.57 0.64 0.74 0.95

TES 0.00 0.05 0.07 0.09 0.10 0.11 0.14 0.23 0.25 0.27 0.29 0.30 0.31 0.32 0.34 0.36 0.38 0.40 0.44 0.57 0.97

PB&BOS 0.00 0.03 0.04 0.05 0.06 0.07 0.08 0.10 0.13 0.14 0.15 0.16 0.17 0.18 0.19 0.19 0.20 0.20 0.22 0.24 0.29

O&M 0.00 0.04 0.05 0.06 0.06 0.07 0.08 0.08 0.12 0.16 0.28 0.54 0.59 0.61 0.64 0.67 0.69 0.71 0.74 0.78 0.93
F-3 

2009 Risk Analysis for Concentrating Solar Power (CSP) Technologies

Technology: Trough

Plant Size: 100 MW with 6 hours Thermal Energy Storage

Total System Cost 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443 6,443

2015 No DOE 5,044 5,500 5,571 5,641 5,738 5,916 6,028 6,103 6,156 6,207 6,250 6,296 6,348 6,409 6,431 6,444 6,444 6,444 6,444 6,444 6,444

2020 No DOE 4,321 4,991 5,069 5,151 5,264 5,401 5,508 5,589 5,679 5,776 5,870 5,956 6,040 6,103 6,165 6,218 6,272 6,335 6,405 6,444 6,444

2025 No DOE 3,678 4,370 4,571 4,655 4,722 4,805 4,918 5,035 5,149 5,277 5,428 5,552 5,666 5,775 5,879 5,959 6,043 6,130 6,220 6,329 6,444

2015 DOE Planned 4,820 5,299 5,368 5,427 5,499 5,596 5,723 5,822 5,904 5,975 6,051 6,119 6,190 6,254 6,317 6,390 6,442 6,444 6,444 6,444 6,444

2020 DOE Planned 4,128 4,756 4,856 4,911 4,969 5,030 5,099 5,171 5,272 5,364 5,456 5,561 5,669 5,765 5,858 5,951 6,062 6,151 6,240 6,333 6,444

2025 DOE Planned 3,413 3,975 4,137 4,280 4,404 4,536 4,610 4,657 4,703 4,777 4,890 4,997 5,134 5,272 5,382 5,483 5,576 5,675 5,820 6,073 6,444

2015 DOE Expanded 4,234 5,103 5,189 5,250 5,303 5,360 5,437 5,530 5,625 5,728 5,825 5,934 6,058 6,150 6,217 6,268 6,315 6,357 6,394 6,433 6,444

2020 DOE Expanded 3,477 4,286 4,451 4,579 4,694 4,774 4,828 4,874 4,927 4,992 5,072 5,209 5,395 5,548 5,670 5,794 5,922 6,044 6,167 6,290 6,444

2025 DOE Expanded 2,870 3,555 3,697 3,814 3,925 4,038 4,160 4,281 4,406 4,535 4,597 4,645 4,720 4,885 5,057 5,259 5,395 5,514 5,650 5,906 6,444

Solar Field 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052

2015 No DOE 2,177 2,315 2,376 2,449 2,664 2,786 2,852 2,901 2,950 2,992 3,033 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052

2020 No DOE 1,791 1,923 2,015 2,203 2,331 2,424 2,519 2,603 2,658 2,702 2,753 2,804 2,853 2,907 2,981 3,052 3,052 3,052 3,052 3,052 3,052

2025 No DOE 1,523 1,650 1,748 1,900 1,995 2,096 2,196 2,284 2,364 2,450 2,523 2,587 2,644 2,697 2,770 2,872 3,036 3,052 3,052 3,052 3,052

2015 DOE Planned 1,951 2,154 2,217 2,275 2,395 2,580 2,661 2,736 2,798 2,860 2,913 2,963 3,027 3,052 3,052 3,052 3,052 3,052 3,052 3,052 3,052

2020 DOE Planned 1,689 1,807 1,880 1,970 2,107 2,199 2,276 2,356 2,436 2,504 2,556 2,606 2,655 2,707 2,772 2,849 2,936 3,052 3,052 3,052 3,052

2025 DOE Planned 1,466 1,594 1,640 1,717 1,811 1,888 1,958 2,035 2,116 2,199 2,285 2,377 2,436 2,482 2,527 2,587 2,666 2,776 2,963 3,052 3,052

2015 DOE Expanded 1,500 2,027 2,093 2,153 2,266 2,421 2,514 2,577 2,631 2,683 2,739 2,799 2,860 2,922 2,979 3,035 3,052 3,052 3,052 3,052 3,052

2020 DOE Expanded 1,500 1,740 1,792 1,852 1,923 2,015 2,108 2,198 2,277 2,344 2,415 2,473 2,531 2,594 2,662 2,749 2,891 3,052 3,052 3,052 3,052

2025 DOE Expanded 1,347 1,532 1,571 1,609 1,668 1,735 1,795 1,850 1,910 1,974 2,038 2,117 2,201 2,306 2,411 2,474 2,551 2,664 2,892 3,052 3,052

HTF/Receiver 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150 150

2015 No DOE 110 124 129 133 136 138 141 143 145 147 149 150 150 150 150 150 150 150 150 150 150

2020 No DOE 87 107 114 120 125 129 132 136 139 141 144 147 150 150 150 150 150 150 150 150 150

2025 No DOE 78 94 99 103 107 110 113 116 120 123 127 130 133 136 140 144 147 150 150 150 150

2015 DOE Planned 82 112 120 125 130 133 135 138 141 143 145 147 149 150 150 150 150 150 150 150 150

2020 DOE Planned 65 93 98 102 105 108 111 114 117 120 123 127 130 134 138 142 146 150 150 150 150

2025 DOE Planned 48 67 75 82 88 93 98 102 105 109 112 116 120 123 127 131 137 143 150 150 150

2015 DOE Expanded 69 97 107 115 121 126 130 134 137 140 143 145 148 150 150 150 150 150 150 150 150

2020 DOE Expanded 48 68 75 81 87 91 96 100 105 109 112 116 119 124 129 135 142 149 150 150 150

2025 DOE Expanded 32 42 46 51 72 80 85 89 94 97 101 104 107 110 114 119 125 133 146 150 150

F.2 Concentrating Solar Power—Trough with Storage 
F-4 

TES 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2015 No DOE 27.2 38.7 40.2 41.2 42.1 42.9 43.6 44.2 44.8 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2020 No DOE 18.5 29.5 33.8 35.9 37.5 38.8 39.9 41.0 42.3 43.9 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2025 No DOE 11.4 23.0 24.7 26.0 27.0 28.1 29.3 30.9 32.9 34.6 36.4 38.3 40.3 42.7 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2015 DOE Planned 28.2 36.8 38.2 39.3 40.2 41.1 42.0 42.9 43.7 44.6 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2020 DOE Planned 11.5 24.4 29.7 31.6 32.9 33.9 34.9 35.9 37.0 38.1 39.3 40.5 41.9 43.2 44.5 45.0 45.0 45.0 45.0 45.0 45.0

2025 DOE Planned 10.0 14.5 17.0 18.3 19.2 20.0 20.8 21.8 23.4 26.1 28.7 31.4 34.1 36.5 38.4 40.3 42.2 44.3 45.0 45.0 45.0

2015 DOE Expanded 27.8 33.7 35.6 37.1 38.3 39.6 40.7 41.9 43.1 44.0 44.9 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0 45.0

2020 DOE Expanded 10.5 19.0 23.8 26.1 27.3 28.4 29.3 30.3 31.4 32.8 34.5 36.6 38.4 40.3 42.6 45.0 45.0 45.0 45.0 45.0 45.0

2025 DOE Expanded 10.0 13.0 14.4 15.1 15.7 16.2 16.9 17.7 19.0 20.6 22.5 24.9 27.7 30.1 32.6 34.6 36.7 39.3 43.4 45.0 45.0

PB&BOS 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0

2015 No DOE 809.1 922.1 971.4 1,002.4 1,026.1 1,046.3 1,063.8 1,080.9 1,098.4 1,116.6 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0

2020 No DOE 706.5 836.1 881.8 915.1 939.9 963.3 985.5 1,005.1 1,026.8 1,049.0 1,074.8 1,102.5 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0

2025 No DOE 635.5 772.1 812.6 847.9 876.5 900.7 923.5 945.7 969.1 994.5 1,019.9 1,050.0 1,088.2 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0 1,119.0

2015 DOE Planned 718.6 883.3 922.2 951.5 975.4 997.9 1,017.0 1,036.1 1,052.3 1,068.8 1,085.7 1,103.0 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0 1,119.0 1,119.0

2020 DOE Planned 650.3 801.4 845.2 880.6 905.3 927.8 948.0 967.5 986.2 1,007.0 1,027.2 1,052.6 1,082.9 1,118.5 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0

2025 DOE Planned 451.1 705.2 764.0 803.6 836.3 862.9 886.7 908.2 929.2 950.7 968.3 984.4 997.9 1,009.3 1,020.9 1,033.6 1,053.2 1,096.5 1,119.0 1,119.0 1,119.0

2015 DOE Expanded 526.4 785.5 876.3 917.4 947.1 973.6 997.6 1,019.8 1,038.8 1,058.2 1,077.8 1,097.7 1,118.7 1,118.7 1,118.7 1,118.7 1,118.7 1,119.0 1,119.0 1,119.0 1,119.0

2020 DOE Expanded 357.8 618.9 742.3 800.4 842.6 871.7 896.6 919.5 942.1 965.3 989.9 1,011.4 1,029.4 1,045.8 1,060.2 1,079.2 1,103.3 1,119.0 1,119.0 1,119.0 1,119.0

2025 DOE Expanded 157.8 476.9 630.0 709.0 752.6 788.3 816.4 842.8 867.8 889.7 914.5 936.9 960.2 982.5 1,005.3 1,029.5 1,057.3 1,096.6 1,119.0 1,119.0 1,119.0

O&M 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0

2015 No DOE 45.7 58.1 61.6 64.3 66.5 68.4 70.1 71.7 73.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0

2020 No DOE 31.4 49.8 54.5 57.1 59.1 60.9 62.3 63.6 64.8 66.0 67.0 68.1 69.5 71.1 73.4 74.0 74.0 74.0 74.0 74.0 74.0

2025 No DOE 17.7 40.5 47.0 50.2 52.7 54.7 56.3 57.8 59.1 60.2 61.5 62.8 64.4 66.2 68.5 71.0 74.0 74.0 74.0 74.0 74.0

2015 DOE Planned 43.7 56.2 59.1 60.9 62.4 63.8 64.9 66.1 67.3 68.6 70.1 71.9 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0

2020 DOE Planned 10.6 37.6 43.8 48.3 51.9 54.9 57.1 58.8 60.1 61.3 62.4 63.4 64.4 65.4 66.5 67.8 69.7 73.3 74.0 74.0 74.0

2025 DOE Planned 10.4 27.6 36.7 39.8 42.5 45.2 47.6 50.1 52.3 54.1 55.5 56.8 58.0 59.4 60.6 62.1 63.9 65.8 69.1 74.0 74.0

2015 DOE Expanded 30.0 50.0 54.6 57.7 59.7 61.3 62.6 63.6 64.8 65.9 67.2 69.0 71.5 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0

2020 DOE Expanded 10.6 33.0 40.9 44.9 47.8 50.1 52.3 54.1 55.4 56.7 57.8 58.9 60.0 61.1 62.3 63.8 65.7 69.2 74.0 74.0 74.0

2025 DOE Expanded 10.5 26.1 35.3 38.3 40.4 42.1 43.8 45.3 46.6 48.0 49.3 50.6 51.8 53.1 54.6 56.4 59.1 62.5 66.8 74.0 74.0

LBD 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Solar Field 0.00 0.06 0.07 0.08 0.09 0.09 0.10 0.10 0.11 0.12 0.14 0.16 0.19 0.22 0.22 0.24 0.26 0.28 0.30 0.32 0.33

HTF/Receiver 0.00 0.03 0.05 0.06 0.07 0.07 0.08 0.08 0.09 0.10 0.10 0.12 0.14 0.16 0.18 0.24 0.25 0.27 0.30 0.32 0.35

TES 0.00 0.05 0.07 0.09 0.10 0.11 0.15 0.23 0.25 0.27 0.29 0.30 0.31 0.33 0.34 0.36 0.38 0.40 0.44 0.44 0.46

PB&BOS 0.00 0.03 0.04 0.05 0.06 0.07 0.08 0.10 0.13 0.14 0.15 0.16 0.17 0.18 0.19 0.19 0.20 0.20 0.22 0.24 0.29

O&M 0.00 0.04 0.05 0.06 0.06 0.07 0.08 0.09 0.12 0.16 0.28 0.17 0.18 0.19 0.19 0.20 0.20 0.22 0.24 0.25 0.27
F-5 

2009 Risk Analysis for Photovoltaic (PV) Technologies

Technology: Crystalline Silicon / Thin Film / CPV in a Utility Market Application

Plant Size: 10 MW 

Module Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000

2010 No DOE 522 1,269 1,498 1,660 1,781 1,887 1,976 2,067 2,162 2,265 2,365 2,470 2,577 2,682 2,800 2,944 3,000 3,000 3,000 3,000 3,000

2015 No DOE 504 1,022 1,159 1,251 1,337 1,426 1,505 1,575 1,637 1,691 1,748 1,809 1,873 1,947 2,029 2,139 2,287 2,504 2,978 3,000 3,000

2020 No DOE 300 593 772 912 1,070 1,183 1,264 1,335 1,394 1,453 1,504 1,559 1,614 1,671 1,735 1,810 1,903 2,038 2,274 3,000 3,000

2010 DOE Planned 502 1,218 1,431 1,579 1,686 1,770 1,841 1,912 1,972 2,029 2,088 2,159 2,231 2,304 2,380 2,451 2,539 2,654 2,847 3,000 3,000

2015 DOE Planned 500 883 983 1,051 1,125 1,196 1,261 1,320 1,376 1,430 1,481 1,531 1,583 1,642 1,713 1,802 1,921 2,110 2,350 2,709 3,000

2020 DOE Planned 300 535 628 711 798 880 954 1,014 1,067 1,117 1,160 1,204 1,250 1,291 1,339 1,401 1,471 1,569 1,734 2,036 3,000

2010 DOE Expanded 501 1,131 1,376 1,517 1,615 1,688 1,744 1,804 1,858 1,911 1,961 2,017 2,072 2,136 2,207 2,288 2,392 2,541 2,799 3,000 3,000

2015 DOE Expanded 500 806 879 930 977 1,024 1,075 1,122 1,169 1,216 1,262 1,304 1,350 1,399 1,455 1,520 1,599 1,726 1,909 2,204 3,000

2020 DOE Expanded 300 464 550 619 687 744 801 857 904 948 984 1,023 1,064 1,108 1,151 1,203 1,272 1,365 1,520 1,738 3,000

Inverter Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470

2010 No DOE 51 178 224 256 284 306 312 316 320 323 327 332 339 359 389 425 442 456 470 470 470

2015 No DOE 50 143 170 191 206 219 232 245 258 272 287 302 314 322 331 348 374 410 428 446 470

2020 No DOE 50 131 153 167 179 190 201 211 221 234 247 262 275 290 305 321 337 367 391 407 470

2010 DOE Planned 51 161 211 240 268 294 305 310 314 317 320 323 328 334 349 363 375 386 404 440 470

2015 DOE Planned 50 137 162 177 191 202 211 221 230 240 249 259 270 284 301 313 324 337 350 366 470

2020 DOE Planned 50 121 141 151 161 171 181 190 200 209 217 225 234 244 255 271 291 309 321 333 470

2010 DOE Expanded 50 147 200 233 266 293 301 305 309 312 315 319 324 330 340 350 361 374 400 441 470

2015 DOE Expanded 50 126 146 158 168 177 184 192 199 205 212 219 227 236 246 255 265 275 286 314 470

2020 DOE Expanded 50 110 126 136 144 151 158 165 171 178 185 191 200 204 208 213 219 227 242 276 470

Total System Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000

2010 No DOE 1,888 2,782 3,103 3,369 3,629 3,892 4,118 4,310 4,471 4,616 4,746 4,829 4,896 4,952 5,000 5,000 5,000 5,000 5,000 5,000 5,000

2015 No DOE 1,713 2,328 2,583 2,747 2,873 2,974 3,063 3,157 3,260 3,373 3,502 3,661 3,822 4,019 4,253 4,531 4,793 4,961 5,000 5,000 5,000

2020 No DOE 1,359 1,940 2,118 2,277 2,424 2,568 2,700 2,815 2,918 3,010 3,094 3,179 3,278 3,388 3,529 3,717 3,972 4,344 4,793 5,000 5,000

2010 DOE Planned 1,698 2,561 2,875 3,111 3,347 3,541 3,731 3,902 4,084 4,267 4,447 4,633 4,709 4,762 4,808 4,853 4,905 4,981 5,000 5,000 5,000

2015 DOE Planned 1,424 1,929 2,099 2,234 2,355 2,452 2,534 2,609 2,697 2,790 2,918 3,100 3,331 3,541 3,757 3,996 4,259 4,588 4,814 5,000 5,000

2020 DOE Planned 1,241 1,579 1,682 1,786 1,896 1,999 2,084 2,163 2,254 2,339 2,418 2,505 2,600 2,708 2,825 2,965 3,149 3,384 3,708 4,388 5,000

2010 DOE Expanded 1,686 2,483 2,749 2,972 3,169 3,347 3,514 3,715 3,967 4,216 4,415 4,563 4,633 4,686 4,732 4,788 4,852 4,940 5,000 5,000 5,000

2015 DOE Expanded 1,284 1,703 1,853 1,972 2,113 2,252 2,341 2,409 2,472 2,546 2,632 2,729 2,849 3,007 3,178 3,365 3,563 3,809 4,091 4,539 5,000

2020 DOE Expanded 1,200 1,411 1,505 1,590 1,687 1,783 1,869 1,951 2,025 2,095 2,164 2,242 2,332 2,417 2,515 2,613 2,733 2,888 3,101 3,447 5,000

F.3 Photovoltaic —Utility
F-6 

O&M Cost (2009$/kW-yr) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0 30.0

2010 No DOE 4.4 19.2 21.8 23.6 24.8 25.7 26.4 27.0 27.5 28.0 28.3 28.7 29.1 29.5 29.9 30.0 30.0 30.0 30.0 30.0 30.0

2015 No DOE 6.6 13.3 15.5 17.1 18.3 19.3 20.2 21.1 21.9 22.7 23.4 24.2 24.9 25.8 26.7 27.8 28.8 29.8 30.0 30.0 30.0

2020 No DOE 4.1 8.4 10.2 11.4 12.3 13.1 13.9 14.8 15.7 16.8 18.0 19.4 20.8 21.8 22.8 23.9 25.2 27.1 29.0 30.0 30.0

2010 DOE Planned 4.2 16.2 19.3 21.5 23.2 24.3 25.1 25.8 26.4 26.9 27.3 27.7 28.1 28.5 28.9 29.3 29.8 30.1 30.0 30.0 30.0

2015 DOE Planned 4.1 11.5 13.4 14.4 15.1 15.6 16.1 16.5 17.0 17.6 18.3 19.5 22.2 23.7 24.7 25.8 27.0 28.3 29.7 30.0 30.0

2020 DOE Planned 3.0 6.2 7.0 7.6 8.2 8.7 9.4 10.1 10.7 11.4 12.5 14.4 15.7 17.0 19.1 21.3 22.2 23.3 25.5 28.5 30.0

2010 DOE Expanded 4.1 16.5 19.2 21.0 22.4 23.7 24.6 25.3 25.8 26.3 26.8 27.2 27.6 27.9 28.3 28.7 29.2 29.8 30.0 30.0 30.0

2015 DOE Expanded 3.0 8.6 11.0 12.2 12.8 13.3 13.7 14.0 14.4 14.7 15.1 15.7 17.2 19.8 22.6 23.9 24.9 26.2 28.6 30.0 30.0

2020 DOE Expanded 3.0 5.2 5.9 6.4 6.9 7.3 7.8 8.4 9.1 10.1 10.8 11.7 13.1 14.5 16.1 19.0 21.1 22.2 23.3 26.5 30.0

Inverter Lifetime (yrs) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0

2010 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.5 11.1 11.8 12.5 13.2 14.1 15.3 17.5 23.9

2015 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.2 11.6 12.5 13.2 13.8 14.3 15.0 15.9 17.2 18.9 20.6 23.1 30.0

2020 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.5 12.8 13.9 14.5 15.1 15.6 16.1 16.9 17.8 18.8 20.0 21.5 24.0 30.0

2010 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.3 10.9 11.5 12.0 12.5 13.0 13.6 14.4 15.3 16.7 18.8 24.0

2015 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 11.3 12.3 13.2 13.8 14.5 15.1 15.9 16.7 17.6 18.8 20.6 23.1 30.0

2020 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.7 12.7 14.1 14.8 15.4 16.1 17.0 17.9 18.7 19.6 20.7 22.7 25.5 30.0

2010 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.8 11.6 12.2 12.8 13.5 14.0 14.6 15.3 16.1 17.1 18.8 24.0

2015 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.2 12.1 13.1 13.9 14.7 15.7 17.3 18.5 19.5 20.3 21.2 22.6 24.8 30.0

2020 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 11.0 13.5 14.5 15.2 15.9 17.5 19.4 20.9 22.5 23.8 24.7 25.8 27.3 30.0

LBD 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Module Cost 0.00 0.03 0.04 0.05 0.06 0.06 0.07 0.08 0.09 0.10 0.11 0.12 0.13 0.14 0.16 0.17 0.18 0.19 0.20 0.22 0.26

Inverter Cost 0.01 0.04 0.05 0.06 0.07 0.08 0.08 0.09 0.10 0.11 0.12 0.13 0.14 0.14 0.15 0.16 0.16 0.16 0.17 0.18 0.20

Total System Cost 0.00 0.05 0.06 0.07 0.08 0.08 0.09 0.10 0.11 0.12 0.14 0.15 0.16 0.17 0.18 0.19 0.19 0.20 0.21 0.22 0.26

O&M Cost 0.00 0.04 0.06 0.07 0.08 0.09 0.10 0.11 0.12 0.13 0.14 0.15 0.16 0.16 0.17 0.17 0.18 0.19 0.19 0.20 0.27

Inverter Lifetime 0.01 0.03 0.04 0.04 0.05 0.05 0.06 0.06 0.07 0.07 0.08 0.08 0.09 0.10 0.10 0.11 0.12 0.13 0.14 0.15 0.19
F-7 

2009 Risk Analysis for Photovoltaic (PV) Technologies

Technology: Crystalline Silicon / Thin Film / CPV in a Commercial Market Application

Plant Size: 150 kW

Module Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500

2010 No DOE 1,216 1,813 1,981 2,114 2,224 2,318 2,405 2,479 2,542 2,600 2,658 2,719 2,786 2,868 2,965 3,090 3,316 3,500 3,500 3,500 3,500

2015 No DOE 696 1,166 1,290 1,395 1,487 1,585 1,681 1,761 1,832 1,899 1,964 2,036 2,105 2,177 2,254 2,352 2,480 2,687 2,992 3,500 3,500

2020 No DOE 237 552 728 898 1,048 1,162 1,248 1,321 1,387 1,446 1,504 1,565 1,629 1,695 1,762 1,835 1,919 2,015 2,172 2,517 3,500

2010 DOE Planned 1,216 1,733 1,861 1,946 2,021 2,084 2,153 2,218 2,286 2,355 2,424 2,494 2,559 2,620 2,678 2,744 2,826 2,925 3,139 3,500 3,500

2015 DOE Planned 585 1,005 1,106 1,185 1,267 1,337 1,409 1,479 1,554 1,636 1,710 1,789 1,863 1,940 2,014 2,096 2,192 2,331 2,562 2,857 3,500

2020 DOE Planned 157 490 627 741 852 951 1,022 1,079 1,131 1,182 1,231 1,287 1,349 1,412 1,486 1,569 1,657 1,755 1,884 2,085 3,500

2010 DOE Expanded 1,216 1,649 1,749 1,826 1,901 1,968 2,035 2,099 2,162 2,222 2,281 2,338 2,394 2,457 2,513 2,583 2,664 2,770 2,940 3,291 3,500

2015 DOE Expanded 190 879 960 1,016 1,064 1,111 1,158 1,208 1,258 1,315 1,379 1,462 1,552 1,636 1,726 1,822 1,914 2,022 2,148 2,390 3,500

2020 DOE Expanded 100 427 532 629 718 795 848 896 940 986 1,030 1,080 1,136 1,200 1,267 1,337 1,412 1,498 1,601 1,788 3,500

Inverter Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470 470

2010 No DOE 200 298 323 327 331 333 336 338 341 344 348 354 419 439 450 462 470 470 470 470 470

2015 No DOE 135 182 202 213 224 236 249 263 280 301 325 335 345 403 423 435 451 470 470 470 470

2020 No DOE 128 159 172 182 191 201 208 217 227 240 257 288 329 365 391 402 418 470 470 470 470

2010 DOE Planned 200 284 317 322 325 328 330 332 335 337 341 345 350 363 375 387 421 470 470 470 470

2015 DOE Planned 133 174 192 204 213 225 235 248 263 281 306 324 332 339 348 357 372 470 470 470 470

2020 DOE Planned 118 149 161 170 179 190 201 210 220 231 247 272 302 316 325 334 347 470 470 470 470

2010 DOE Expanded 200 278 312 317 320 323 325 327 329 332 335 337 341 346 353 366 417 470 470 470 470

2015 DOE Expanded 124 163 179 191 201 209 218 227 238 248 257 265 273 280 289 304 346 470 470 470 470

2020 DOE Expanded 110 138 150 160 169 179 190 200 204 208 212 217 223 232 250 279 333 470 470 470 470

Total System Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500

2010 No DOE 2,320 3,090 3,399 3,703 4,045 4,291 4,450 4,569 4,679 4,777 4,887 5,015 5,192 5,313 5,377 5,429 5,500 5,500 5,500 5,500 5,500

2015 No DOE 1,570 2,298 2,556 2,777 2,964 3,062 3,145 3,231 3,332 3,469 3,611 3,739 3,858 3,969 4,090 4,229 4,447 4,801 5,340 5,500 5,500

2020 No DOE 640 1,357 1,711 1,994 2,162 2,300 2,451 2,679 2,847 2,969 3,057 3,123 3,193 3,269 3,351 3,453 3,590 3,791 4,441 5,356 5,500

2010 DOE Planned 2,159 2,945 3,168 3,332 3,463 3,602 3,782 4,082 4,348 4,512 4,656 4,801 4,970 5,106 5,176 5,233 5,280 5,331 5,388 5,482 5,500

2015 DOE Planned 860 1,966 2,217 2,370 2,510 2,611 2,694 2,768 2,838 2,902 2,967 3,046 3,173 3,418 3,594 3,732 3,884 4,106 4,769 5,253 5,500

2020 DOE Planned 511 1,185 1,570 1,704 1,783 1,853 1,931 2,023 2,117 2,211 2,311 2,416 2,542 2,665 2,773 2,871 2,970 3,084 3,255 3,764 5,500

2010 DOE Expanded 2,088 2,787 2,979 3,126 3,278 3,437 3,651 3,963 4,161 4,314 4,456 4,626 4,795 4,871 4,932 4,988 5,047 5,122 5,200 5,336 5,500

2015 DOE Expanded 822 1,794 1,975 2,119 2,246 2,391 2,503 2,578 2,636 2,710 2,783 2,861 2,947 3,074 3,227 3,362 3,489 3,639 3,856 4,319 5,500

2020 DOE Expanded 501 993 1,270 1,519 1,591 1,646 1,713 1,795 1,911 2,020 2,124 2,226 2,324 2,416 2,512 2,604 2,697 2,792 2,913 3,167 5,500

F.4 Photovoltaic—Commercial
F-8 

O&M Cost (2009$/kW-yr) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0

2010 No DOE 4.0 22.6 26.2 28.0 29.1 29.8 30.4 30.9 31.4 31.8 32.1 32.6 33.0 33.4 33.8 34.3 34.9 35.0 35.2 35.0 35.0

2015 No DOE 4.0 14.2 16.3 17.8 19.2 20.1 20.9 21.7 22.5 23.1 23.8 24.6 25.4 26.4 27.6 28.9 30.5 31.8 33.2 35.0 35.0

2020 No DOE 4.0 8.7 10.2 11.5 12.4 13.1 13.8 14.4 15.0 15.7 16.4 17.3 18.3 19.5 21.0 22.6 24.3 26.8 29.9 33.0 35.0

2010 DOE Planned 4.0 20.5 23.7 26.0 27.5 28.5 29.2 29.7 30.2 30.6 31.0 31.5 31.9 32.3 32.8 33.3 33.8 34.4 35.0 35.0 35.0

2015 DOE Planned 4.0 11.1 13.1 14.6 15.6 16.2 16.6 17.0 17.3 17.7 17.9 18.2 18.5 18.9 19.3 19.8 20.6 27.6 31.0 33.4 35.0

2020 DOE Planned 4.0 6.8 7.4 7.8 8.2 8.5 8.8 9.1 9.5 9.8 10.2 10.6 11.1 11.7 12.4 13.7 16.0 17.4 18.5 21.0 35.0

2010 DOE Expanded 4.0 19.3 22.4 24.4 25.6 26.6 27.5 28.2 28.8 29.3 29.8 30.3 30.6 31.0 31.5 31.9 32.5 33.2 34.0 35.0 35.0

2015 DOE Expanded 4.0 9.1 10.6 11.7 12.7 13.3 13.7 14.1 14.4 14.8 15.1 15.4 15.6 15.9 16.1 16.3 16.6 17.0 17.8 24.7 35.0

2020 DOE Expanded 4.0 5.5 6.4 6.8 7.1 7.3 7.6 7.8 8.1 8.3 8.6 9.0 9.3 9.7 10.2 10.7 11.6 13.1 14.9 16.4 35.0

Inverter Lifetime (yrs) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0

2010 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.7 11.4 12.0 12.9 14.0 18.0

2015 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 11.2 12.5 13.4 14.1 14.9 15.9 17.4 23.6

2020 No DOE 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 13.4 14.6 15.5 16.2 16.8 17.8 19.0 23.2

2010 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.1 10.9 11.6 12.3 13.0 14.1 18.1

2015 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.7 13.2 14.4 15.2 16.0 16.9 18.1 24.0

2020 DOE Planned 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 13.1 15.5 16.7 17.5 18.2 18.9 19.7 23.2

2010 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.8 12.3 13.3 14.1 14.9 16.0 18.7

2015 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 12.4 15.5 17.8 19.0 19.9 20.7 21.8 30.0

2020 DOE Expanded 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 15.0 18.9 22.3 23.7 24.7 25.6 26.6 30.0

10.0

10.0

LBD 0% 5% 10% 10.0 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Module Cost 0.01 0.04 0.05 10.0 0.08 0.09 0.10 0.12 0.13 0.14 0.15 0.16 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23 0.32

Inverter Cost 0.01 0.05 0.07 10.0 0.10 0.11 0.13 0.13 0.14 0.14 0.15 0.15 0.16 0.16 0.16 0.16 0.17 0.17 0.18 0.18 0.20

Total System Cost 0.01 0.04 0.05 10.0 0.07 0.09 0.10 0.12 0.13 0.15 0.16 0.17 0.18 0.18 0.19 0.20 0.20 0.20 0.21 0.22 0.27

O&M Cost 0.01 0.05 0.07 10.0 0.10 0.11 0.13 0.14 0.15 0.15 0.16 0.16 0.17 0.17 0.18 0.18 0.18 0.19 0.19 0.20 0.22

Inverter Lifetime 0.01 0.04 0.05 10.0 0.07 0.07 0.08 0.09 0.09 0.10 0.10 0.10 0.11 0.11 0.12 0.13 0.13 0.14 0.15 0.16 0.19
F-9 

2009 Risk Analysis for Photovoltaic (PV) Technologies

Technology: Crystalline Silicon / Thin Film in a Residential Market Application

Plant Size: 4 kW

Module Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000

2010 No DOE 1,122 1,861 2,006 2,112 2,218 2,316 2,407 2,492 2,571 2,665 2,766 2,873 2,984 3,091 3,229 3,439 4,000 4,000 4,000 4,000 4,000

2015 No DOE 951 1,536 1,677 1,761 1,816 1,865 1,908 1,950 1,989 2,031 2,075 2,116 2,161 2,214 2,276 2,353 2,479 2,957 3,761 4,000 4,000

2020 No DOE 361 646 879 1,191 1,343 1,437 1,512 1,572 1,626 1,677 1,730 1,784 1,837 1,898 1,963 2,030 2,106 2,203 2,420 3,852 4,000

2010 DOE Planned 1,131 1,519 1,732 1,874 1,963 2,039 2,106 2,172 2,237 2,302 2,370 2,439 2,520 2,624 2,756 2,872 2,987 3,116 3,309 4,000 4,000

2015 DOE Planned 810 1,184 1,265 1,324 1,374 1,418 1,461 1,499 1,534 1,571 1,608 1,646 1,687 1,736 1,792 1,860 1,983 2,162 2,481 3,033 4,000

2020 DOE Planned 360 602 782 918 1,011 1,086 1,148 1,203 1,249 1,291 1,332 1,373 1,412 1,450 1,486 1,524 1,565 1,620 1,697 1,981 4,000

2010 DOE Expanded 948 1,295 1,520 1,734 1,846 1,939 2,018 2,088 2,160 2,228 2,301 2,372 2,445 2,520 2,605 2,704 2,812 2,944 3,107 3,926 4,000

2015 DOE Expanded 637 961 1,029 1,078 1,121 1,162 1,204 1,241 1,277 1,313 1,353 1,398 1,445 1,499 1,564 1,644 1,738 1,866 2,027 2,337 4,000

2020 DOE Expanded 361 556 683 778 846 893 932 969 1,000 1,030 1,062 1,099 1,134 1,170 1,210 1,253 1,301 1,358 1,437 1,651 4,000

Inverter Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600

2010 No DOE 200 323 338 347 355 361 366 371 376 381 386 393 400 412 466 491 507 525 553 600 600

2015 No DOE 142 194 212 226 238 248 259 271 284 298 317 337 354 373 390 421 439 450 459 474 600

2020 No DOE 140 168 181 191 199 207 214 223 231 241 252 265 285 320 358 381 392 401 410 425 600

2010 DOE Planned 200 313 331 340 347 354 359 364 369 373 378 383 390 398 409 427 444 456 472 499 600

2015 DOE Planned 140 186 205 218 230 240 250 261 272 286 301 319 340 362 376 386 395 404 414 432 600

2020 DOE Planned 140 163 175 184 192 200 207 215 224 233 243 254 269 300 322 335 346 356 366 386 600

2010 DOE Expanded 201 312 327 336 343 350 355 360 364 368 373 378 383 388 394 400 408 421 441 484 600

2015 DOE Expanded 140 178 195 208 219 228 236 245 254 263 272 280 287 294 300 306 314 324 348 403 600

2020 DOE Expanded 140 158 168 177 184 193 201 208 216 225 234 245 255 266 275 285 295 308 325 374 600

Total System Cost (2009$/kW) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000

2010 No DOE 3,006 4,138 4,635 5,221 5,804 6,106 6,285 6,408 6,494 6,578 6,658 6,731 6,801 6,873 6,961 7,000 7,000 7,000 7,000 7,000 7,000

2015 No DOE 2,303 3,414 3,789 4,008 4,184 4,353 4,516 4,665 4,838 5,011 5,190 5,360 5,549 5,764 6,088 6,474 6,744 7,000 7,000 7,000 7,000

2020 No DOE 1,914 2,804 2,968 3,102 3,239 3,403 3,564 3,759 3,921 4,074 4,218 4,356 4,491 4,621 4,811 5,042 5,471 6,409 6,918 7,000 7,000

2010 DOE Planned 2,971 4,048 4,407 4,630 4,828 5,008 5,189 5,382 5,625 5,965 6,237 6,374 6,479 6,567 6,647 6,720 6,796 6,883 7,000 7,000 7,000

2015 DOE Planned 2,212 2,952 3,141 3,291 3,414 3,515 3,607 3,702 3,798 3,898 3,998 4,122 4,245 4,381 4,556 4,770 5,093 5,760 6,511 6,826 7,000

2020 DOE Planned 1,773 2,375 2,483 2,558 2,619 2,686 2,755 2,828 2,897 2,976 3,052 3,142 3,254 3,362 3,480 3,602 3,744 3,919 4,228 4,994 7,000

2010 DOE Expanded 2,776 3,777 4,067 4,294 4,470 4,650 4,862 5,123 5,486 5,824 6,108 6,245 6,340 6,421 6,495 6,561 6,641 6,739 6,862 7,000 7,000

2015 DOE Expanded 1,786 2,517 2,723 2,867 2,989 3,106 3,211 3,313 3,428 3,537 3,644 3,756 3,881 4,007 4,135 4,290 4,454 4,669 5,053 6,236 7,000

2020 DOE Expanded 1,705 2,123 2,225 2,298 2,359 2,410 2,458 2,513 2,567 2,634 2,713 2,798 2,880 2,974 3,069 3,172 3,310 3,469 3,688 4,160 7,000

F.5 Photovoltaic—Residential
F-10 

O&M Cost (2009$/kW-yr) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0 52.0

2010 No DOE 4.0 15.5 23.2 29.3 34.3 38.9 42.9 46.9 47.9 48.4 48.9 49.3 49.6 50.0 50.3 50.6 51.0 51.4 52.0 52.0 52.0

2015 No DOE 4.0 11.2 16.4 20.7 24.8 29.2 33.0 34.6 36.0 37.1 38.1 39.0 39.8 40.6 41.5 42.4 43.4 44.7 46.3 49.5 52.0

2020 No DOE 4.0 10.4 13.3 14.9 16.1 17.2 18.1 18.9 19.7 20.5 21.3 22.2 23.1 24.2 25.6 27.4 31.0 35.6 40.7 46.6 52.0

2010 DOE Planned 4.1 14.7 21.4 26.7 31.1 35.2 36.5 37.5 38.2 38.9 39.4 39.9 40.4 40.9 41.4 42.1 42.9 43.9 46.6 51.2 52.0

2015 DOE Planned 4.0 10.4 13.3 14.7 16.0 17.0 18.0 18.8 19.6 20.3 21.1 22.0 23.0 24.0 25.4 27.0 30.3 34.7 39.8 46.5 52.0

2020 DOE Planned 4.0 7.9 9.6 10.8 11.8 12.7 13.5 14.3 15.0 15.7 16.5 17.3 18.2 19.2 20.4 22.1 24.9 29.1 34.0 40.6 52.0

2010 DOE Expanded 4.1 14.1 20.5 25.6 28.6 30.1 31.4 32.3 33.3 34.1 34.9 35.7 36.5 37.4 38.5 39.6 41.0 42.9 47.0 52.0 52.0

2015 DOE Expanded 4.0 7.9 9.6 10.9 11.9 12.8 13.7 14.5 15.2 15.9 16.7 17.7 18.6 19.8 21.2 23.1 26.9 31.0 36.9 44.0 52.0

2020 DOE Expanded 4.0 5.8 6.8 7.6 8.4 9.1 9.7 10.3 11.0 11.7 12.4 13.2 14.2 15.2 16.4 18.1 21.1 24.8 29.9 38.7 52.0

Inverter Lifetime (yrs) 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reference 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0

2010 No DOE 5.0 5.0 5.4 5.9 6.3 6.7 7.0 7.3 7.7 8.0 8.4 8.7 9.1 9.6 10.0 10.6 11.2 12.0 13.3 15.0 19.0

2015 No DOE 5.0 6.5 7.4 8.0 8.5 8.9 9.3 9.6 9.9 10.2 10.5 10.8 11.2 11.5 12.0 12.6 13.5 15.2 17.2 19.9 26.4

2020 No DOE 5.0 6.9 8.4 9.2 9.8 10.3 10.8 11.2 11.6 12.0 12.3 12.7 13.1 13.5 14.0 14.6 15.2 16.1 17.7 20.3 26.6

2010 DOE Planned 5.0 6.2 7.1 7.7 8.2 8.6 9.0 9.3 9.6 9.9 10.2 10.5 10.8 11.1 11.5 11.9 12.3 12.9 13.8 15.1 18.3

2015 DOE Planned 5.0 8.4 10.0 11.2 12.1 12.7 13.2 13.6 14.0 14.3 14.6 14.9 15.2 15.5 15.8 16.2 16.6 17.0 17.7 19.1 23.9

2020 DOE Planned 5.0 9.5 11.2 12.5 13.6 14.3 14.8 15.3 15.7 16.0 16.3 16.7 16.9 17.2 17.5 17.9 18.2 18.7 19.2 20.0 23.9

2010 DOE Expanded 5.0 6.6 8.1 9.4 10.5 11.5 12.3 12.9 13.4 13.8 14.2 14.6 14.9 15.2 15.6 16.0 16.4 16.9 17.6 19.3 25.2

2015 DOE Expanded 5.0 8.3 10.1 11.6 13.2 14.3 14.9 15.4 15.8 16.2 16.6 16.9 17.2 17.6 18.0 18.4 18.9 19.5 20.8 23.7 30.0

2020 DOE Expanded 5.0 11.2 13.8 15.7 17.1 17.8 18.3 18.8 19.2 19.5 19.8 20.1 20.5 20.8 21.1 21.6 22.1 22.7 24.2 26.6 30.0

LBD 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Module Cost 0.01 0.05 0.07 0.09 0.10 0.11 0.12 0.12 0.13 0.14 0.15 0.15 0.16 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.27

Inverter Cost 0.01 0.05 0.07 0.09 0.10 0.11 0.13 0.13 0.14 0.15 0.15 0.15 0.16 0.16 0.16 0.16 0.17 0.17 0.18 0.18 0.20

Total System Cost 0.01 0.05 0.07 0.09 0.10 0.11 0.12 0.13 0.14 0.15 0.16 0.17 0.18 0.18 0.19 0.20 0.20 0.21 0.21 0.22 0.24

O&M Cost 0.01 0.04 0.05 0.06 0.07 0.07 0.08 0.09 0.09 0.10 0.10 0.10 0.11 0.11 0.12 0.13 0.13 0.14 0.15 0.16 0.19

Inverter Lifetime 0.01 0.04 0.05 0.06 0.07 0.07 0.08 0.09 0.09 0.10 0.10 0.11 0.11 0.12 0.12 0.13 0.13 0.14 0.15 0.16 0.19
G-1 

Appendix G: Aggregated Percent Likelihoods for Photovoltaic 

(PV) Disruptive Advancements

Technology Advancement

Module 2010 2015 2020 2030 2040 2050

Kerfless wafering @ ~1g/W >20% of 

wafering industry's annual production

No DOE 1% 13% 29% 51% 67% 73%

Planned 1% 19% 40% 63% 70% 73%

Expanded 1% 27% 51% 69% 71% 73%

UMG silicon (no Siemens or FBR 

processing) provides >20% of 

industry's annual cell manufacturing

No DOE 0% 12% 30% 42% 48% 55%

Planned 1% 16% 39% 47% 52% 57%

Expanded 2% 23% 45% 50% 55% 57%

≤100um wafer thickness achieved in 

>20% of annual wiresaw wafering 

production

No DOE 1% 8% 18% 30% 40% 48%

Planned 1% 14% 28% 39% 46% 49%

Expanded 2% 20% 38% 45% 47% 50%

 

 2010 2015 2020 2030 2040 2050

≥15% thin film module efficiency in 

unconcentrated, terrestrial

commercial modules

No DOE 1% 14% 32% 54% 61% 68%

Planned 1% 18% 39% 59% 64% 72%

Expanded 1% 24% 44% 62% 71% 74%

Flexible modules comprise >20% of 

annual market

No DOE 0% 3% 8% 18% 24% 25%

Planned 0% 6% 13% 22% 26% 31%

Expanded 0% 8% 19% 26% 32% 37%

Organic PV modules comprise >20% 

of annual market

No DOE 0% 0% 4% 10% 11% 12%

Planned 0% 2% 6% 11% 12% 17%

Expanded 0% 4% 8% 12% 17% 22%

CIGS modules comprise >20% of 

annual market

No DOE 0% 12% 20% 28% 32% 35%

Planned 0% 15% 23% 30% 32% 35%

Expanded 0% 17% 26% 31% 34% 36%

 

 2010 2015 2020 2030 2040 2050

Use of III-V devices in non-tracking 

modules to achieve commercial 

modules with >25% efficiency at 

competitive cost 

No DOE 0% 3% 6% 21% 27% 30%

Planned 0% 7% 12% 28% 35% 37%

Expanded 0% 13% 22% 35% 40% 44%

Multi-exiton photogeneration or 

intermediate band structure devices 

sold in a commercial terrestrial PV 

product

No DOE 3% 8% 14% 22% 39% 53%

Planned 7% 11% 20% 31% 48% 58%

Expanded 10% 15% 27% 40% 54% 62%

Commercial CPV modules >30% 

efficiency

No DOE 19% 35% 56% 67% 79% 86%

Planned 24% 46% 69% 82% 91% 97%

Expanded 27% 66% 79% 84% 93% 99%
G-2 

Technology Advancement

Inverter/System 2010 2015 2020 2030 2040 2050

Economical 30 year warrantee 

available on > 20% annual inverter 

market

No DOE 4% 14% 38% 80% 81% 82%

Planned 8% 27% 65% 81% 82% 82%

Expanded 16% 50% 70% 81% 82% 82%

AC PV modules (microinverters) 

achieve > 20% annual market share 

of residential rooftop installations

No DOE 0% 19% 36% 60% 68% 78%

Planned 0% 29% 48% 64% 72% 82%

Expanded 0% 39% 56% 68% 76% 86%

20% of new inverters installations 

employ time-of-use pricing operation

No DOE 4% 37% 80% 88% 90% 90%

Planned 12% 54% 82% 88% 90% 90%

Expanded 20% 72% 84% 88% 90% 90%

20% of grid tied systems 

incorporating energy storage 

functionality (i.e. battery or PHEV)

No DOE 0% 13% 44% 74% 81% 86%

Planned 0% 30% 69% 79% 86% 86%

Expanded 0% 62% 72% 84% 86% 86%

Technology Advancement 

Installation and Market Penetration 2010 2015 2020 2030 2040 2050

Physical installation of BIPV shingle 

by non-PV-trained roofer achieves 

>20% of annual residential 

installations

No DOE 11% 28% 58% 73% 81% 86%

Planned 14% 38% 65% 78% 81% 86%

Expanded 18% 49% 74% 78% 82% 87%

Commercial Roofing PV membrane 

comprise >20% of annual commercial 

rooftop installations

No DOE 13% 22% 36% 50% 67% 68%

Planned 16% 28% 46% 59% 69% 71%

Expanded 19% 37% 58% 65% 72% 76%

Highly automated ground installations 

(~1 MW/year/installer) 

No DOE 14% 25% 49% 76% 92% 96%

Planned 22% 37% 64% 92% 96% 96%

Expanded 30% 54% 73% 96% 96% 96%

CPV (>100x concentration) achieves 

20% of annual ground mount 

installations

No DOE 0% 8% 21% 30% 39% 43%

Planned 0% 18% 31% 39% 49% 54%

Expanded 0% 44% 54% 58% 65% 68%
F1146-E(10/2008)

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4. TITLE AND SUBTITLE

2009 Technical Risk and Uncertainty Analysis of the U.S. 

Department of Energy’s Solar Energy Technologies Program 

Concentrating Solar Power and Photovoltaics R&D

5a. CONTRACT NUMBER

DE-AC36-08GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

J. McVeigh, M. Lausten, E. Eugeni, and A. Soni

5d. PROJECT NUMBER

NREL/SR-6A20-48043

5e. TASK NUMBER

SS10.2110

5f. WORK UNIT NUMBER

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

Sentech, Inc.

7475 Wisconsin Avenue

Bethesda, MD 20814

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REPORT NUMBER

KACX-8-88314-04

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National Renewable Energy Laboratory

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NREL

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13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Robert Margolis

14. ABSTRACT (Maximum 200 Words)

The U.S. Department of Energy (DOE) Solar Energy Technologies Program (SETP) conducted a 2009 Technical 

Risk and Uncertainty Analysis to better assess its cost goals for concentrating solar power (CSP) and photovoltaic 

(PV) systems, and to potentially rebalance its R&D portfolio. This report details the methodology, schedule, and 

results of this technical risk and uncertainty analysis.

15. SUBJECT TERMS

Solar Energy Technologies Program; SETP; clean energy; risk analysis; concentrating solar power; CSP; solar 

trough; photovoltaics; PV; solar risk analysis; system cost; energy analysis; Department of Energy; DOE

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