June 2013

U.S. Energy Information Administration | Distributed Generation System Characteristics and Costs in the Buildings Sector 

APPENDIX A
 

EIA Task Order No. DE-DT0000804, Subtask 3 

Photovoltaic (PV) Cost and 

Performance 

Characteristics for 

Residential and 

Commercial Applications 

Final Report 

August 2010 

Prepared for: 

Office of Integrated Analysis and Forecasting 

U.S. Energy Information Administration Prepared by: 

ICF International 

Contact: 

Robert Kwartin 

T: (703) 934-3586 

E: rkwartin@icfi.com 
 

ii 

Table of Contents 

Executive Summary ...................................................................................................................... v

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

1.1 Objective....................................................................................................................1

1.2 Approach....................................................................................................................1

1.3 Report Organization...................................................................................................2

2. Technologies.........................................................................................................................3

2.1 PV Cell Technology ...................................................................................................3

2.2 Modules & Arrays.......................................................................................................6

2.3 Tracking Technology..................................................................................................7

2.4 Inverters.....................................................................................................................8

2.5 System Efficiency.......................................................................................................9

3. Markets ...............................................................................................................................11

3.1 U.S. Market Perspective ..........................................................................................11

3.2 Installation and Financing ........................................................................................11

3.3 International Market Volatility...................................................................................12

4. Historical Costs ...................................................................................................................13

4.1 Installed PV System Costs.......................................................................................13

4.2 Component Costs ....................................................................................................18

5. Forecast of PV Characteristics – Reference Case..............................................................20

5.1 Technical Performance............................................................................................20

5.2 Cost..........................................................................................................................27

6. Forecast of PV Characteristics – Advanced Case ..............................................................38

References..................................................................................................................................40

Appendix A. Recommended Characteristics, Crystalline PV, Reference Case.......................46

Appendix B. Recommended Characteristics, Thin-film PV, Reference Case..........................47

Appendix C. GDP Implicit Price Deflator Index........................................................................48
 

iii 

Tables 

Table 1. PV Prototypes............................................................................................................ v

Table 2. PV Prototypes............................................................................................................1

Table 3. Report Organization...................................................................................................2

Table 4. PV Technologies........................................................................................................4

Table 5. Impact of Azimuth and Tilt on Solar Energy ..............................................................8

Table 6. Derate Factors Used in PVWATTS..........................................................................10

Table 7. Relationship of PVWATTS Derate Factors to Efficiency Values..............................10

Table 8. Installed PV in U.S. through 2008............................................................................13

Table 9. Grid Connected PV Coverage in Tracking the Sun II ..............................................13

Table 10. Grid Connected PV Coverage in Tracking the Sun II ..............................................15

Table 11. Rack Mounted Systems Installed in 2008................................................................17

Table 12. Forecast Parameters, Module Efficiency .................................................................21

Table 13. Forecast Parameters, System Efficiency.................................................................23

Table 14. Forecast Parameters, Degradation (% per yr) .........................................................24

Table 15. Forecast Parameters, Module and Inverter Lifetime (yrs)........................................25

Table 16. Starting Point Inverter Costs (2008$/kWDC) .............................................................27

Table 17. Starting Point Costs for Module Plus Other Components (2008$/kWDC).................27

Table 18. Forecast Parameters, O&M Costs, (2008$ / kWDC / yr) ...........................................37

Table 19. Crystalline Costs, Reference and Advanced Cases ................................................39

Table 20. Thin-film Costs, Reference and Advanced Cases ...................................................39
 

iv 

Figures 

Figure 1. Illustration of Grid-connected PV System..................................................................3

Figure 2. Relationship of PV Cells, Modules, and Arrays.........................................................4

Figure 3. Historical Laboratory Cell Efficiencies – Best Research. ..........................................6

Figure 4. Installed Capacity by State......................................................................................14

Figure 5. Number of Sites by State ........................................................................................15

Figure 6. PV Installed Cost Trends.........................................................................................16

Figure 7. PV Installed Cost Trends by System Size...............................................................17

Figure 8. PV Installed Costs for Crystalline and Thin-film Technologies................................18

Figure 9. Component Costs (systems installed in 2008) ........................................................19

Figure 10. Forecast, Module Efficiency, Reference Case ....................................................22

Figure 11. Forecast, System Efficiency, Reference Case ....................................................23

Figure 12. Forecast, Degradation, Reference Case.............................................................24

Figure 13. Forecast, Module and Inverter Life, Reference Case..........................................26

Figure 14. Normalized Cost Trend for PV Modules and Other Components........................28

Figure 15. Cost Projection for 5 kWDC Crystalline System....................................................29

Figure 16. Recommended Crystalline Installed Costs, Reference Case..............................30

Figure 17. Recommended Thin-film Installed Costs, Reference Case.................................31

Figure 18. Residential Installed Capital Costs, Reference Case..........................................32

Figure 19. Historical and Forecast Residential Capital Costs...............................................33

Figure 20. Commercial Installed Capital Costs, Reference Case.........................................34

Figure 21. Historical and Forecast Commercial Capital Costs .............................................35

Figure 22. Recommended O&M Costs, Reference Case.....................................................37

Figure 23. Cost Trends for Reference Case and Advanced Case .......................................38
 

v 

Executive Summary 

Technical performance and cost characteristics were developed for residential and 

commercial photovoltaic (PV) systems for a time horizon extending to 2035. 

Characteristics were developed for six typical PV systems shown in Table 1. As 

indicated, crystalline and thin-film PV technologies were evaluated in three sizes – 5, 

25, and 250 kWDC. The 5 kWDC size is representative of residential applications, and 

the 25 and 250 kWDC sizes are representative of commercial installations. 

Table 1. PV Prototypes 

Application Technology Size (kWDC) 

Residential Crystalline 5 

Thin-film 5 

Crystalline 25 

250 

25 

Commercial 

Thin-film 

250 

Based on a comprehensive literature search, discussions with PV stakeholders, and 

ICF in-house data, the following characteristics were developed: 

 Module Efficiency1

 

 System Efficiency2

 Degradation 

 Life 

 Installed Capital Costs 

 O&M Costs 

Key results and observations from this study include: 

Module Efficiency. Module efficiencies for crystalline technologies operating in the 

field are estimated to range from 14% in 2008 to 20% in 2035. For thin-film 

technologies, module efficiencies are anticipated to range from 10% to 14% over this 

same time span (2008 to 2035). 

System Efficiency. System efficiencies (DC to AC power) for crystalline technologies 

are expected to increase from levels in the range of 78% to 82% in 2008, to levels in the 

range of 86% to 90% in 2035. For thin-film technologies, system efficiencies are 

forecast to increase from a range of 77% to 81% in 2008, to a range of 86% to 90% in 

2035. 

 

1

 In this report, module efficiency refers to the conversion of sunlight to direct current (DC) power. 2

 System efficiency refers to the conversion of DC to AC power. 
 

vi 

Degradation. Forecast degradation rates for crystalline technologies start at 0.60%/yr 

in 2008, and decline to 0.33%/yr in 2035. Forecast degradation rates for thin-film 

technologies are higher, ranging from 1.00%/yr in 2008 and falling to 0.73%/yr in 2035. 

Lifetime. Crystalline PV modules and balance of plant components (except the 

inverter) are forecast to have an expected lifetime of 25 years in 2008. Thin-film 

modules and balance of plant components (except the inverter) are forecast to have a 

lifetime of 20 years in 2008. Both technologies are forecast to have a lifetime of 30 

years by 2035. Inverters, which are assumed to be identical for both crystalline and 

thin-film technologies, are forecast to have lifetime of 10 years in 2008, rising to 15 

years by 2035. 

Residential Installed Capital Costs (expressed in 2008 dollars). For residential 

systems, crystalline technologies are forecast to have lower costs compared to thin-film 

technologies. Forecast costs for installed residential PV systems are approximately 

$7,100/kWDC (crystalline) and $7,300/kWDC (thin-film) in 2010. These costs fall to 

approximately $4,000/kWDC (crystalline) and $4,100/kWDC (thin-film) by 2035. 

Commercial Installed Capital Costs (expressed in 2008 dollars). For commercial 

applications, thin-film technologies are forecast to have lower costs compared to 

crystalline systems (reverse situation compared to residential systems). In 2010, 

forecast costs for installed commercial PV systems are in the range of $5,500/kWDC

(thin-film, 25 kWDC) to $6,800 (crystalline, 25 kWDC). By 2035, forecast costs are 

estimated to decline to an approximate range of $3,200/kWDC (thin-film, 25 kWDC and 

250 kWDC) to $3,800/kWDC (crystalline, 25 kWDC) 

O&M Costs. O&M consists of periodic system inspection and solar panel cleaning. For 

forecasting purposes, it is assumed that both commercial and residential PV system 

owners will properly maintain their systems. Residential homeowners will likely take a 

“do it yourself” approach, while commercial sites will use a maintenance contract. In the 

case of a DIY approach, a cost is still incurred in terms of time required to complete the 

maintenance. O&M is assumed to scale in direct proportion to panel size, which 

decreases as module efficiency increases, and with overall system capacity (decreases 

as capacity increases). Crystalline O&M costs are forecast to decline 30% between 

2008 and 2035, reaching levels in the range of $11.20/ kWDC to $$16.80/kWDC by 2035. 

For thin-film, forecast costs decline 29%, reaching levels in the range of $16.00/kWDC to 

$24.80/kWDC by 2035. 

The recommended characteristics described above correspond to a reference case, or 

business-as-usual, scenario. In addition to a reference case analysis, an advanced 

case was developed based on more aggressive assumptions concerning technology 

advancements and market penetration. The primary difference between the reference 

case and the advanced case is that installed capital costs decline more quickly over 

time in the advanced case as a result of accelerated R&D investments. 
 

1 

1. Introduction 

The Energy Information Administration (EIA) produces a wide range of analyses and 

reports, including forecasts for energy supply and demand, and the diffusion of 

technologies in the marketplace. To develop forecasts, EIA uses the National Energy 

Modeling System (NEMS), which is a robust model that describes energy markets in the 

United States. Each year, EIA produces the Annual Energy Outlook (AEO), which 

includes projections generated with NEMS. The AEO report covers a time horizon of 25 

to 30 years, and includes market penetration estimates for a wide range of 

technologies, including residential and commercial photovoltaic (PV) systems. 

To develop reliable projections using NEMS, it is important to have accurate technical 

performance and cost characteristics describing supply side and demand side 

technologies. Regarding demand side technologies, the residential and commercial PV 

characteristics that EIA has previously used to support NEMS are based on a solar 

roadmap baseline projection prepared in 2004.3

1.1 Objective 

The objective of this project was to develop a recommended set of technical 

performance and cost characteristics for residential and commercial PV technologies for 

the time period extending from 2010 to 2035. 

1.2 Approach 

ICF conducted a comprehensive literature review and talked with solar experts at 

manufacturing organizations, national laboratories, and academic institutions. This 

information was analyzed and used to shape a forecast of PV characteristics through 

2035. Recommended characteristics were developed for six PV system prototypes as 

shown in Table 2. The 5 kWDC size is intended to be representative of residential 

applications, and the 25 and 250 kWDC capacities are consistent with commercial 

installations (25 kWDC at the low end, and 250 kWDC at the high end). 

Table 2. PV Prototypes 

Capacity (kWDC)

4 Technology 

5, 25, 250 Crystalline 

5, 25, 250 Thin-film 

As indicated in Table 2, the prototypes are based on crystalline and thin-film solar cell 

technology. Multi-junction technologies were also evaluated. However, multi-junction 

technologies are not expected to have significant market penetration in residential and 

 

3

 Our Solar Power Future, The U.S. Photovoltaics Industry Roadmap Through 2030 and Beyond, 

September 2004. 

4

 Unless noted otherwise, all PV power ratings (kWDC) in this report are based on direct current (DC) at 

standard test conditions (STC). Standard test conditions are 1,000 W/m2

 of solar irradiance, cell 

temperature of 25 o

C, and air mass (AM) of 1.5. 
 

2 

commercial applications in the foreseeable future, and prototypes were therefore based 

only on crystalline and thin-film systems. 

Using the prototypes shown in Table 2, a set of recommended PV characteristics was 

developed that is consistent with a reference case scenario. The reference case 

scenario is intended to reflect a business-as-usual outcome, assuming that the current 

pace of R&D investments and policy drivers will prevail over the forecast time horizon. 

In addition to the reference case scenario, a set of recommended PV characteristics 

was also developed for an advanced case. The advanced case is based on a scenario 

that includes higher levels of R&D investments that may accelerate the adoption of 

residential and commercial PV. 

1.3 Report Organization 

This report is organized as shown in Table 3. An overview of PV technologies is 

provided in Section 2, followed by a discussion of markets in Section 3. Historical cost 

trends from 1998 through 2008 are covered in Section 4. In Section 5, PV 

characteristics used in the AEO 2010 report are discussed. Results from discussions 

with PV experts and the literature search are presented in Section 6. In Section 7, 

recommended PV characteristics for a reference case are presented, and in Section 8 

characteristics for an advanced case are described. 

Table 3. Report Organization 

Section Title 

1 Introduction 

2 Technologies 

3 Markets 

4 Historical Costs 

5 Forecast of PV Characteristics – Reference Case 

6 Forecast of PV Characteristics – Advanced Case 
 

3 

2. Technologies 

For residential and commercial PV applications, the two main components are a PV 

array (also called solar array) and an inverter. A third component in many PV 

installations is bank of batteries for energy storage. The PV array produces direct 

current (DC) from sunlight, and the inverter converts the direct current to alternating 

(AC) current. The AC power is then used on site or exported to the grid. A simplified 

schematic for a residential PV installation is shown in Figure 1 (no battery backup). 

Source: Homepower magazine 

Figure 1. Illustration of Grid-connected PV System 

Residential and commercial PV systems can be connected to the grid or configured as 

an off-grid system. Off-grid installations are typically only used in remote locations, and 

have little or no impact on the national energy forecast; as a result, this report is focused 

on grid-connected PV only. 

In this section, key components of a PV system are discussed, including the current 

status and development trends. The discussion is organized into the following sections: 

 PV Cells 

 Modules & Arrays 

 Tracking Systems 

 Inverters 

 System Efficiency 

2.1 PV Cell Technology 

The building block for a PV system is a PV cell (or solar cell). Multiple PV cells are 

interconnected and assembled in a support structure, or frame, to form a PV module (or 

solar panel). Multiple modules are then combined to form a PV array (see Figure 2). 

DC Power AC Power 

Sunlight 
 

4 

Source: NASA 

Figure 2. Relationship of PV Cells, Modules, and Arrays 

Photovoltaic (PV) technologies are constructed using semiconductor materials that have 

the ability to convert sunlight into electricity. PV technologies are typically divided into 

three categories – crystalline silicon, thin-film, and multi-junction (see Table 4). 

Table 4. PV Technologies 

Category Semiconductor Material 

Crystalline Silicon --- 

Cadmium Telluride (CdTe) 

Gallium Arsenide (GaAS) 

Copper Indium Gallium Diselenide (CIGS) 

Thin-film 

Amorphous Silicon (a-SI) 

Multi-junction --- 

Of the three categories, crystalline technologies are the oldest, and were 

commercialized by Bell Labs in the 1950s. Crystalline PV cells are manufactured by 

slicing silicon into thin wafers, with state-of-the-art technology near 170 microns (Shah 

2009). There are two types of crystalline cells – monocrystalline and polycrystalline. 

Compared to polycrystalline cells, monocrystalline cells offer higher efficiencies, but are 

more expensive to manufacture. Polycrystalline cells have lower efficiencies, but are 

lest expensive to manufacture. 

Thin-film PV cells are produced by depositing very thin layers of a semiconductor 

material on an inexpensive substrate, such as glass, plastic, or metal. Table 4 shows 

four common types of semiconductor materials that are used in thin-film PV cells. 

Compared to crystalline technologies, thin-film cells are typically less expensive to 

manufacture, but tend to have lower efficiencies. 
 

5 

Multi-junction cells are fabricated using thin-film techniques, but have two or more 

different semiconductor materials. The semiconductor materials in a multi-junction cell 

capture solar energy from different ranges of the solar spectrum, thereby optimizing the 

conversion of solar energy to electricity. Compared to crystalline and thin-film 

technologies, multi-junction cells are significantly more expensive to manufacture. Due 

to the high cost, multi-junction cells do not currently compete in residential and 

commercial markets. 

Crystalline Technology – Trends and Observations 

Crystalline modules have dominated residential and commercial PV markets. 

Crystalline cell efficiencies in the field have improved from approximately 11% to over 

14% over the past five years (Shah 2009, Barnett 2009). , Efficiencies in the lab, which 

are higher than efficiencies in the field, have reached 26% under standard test 

conditions (STC) (Green 2009).

In recent years, the silicon wafer thickness has been reduced from approximately 300 to 

170 microns, and manufacturers have generally increased warranty times from 20 to 25 

years. Crystalline cell research is currently focused on reducing material costs, 

increasing efficiencies, improving the manufacturing processes, and improving reliability 

of modules (DOE 2008). 

Thin-film Technology – Observations and Trends 

Over the past five years, thin-film efficiencies have increased from the range of 5-8% to 

approximately 10% (Barnett 2009). The thin-film market is currently dominated by 

modules using cadmium telluride (CdTe) as a semiconductor (Maycock and Bradford 

2007; Ullal and von Roedern 2007; Venkataraman 2009). In the lab, CdTe modules 

have reached efficiencies greater than 16% (Green 2009). Two emerging thin-film 

technologies are copper indium diselenide (CIS) and copper indium gallium diselenide 

(CIGS). These two cell technologies have shown lab efficiencies of approximately 19% 

(Green 2009). Another thin-film technology is based on the deposition of amorphous 

silicon (a-Si) less than a micron thick (Maycock and Bradford 2007). One advantage of 

a-Si is that these cells can be manufactured in long continuous rolls rather than by 

batch production (Maycock and Bradford 2007). 

Thin-film technologies continue to undergo advancements. CdTe manufacturers are 

working to standardize film growth equipment, achieve higher efficiencies, and prevent 

moisture ingress (Ullal 2007). CIGS manufacturers are developing standardized layer 

deposition equipment and working to achieve higher efficiencies and reduced layer 

thicknesses (Ullal 2007). 

Cell Efficiency – Observations and Trends 

As indicated in Figure 3, solar cell efficiencies have increased at a steady rate over the 

last several decades (DOE 2006). Efficiencies for advanced multi-junction technologies 

have approached 40% in laboratory settings at STC conditions. However, efficiencies 
 

6 

for practical cells, such as crystalline and thin film technologies, are well below these 

levels in the field. 

Source: NREL (2010) 

Figure 3. Historical Laboratory Cell Efficiencies – Best Research. 

2.2 Modules & Arrays 

Optimizing Performance 

Several environmental factors contribute to system output losses, including sub-optimal 

orientation with respect to the sun, soiling, shading, and seasonal snow cover. The 

soiling factor is the percent of output lost by dirt or any other film that obscures the 

module surface, and ranges from slightly under 1% to 4% (Xantrex 2009). The amount 

of soiling depends on factors such as physical location (proximity to dusty roads, etc.), 

type of dust or film, and length of time since the last rainfall. Regular cleaning 

minimizes the impact of soiling (Xantrex 2009). 

PV modules are connected in series, and a mismatch in electrical output between 

modules will decrease the electrical production of the PV array. Electrical mismatch can 

occur due to shading from buildings, trees, or other obstacles that interfere with direct 

sunlight striking the solar array. The magnitude of the mismatch depends on the array 

area affected, length of time, and time of day (Xantrex 2009). In colder climates, 

seasonal snow cover also shades systems and leads to mismatch. All of these factors 

need to be taken into account when estimating conversion losses of a PV system. 
 

7 

The electrical efficiency of a solar cell in the lab under Standard Test Conditions (STC) 

is almost always higher than the field efficiency, in part due to temperature differences. 

For STC measurements, the solar cell is held at 25 o

C. The efficiency of a solar cell 

decreases with increasing temperature, and the field temperature of a solar cell is 

almost always higher than 25 o

C. Roof mounted arrays can reach temperatures of 70-

80o

C (Wiles 2009). For rooftop conditions, the California Energy Commission 

recommends a de-rating factor of 89% from STC lab conditions to expected field power 

(Xantrex 2009). 

Building Integrated PV (BIPV) 

This report is primarily focused on PV panels that are rack mounted. However, an 

interesting development is the growth of building integrated PV (BIPV). BIPV 

technologies are currently more expensive than rack mounted systems, but BIPV 

breakthroughs could push down PV costs in residential and commercial applications 

(Chiras 2009). 

2.3 Tracking Technology 

Maximum PV output occurs when a solar panel is oriented perpendicular to incoming 

sunlight. The optimum orientation changes through the day as the sun moves across 

the sky, and on a seasonal basis as the height of the sun above the horizon changes. 

Tracking systems can be added to PV arrays to optimize electrical output. 

In most residential applications, PV panels are placed on roof tops in fixed frames (also 

called “racks”), and tracking systems are not utilized. When the panels are located 

directly on the roof top, they are referred to as “flat racked” systems. Unless the roof is 

pitched at the local latitude angle, the system’s power output can be increased by tilting 

the racking to be closer to the latitude angle to capture more sunlight (see Table 5). 

This type of tilting is referred to as “latitude racking.” 

Latitude racking is more expensive than flat-racking for both the residential and 

commercial sectors. Compared to flat-racked systems, significantly more hardware, 

assembly, and labor is involved in latitude racked systems. However, there is a 

financial trade off to consider. Even though flat-racking costs less, the modules are 20-

30% less efficient than latitude racked systems (Focusing on Energy 2008). 

In addition to static latitude racking, more sophisticated dynamic tracking systems can 

be used. Dynamic tracking systems can be either single-axis or dual-axis designs. A 

single axis design follows the daily east-west arc of the sun. With a dual axis system, 

hourly tracking (east-west) is achieved as well as seasonal tracking (north-south). 
 

8 

Table 5. Impact of Azimuth and Tilt on Solar Energy 5

2.4 Inverters 

PV arrays produce direct current (DC) from sunlight; and this DC current is converted to 

alternating (AC) current with an inverter. Inverters are not 100% efficient, and energy is 

lost during this conversion process. 

Today, the highest inverter conversion efficiency of DC to AC power is 96-97%, 

compared to approximately 94% in the 2004 time frame (Waiter 2009). In practice, 

typical inverter efficiencies in the field range from 92% to over 94% (Shah 2009). 

Residential inverters are smaller and slightly less efficient than larger scale commercial 

inverters, which leads to larger conversion losses in the residential sector (Shah 2009). 

For a PV system that includes battery energy storage, there are additional energy 

losses that occur as batteries are charged and discharged. The battery efficiency, 

which is often referred to as the “roundtrip” efficiency, depends on several factors, 

including the type of battery (e.g., lead acid or nickel cadmium) and the state of charge 

 

5

 This table is derived from the NREL Surface Orientation Factor charts in: Christensen, Craig B. 

and Greg M. Barker. Effects of Tilt and Azimuth Angle on Annual Incident Solar Radiation for 

United States Locations. Washington, DC: Proceedings of Solar Forum 2001 – Solar Energy: 

The Power to Choose, April 21-25, 2001. The table is presented for a latitude of approximately 

32o

N.
 

9 

(i.e., near full charge or at some lower charge level). Deep discharge lead acid 

batteries are frequently used for PV applications, and these batteries have a roundtrip 

efficiency level typically near 80% (i.e., 80% of the energy used to charge the battery is 

available for discharge). 

A common configuration for residential and commercial PV systems is to use a single 

inverter (see Figure 1) located near the electrical service panel for the building. PV 

systems that use multiple inverters – referred to as microinverters – are entering the 

market. Microinverters convert DC to AC power in a unit attached directly to each PV 

module, instead of through a single stand-alone inverter that serves the entire PV array. 

Microinverters are an emerging technology, and there is limited data available to assess 

actual performance and costs. However, potential advantages of microinverters may 

include: 

 Increased reliability. A separate inverter for each module means there is no 

single point of failure. If one microinverter fails, other modules continue to 

operate. 

 Longer life. Enphase, a manufacturer of microinverters, reports that their 

microinverters are designed for a service life greater than 20 years.6

 

 Improved performance of each module. A separate microinverter on each 

module maximizes performance of that module. 

 Lower installation costs. Simplified installation with no wiring required for a 

central inverter. 

2.5 System Efficiency 

Inverters are just one source of power loss when converting from DC to AC power. An 

example of other factors that contribute to power losses in PV systems is shown in 

Table 6. This table, which is taken from NREL data used in the PVWATTS tool, shows 

that there are 10 factors in addition to the inverter that may contribute to power losses. 

For the default values in the PVWATTS tool, the inverter derate factor is 0.92 and the 

overall derate factor is 0.77. 

In this report, a detailed analysis and forecast of derate factors, or efficiency losses, by 

component, was not conducted. Rather, the analysis and forecast was divided into two 

categories: 

 System efficiency (includes all factors that contribute to DC to AC power with 

the exception of age) 

 Degradation (accounts for power losses that occur due to the age of the 

system) 

 

6

 Enphase web site, 

http://www.enphaseenergy.net/downloads/Enphase_WhitePaper_Reliability_of_Enphase_Microinverters.pdf , accessed March 2010. 
 

10 

A cross map of PVWATTS derate factors and efficiency factors used in this report is 

show in Table 7. 

Table 6. Derate Factors Used in PVWATTS 

Component Derate Factors PVWATTS Default Range 

PV module nameplate DC rating 0.95 0.80 - 1.05 

Inverter and Transformer 0.92 0.88 - 0.98 

Mismatch 0.98 0.97 – 0.995 

Diodes and connections 1.00 0.99 – 0.997 

DC wiring 0.98 0.97 - 0.99 

AC wiring 0.99 0.98 – 0.993 

Soiling 0.95 0.30 – 0.995 

System availability 0.98 0.00 – 0.995 

Shading 1.00 0.00 - 1.00 

Sun-tracking 1.00 0.95 - 1.00 

Age 1.00 0.70 - 1.00 

Overall DC-to-AC derate factor 0.77 --- 

Source: NREL PVWATTS, http://rredc.nrel.gov/solar/calculators/PVWATTS/system.html 

Table 7. Relationship of PVWATTS Derate Factors to Efficiency Values 

Derate Component in PVWATTS Efficiency Component in this Report 

PV module nameplate DC rating 

Inverter and Transformer 

Mismatch 

Diodes and connections 

DC wiring 

AC wiring 

Soiling 

System availability 

Shading 

Sun-tracking 

System Efficiency (changes by year, 

cell material, and capacity) 

Age Degradation Rate (changes by year and 

PV cell material) 
 

11 

3. Markets 

3.1 U.S. Market Perspective 

Federal, state, and utility incentives provide strong drivers that push the adoption of PV 

systems. At the Federal level, there is an investment tax credit (ITC), which provides an 

income tax credit for residential and commercial PV installations. The ITC was revised 

in 2009 as part of the American Recovery and Reinvestment Act (ARRA). ITC 

provisions in ARRA that specifically relate to PV include: 

 30% ITC extended through end of 2016 for both residential and commercial 

solar installations 

 $2,000 cap eliminated for residential PV 

 Utilities allowed to benefit from credit (utilities were previously excluded) 

 Tax payers (both individuals and businesses) that are required to file 

Alternative Minimum Tax (AMT) are allowed to claim credit (previously 

excluded) 

PV market size, maturity, and total installed costs vary widely from state to state. The 

growth of residential and commercial PV markets within a state has been driven almost 

entirely by state-based incentive programs (Venkataraman 2009). The overwhelming 

majority of residential and commercial PV installations have occurred in just two states 

– California and New Jersey (Wiser 2009). Both of these states have well developed 

incentive programs that have stimulated PV adoption. 

In addition to capacity based incentives and performance based incentives, states have 

used a variety of other tools to encourage the installation of PV, including sales and 

property tax exemptions, net metering laws, feed-in tariffs, solar access laws, 

standardized and liberalized interconnection procedures, etc. The incentive mix 

changes continuously; refer to the Database of State Incentives for Renewables and 

Efficiency (DSIRE) for the most recent information (DSIRE 2009). 

3.2 Installation and Financing 

Historically, the installation of PV systems has been performed by companies that 

specialize in PV. However, the drop in demand for new construction and building 

retrofit work, coupled with growing demand for end-use PV, has motivated construction 

companies, roofing contractors, and electrical contractors to enter the PV installation 

business (Shah 2009). With their project management and business experience, these 

companies are streamlining the installation process and increasing competition within 

the industry. 

In addition, new financing methods have begun to emerge that are encouraging the 

adoption of PV systems. The financial factors that influence a consumer’s decision to 

purchase include upfront costs, financial incentives, utility bill savings, and maintenance 

costs. Due to the current weak economic conditions, residential homeowners and 
 

12 

commercial building owners/developers are reluctant to make expensive capital 

investments such as PV (Coughlin 2009). New financing methods, such as the 

commercial solar power purchase agreement (SPPA) and the residential solar lease, 

seek to overcome these financial barriers by significantly reducing or eliminating the 

upfront cost to commercial and residential customers (Coughlin 2009). 

3.3 International Market Volatility 

The U.S. PV industry is influenced by the volatility of the larger international solar 

market. Manufacturers focus their attention, and their sales, on the fastest growing and 

most profitable markets. For example, Spain’s feed-in tariff motivated rapid growth and 

made Spain the largest PV market in the world in 2008. Unprecedented demand in 

Spain put a strain on global supply that kept equipment costs high in the U.S. and 

elsewhere in the world (Tarbell 2009). Growth in Spain has slowed recently, but growth 

in other markets has picked up. For example, Germany installed 3.8 GW of PV in 2009, 

and 1.45 GW in December alone.7

 

7 http://www.pv-tech.org/lib/printable/8828, accessed May 2010.
 

13 

4. Historical Costs 

Historical costs for PV systems are discussed in this section, which is organized as 

follows: 

 Installed PV System Costs 

 Component Costs 

4.1 Installed PV System Costs 

Technological developments across the PV supply chain, from commodities to 

efficiencies, have pushed total installed costs downward. An increase in silicon 

manufacturing has increased supply and lowered the price of silicon in crystalline PV 

modules (Hasan 2009). Improved manufacturing processes have increased the 

production output of facilities, while decreasing the costs of production (GT Solar 2009). 

In recent years, streamlined manufacturing has led to decreased manufacturing costs.

Machine manufacturers have begun to offer turn-key production lines which are 

complete manufacturing system packages. Turn-key solutions are sold for every stage 

of the supply chain, from wafer fabrication to module fabrication (GT Solar 2009). These 

automated turn-key production lines have helped increase productivity, quality, and 

yields, while lowering manufacturing costs. Automated systems have also made it 

easier for new firms to enter the manufacturing arena, thereby increasing competition 

and putting downward pressure on prices. 

A recent report titled “Tracking the Sun II” by Lawrence Berkeley National Laboratory 

summarizes the installed cost of PV systems in the United State from 1998 through 

2008. Costs in this report cover approximately 52,000 residential and non-residential 

systems, with a total capacity of 566 MW (71% of grid connected capacity in the United 

States at the end of 2008). PV installed capacity and coverage as reported in Tracking 

the Sun II are shown in Table 8 and Table 9, respectively. 

Table 8. Installed PV in U.S. through 2008 

Type of Installation Capacity 

(MW) (%) 

Grid Connected 798 88% 

Off Grid 109 12% 

Total 906 100% 

Table 9. Grid Connected PV Coverage in Tracking the Sun II 

Capacity 

(MW) (% of all grid 

connected) 

(% of all PV) 

Covered in TS II 566 71% 62% 

Not Covered in TS II 231 29% 26% 

Total Grid Connected 798 100% 88% 
 

14 

PV system data reported in Tracking the Sun II was collected from 16 states. A 

comparison of the PV installed capacity across the 16 states is shown in Figure 4, and 

a comparison of the number of PV installations by state is shown in Figure 5. As 

indicated, California has the highest representation in the sample, followed by New 

Jersey. 

AZ

1% MA

1%

CT

2%

NY

1% Other 10 States

2%

NJ

11%

CA

82%

Figure 4. Installed Capacity by State 
 

15 

NY

AZ 2%

MA 2%

2%

CT

1%

NJ

6%

Other 10 States

5%

CA

82%

Figure 5. Number of Sites by State 

Average annual costs for all PV systems in the LBNL sample are shown in Table 10 

and graphed in Figure 6. These data are based on all system types in the data sample 

(e.g., rack-mounted, building integrated, tracking, non-tracking, crystalline, thin-film, 

etc.). As indicated in the table, the simple average of PV installed costs has declined 

from $12,260/kWDC in 1998 to $8,243 in 2008 (a total decrease of 33%, or 3.9% per 

year). 

Table 10. Grid Connected PV Coverage in Tracking the Sun II 

Year Number of Installed Cost (2008$ / kWDC) 

Systems 

Capacity (MW)

Capacity Weighted Simple Average 

1998 39 0.2 10,849 12,260 

1999 180 0.8 10,600 11,611 

2000 217 0.9 9,485 10,900 

2001 1,308 5.4 9,768 10,492 

2002 2,489 15.0 9,754 10,455 

2003 3,526 34.0 8,370 9,308 

2004 5,527 44.0 8,287 8,566 

2005 5,193 57.0 7,770 8,264 

2006 8,677 90.0 7,838 8,385 

2007 12,103 122.0 7,837 8,474 

2008 13,097 197.0 7,480 8,243 

52,356 566.3 
 

16 

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

Installed Cost (2008$ / kWDC)

Capacity Weighted

Simple Average

Figure 6. PV Installed Cost Trends 

Figure 7 shows a breakout of historical PV costs by size range. Systems less than 100 

kWDC showed a steady decline from 1998 through about 2005, and then remained 

generally flat from 2005 through 2007, followed by a decline in installed costs for 2008. 

Compared to systems under 100 kWDC, there are far fewer systems with capacities 

above 100 kWDC, and the data are somewhat more scattered for these larger systems. 

However, based on Figure 7, it is clear that there are economies of scale, with larger 

systems consistently showing lower costs. 
 

17 

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Installation Year

Average Installed Cost (2008$ / kWDC)

<5 kW

5-10 kW

10-100 kW

100-500 kW

>500 kW

Figure 7. PV Installed Cost Trends by System Size 

Table 11 shows average costs for rack mounted PV technologies in 2008 with a 

breakdown for crystalline and thin-film technologies in three size categories. In 2008, 

similar to other years, the majority of PV installations have used rack mounted 

crystalline technology. In 2008, over 10,500 rack mounted crystalline systems were 

installed, representing 80% of the total PV installations tracked by LBNL in 2008 

(13,097 total systems in 2008). 

Table 11. Rack Mounted Systems Installed in 2008 

Technology 

Crystalline Thin-film 

Size 

Number of 

Systems 

Capacity 

(MW) 

Cost 

(2008$/kWDC) 

Number of 

Systems 

Capacity 

(MW) 

Cost 

(2008$/kWDC) 

< 10 kWDC 9,179 43 8,200 22 0.1 8,500 

10-100 kWDC 1,098 24 7,900 16 0.7 6,400 

>100 kWDC 242 86 7,200 6 2.4 6,700 

10,519 153 44 3.2 

Compared to the population of crystalline systems, LBNL identified far fewer rack 

mounted thin-film installations. As indicated in Table 11, there are only 44 total thin film 

systems identified in all three size categories, with a combined capacity of 3.2 MW. 
 

18 

While the cost numbers for the thin-film systems seem reasonable (range from 

$6,400/kWDC to $8,500/kWDC), these results should be viewed with caution given the 

small sample size. The cost numbers for thin-film technologies could change 

significantly as the sample size grows and becomes more statistically relevant. 

Figure 8 compares the average costs for crystalline and thin-film technologies by the 

three size categories. For systems <10 kWDC, crystalline technologies show slightly 

lower costs -- $8,200/kWDC for crystalline compared to $8,500 for thin-film. However, 

for systems >10 kWDC, thin-film technologies have lower costs. In the 10-100 kWDC size 

range, the cost differential is $1,500/kWDC ($7,900/kWDC compared to $6,400/kWDC), 

and in the >100 kWDC size range the differential is $500/kWDC ($7,200/kWDC compared 

to $6,700/kWDC). 

8,200

7,900

7,200

8,500

6,400

6,700

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

< 10 kW 10-100 kW >100 kW

Size 

Cost (2008$/kWDC)

Crystalline

Thin Film

Figure 8. PV Installed Costs for Crystalline and Thin-film Technologies 

4.2 Component Costs 

Component level cost data are scarce. However, in Tracking the Sun II component 

costs are reported for a single year (2008) as shown in Figure 9. The costs in this 

figure are average costs for crystalline and thin-film technologies combined. The costs 
 

19 

are separated into three different size ranges – 1) under 10 kWDC, 2) 10-100 kWDC, and 

3) >100 kWDC. 

$4,600 $4,500

$3,900

$2,900

$2,600

$2,800

$500

$600

$700

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

<10 kW 10-100 kW >100 kW

Size

Average Cost (2008$ / kWDC)

Other

Inverter

Module

(56%)

(9%)

(35%)

(58%)

(8%)

(34%)

(54%)

(7%)

(39%)

Figure 9. Component Costs (systems installed in 2008) 

As indicated in Figure 9, module costs account for the largest fraction of PV installed 

costs, ranging from 54% to 58% of the average total installed cost. Module costs are 

$600 to $700/kWDC lower for systems over 100 kWDC compared to the two small size 

bins, which suggests that there are may be bulk purchasing discounts that help reduce 

module costs for large systems. 

Based on 2008 system data in the LBNL Tracking the Sun II report, inverters account 

for 7% to 9% of the total installed cost. As system sizes increase, inverter costs show 

declining costs (decline from $700/kWDC in smallest size bin to $500/kWDC in largest 

size bin). A report prepared by Navigant for NREL (NREL 2006) offers additional 

insights into inverter costs. In this report, which is based on data from 2006, inverters 

are estimated to account for 10-20% of the initial PV system installed cost (higher than 

the 7-9% reported by LBNL in 2008) 

In Figure 9, the “other” category includes costs associated with design, engineering, 

installation labor, and regulatory compliance. These other expenses account for a third 

or more of total installed costs (range from 34% to 39% depending on PV size). 
 

20 

5. Forecast of PV Characteristics – Reference Case 

While there is ample research and analysis on the size and scope of the PV market, 

there are few detailed forecasts regarding PV costs and technical performance in the 

public domain. To develop a PV forecast, ICF collected information from several 

sources, including interviews with industry PV stakeholders, publicly available literature, 

and in-house ICF data. The data were grouped into three capacities (5, 25, and 250 

kWDC) and two technology types (crystalline and thin-film), resulting in six unique PV 

technology categories. 

No rigid formula was used to develop a composite industry forecast of PV technical 

performance and cost characteristics. Rather, all data were examined, and data that 

appeared to lie well outside norms were excluded. The remaining data were further 

examined and ICF forecasts were developed. 

The characteristics described in this section correspond to a reference case scenario 

consistent with the assumptions used for the reference case described in the AEO 2010 

report. The discussion of recommended reference case characteristics is organized as 

follows: 

 Technical Performance 

o Module Efficiency 

o System Efficiency 

o Degradation 

o Lifetime 

 Cost 

o Component Costs (including inverter) 

o Installed Capital 

o O&M 

For reference, tables with selected results for the reference case are shown in 

Appendix A (crystalline technologies) and Appendix B (thin-film technologies). In 

these tables, and elsewhere in this report, costs are reported in 2008 dollars unless 

noted otherwise. Conversions between dollar years, if necessary, have been calculated 

using a gross domestic product (GDP) index shown in Appendix C. 

5.1 Technical Performance 

5.1.1 Module Efficiency 

Module efficiencies are primarily dependent on the type of solar cell, and no significant 

efficiency differences are expected for different capacities. However, different efficiency 

curves are expected for crystalline and thin-film technologies. 
 

21 

To develop a forecast, ICF estimated values for module efficiency when installed in the 

year 2008, and then looked at potential upper limits. A range of module efficiencies 

were examined from manufacturers, industry experts, and research reports. Based on 

this review, ICF selected an average crystalline module efficiency in 2008 of 14%, and 

an average thin-film module efficiency of 10%. The analysis also suggested that a 

reasonable upper limit for crystalline modules is 20%, and a reasonable upper limit for 

thin-film is 14%. 

Note that these module efficiencies are based on field performance, and not laboratory 

measurements. Laboratory measurements conducted at standard test conditions 

almost always exceed average field performance values. 

Linear improvement rates were then developed to connect the starting values and end 

points. The improvement rates were adjusted by “eye” to achieve a smooth transition 

over time. The module efficiency forecast parameters are shown in Table 12, and the 

resulting values are shown in Figure 10. 

Table 12. Forecast Parameters, Module Efficiency 

PV Cell Technology 

Crystalline Thin-film 

Starting Value (2008) 14% (0.140) 10% (0.100) 

Annual Change +0.005 thru 2018 +0.002 thru 2028 

 +0.001 thru 2028 --- 

 no change after 2028 no change after 2028 

Value in 2035 20% 14% 
 

22 

0%

5%

10%

15%

20%

25%

2005 2010 2015 2020 2025 2030 2035

Year

Module Efficiency (%)

Crystalline

Thin-film

 

Figure 10. Forecast, Module Efficiency, Reference Case 

5.1.2 System Efficiency 

The overall efficiency of a PV system is determined by several factors, including inverter 

losses, resistance of wires and connectors, soiling, and module mismatch. While these 

factors affect all types of PV systems, there are also differences between PV system 

types. Residential inverters are smaller and therefore less efficient than commercial 

inverters, leading to generally lower system efficiencies in residential PV technologies 

(all other factors being equal). 

Similar to module efficiencies, linear improvement rates were developed to connect 

starting values and end points. The improvement rates were adjusted to achieve a 

smooth transition over time. The system efficiency forecast parameters are shown in 

Table 13, and the resulting system efficiency curves are shown in Figure 11. 
 

23 

Table 13. Forecast Parameters, System Efficiency 

PV Cell Technology 

Crystalline Thin-film 

5 kW 25 kW 250 kW 5 kW 25 kW 250 kW 

Starting 

Value (2008) 

78% 80% 82% 77% 79% 81% 

+0.01 thru 2012 +0.01 thru 2012 

+0.005 thru 2020 +0.005 thru 2022 

Annual 

Change 

no change after 2020 no change after 2022 

Value in 

2035 

86% 88% 90% 86% 88% 90% 

As indicated, crystalline system efficiencies are expected to increase from levels in the 

range of 78% to 82% in 2008, to levels in the range of 86% to 90% in 2035. For thin-film 

technologies, the efficiencies increase from the range of 77% to 81% in 2008, to 86%to 

90% by 2035 (same end point for thin film as crystalline). 

75%

80%

85%

90%

95%

100%

0 5 10 15 20 25 30

Year

System Efficiency (%)

Crystalline, 5 kW

Crystalline, 25 kW

Crystalline, 250 kW

Thin-film, 5 kW

Thin-film, 25 kW

Thin-film, 250 kW

Figure 11. Forecast, System Efficiency, Reference Case 
 

24 

5.1.3 Degradation 

PV modules typically lose capacity over time as a result of UV effects on construction 

materials and other aging factors. The rate at which modules lose capacity is 

debatable. However, based on sources consulted for this report ICF selected the 

starting values and annual change rates shown in Table 14. Based on these 

parameters, the resulting degradation curves are shown in Figure 12. 

Table 14. Forecast Parameters, Degradation (% per yr) 

PV Cell Technology 

Crystalline Thin-film 

Starting Value (2008) 0.60% (0.0060) 1.00% (0.1000) 

Annual Change -0.0001 thru 2035 

Value in 2035 0.33% 0.73% 

0.0%

0.1%

0.2%

0.3%

0.4%

0.5%

0.6%

0.7%

0.8%

0.9%

1.0%

2005 2010 2015 2020 2025 2030 2035 2040

Year

Degradation (% / yr)

Crysalline

Thin-film

Figure 12. Forecast, Degradation, Reference Case 

In the ICF forecast, the degradation rate for crystalline technologies declines by about 

45% between 2008 and 2035 (0.60% to 0.33%), and by about 27% for thin film 

technologies (1.00% to 0.73%). Over the forecast horizon, thin-film degradation rates 

are held higher than crystalline technologies. 
 

25 

Thin-film technologies have a higher surface area than crystalline systems for 

equivalent rated capacity, and a higher surface area could contribute to higher 

degradation rates. However, in general, there are no fundamental reasons that thin-film 

systems should have higher degradation rates than crystalline systems. However, 

compared to crystalline technologies, there are fewer thin-film technologies currently 

being used in residential and commercial applications. The higher degradation rate for 

thin-film technologies is a conservative value based on a smaller data set with 

potentially unknown or not-well characterized degradation factors. 

5.1.4 Lifetime 

Thin-film technologies are relatively new, and there is little field experience data 

available to support lifetime projections. However, for forecasting purposes, ICF 

assumed that thin-film systems would follow similar lifetime trends as more mature 

crystalline technologies, but lag behind in terms of the time required to achieve these 

lifetime estimates. For crystalline technologies, ICF developed the forecasting 

parameters shown in Table 15. This table also shows the forecasting parameters 

developed for thin-film technologies and inverters. 

Table 15. Forecast Parameters, Module and Inverter Lifetime (yrs) 

PV Cell Technology 

Crystalline Thin-film 

Inverter 

Starting Value (2008) 25 yrs 20 yrs 10 yrs 

Annual Change + 0.5 yrs thru 2018 + 0.5 yrs thru 2018 + 0.5 yrs thru 2018 

 + 0.5 yrs thru 2018 + 0.5 yrs thru 2018 + 0.5 yrs thru 2018

 no change after 2018 no change after 

2028 

no change after 

2018 

Value in 2035 30 yrs 30 yrs 15 yrs 

Lifetime forecasts are shown in Figure 13. As indicated, the lifetime of thin-film 

modules is forecast to lag crystalline modules through 2028. From 2028 onward, the 

lifetime for both technologies is assumed to be 30 years. For forecasting purposes, 

ICF is estimating that average inverter lifetimes will start at 10 years in 2008, and 

increase to 15 years by 2018. 
 

26 

0

5

10

15

20

25

30

35

2005 2010 2015 2020 2025 2030 2035 2040

Year

Lifetime (yrs)

Crystalline

Thin-film

Inverter

Figure 13. Forecast, Module and Inverter Life, Reference Case 
 

27 

5.2 Cost 

Long term cost projections for residential and commercial PV installations are scarce in 

the literature. However, industry stakeholders did provide opinions on long term cost 

trends. These opinions were combined with ICF in-house data to develop cost 

projections, which are provided in the following subsections: 

 Component costs (including inverters) 

 Installed capital costs 

 O&M costs 

5.2.1 Component Costs 

For forecasting purposes, PV components were divided into three categories 

 Module 

 Inverter 

 Other (installation labor, regulatory compliance, and overhead) 

ICF set the starting point costs for inverters to be consistent with data reported in the 

LBNL Tracking the Sun II report (see Figure 9). These inverter starting point costs are 

shown in Table 16. 

Table 16. Starting Point Inverter Costs (2008$/kWDC) 

Cost by System Size ($/kWDC) – same for crystalline and thin-film 

5 kWDC 25 kWDC 250 kWDC

$700 $600 $500 

Starting point costs for modules and other components (less the inverter) were 

combined and calculated by subtracting inverter costs from the total costs reported by 

LBNL for crystalline and thin-film technologies. These costs are shown in Table 17. 

Table 17. Starting Point Costs for Module Plus Other Components 

(2008$/kWDC) 

` Cost by System Size ($/kWDC) 

5 kWDC 25 kWDC 250 kWDC

Crystalline $7,500 $7,300 $6,700 

Thin-film $7,800 $5,800 $6,200 

Cost trends over time were then developed for modules and other components based 

on input from PV stakeholders and ICF in-house data. Module and other costs (less the 

inverter) were assumed to follow the same cost trend, which is shown in Figure 14. 
 

28 

0%

20%

40%

60%

80%

100%

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Year

Cost Relative to 2008

Figure 14. Normalized Cost Trend for PV Modules and Other Components 

(does not apply to inverter) 

Inverter costs presented somewhat of a dilemma. The technical performance of 

inverters is evolving (e.g., development of microinverters), but there is mixed 

information on whether inverter costs are declining or remaining steady. Some PV 

stakeholders suggested that inverter costs are remaining steady, although price 

declines have occurred in recent months.8

 ICF weighed the limited information 

available for inverter costs, and chose to forecast inverter costs as remaining 

unchanged in future years (same costs for crystalline and thin-film technologies). It is 

expected that inverter performance features will continue to advance, but for forecasting 

purposes ICF assumed that manufacturers will hold inverter prices relatively constant as 

inverter performance improves (i.e., inverter value will increase, but prices will remain 

steady). 

An example of how the forecast costs for modules, inverters, and other components 

changes over time is shown in Figure 15. This figure corresponds to a 5 kWDC

crystalline PV system. As indicated, costs start at $8,200/kWDC ($700 inverter plus 

$7,500 for module and other components) in 2008, with inverters accounting for 9% of 

the installed cost. Inverters remain flat over the forecast horizon, while module and 

 

8

 Solarbuzz provides an index of monthly inverter and PV module costs 

(http://www.solarbuzz.com/Inverterprices.htm ). 
 

29 

other components decline. By 2035, the total installed cost is forecast to decline to 

$4,000/kWDC with inverters accounting for 18% of the total installed cost. Similar 

behavior is forecast for thin film technologies and larger sizes (25 kWDC and 250 kWDC). 

Inverter

Module & Other 

Components

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Year

Cost (2008$/kW)

Figure 15. Cost Projection for 5 kWDC Crystalline System 

5.2.2 Installed Capital Costs 

Using the methodology described in the previous section, installed capital cost forecasts 

were developed for crystalline and thin-film technologies. Reference case cost 

projections for three sizes (5, 25, and 250 kWDC) of crystalline technologies are shown 

in Figure 16, and cost projections for the same three sizes of thin-film technologies are 

shown in Figure 17. Unless noted otherwise, all costs are reported in 2008 dollars. 

As indicated, installed capital costs for all three crystalline sizes start in the range of 

$7,000 to slightly greater than $8,000/kWDC in 2008, and then decline to a range 

between $3,500 and $4,000/kWDC in 2035. For thin film technologies, the 5 kWDC size 

starts at approximately $8,500/kWDC in 2008 and declines to slightly above 

$4,000/kWDC in 2035. The larger 25 and 250 kWDC sizes start near $6,500/kWDC in 

2008, and decline to slightly above $3,000/kWDC in 2035. 
 

30 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

5 kW

25 kW

250 kW

Figure 16. Recommended Crystalline Installed Costs, Reference Case 

One unexpected result shown in Figure 17 is that costs for a 250 kWDC thin-film system 

are forecast to be slightly higher than a 25 kWDC system. Based on economy of scale 

considerations, one would expect costs for a 250 kWDC system to be lower than a 25 

kWDC system. However, these forecasts are consistent with historical costs, which do 

show an up turn in costs for large thin film PV systems. Historical PV costs are 

discussed in Section 4.1, and this discussion includes an important note concerning 

thin-film costs. As mentioned in Section 4.1, historical thin-film costs should be viewed 

with caution because these costs are based on a small sample size. It would not be 

surprising if future thin-film costs follow economy of scale considerations (i.e., costs 

decline as capacities increase). 
 

31 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

5 kW

25 kW

250 kW

Figure 17. Recommended Thin-film Installed Costs, Reference Case 

Figure 18 offers a perspective of how the forecast PV costs correspond to residential 

applications. In this figure, 5 kWDC crystalline and 5 kWDC thin-film costs are shown, 

which are representative of the residential market. As indicated, costs start in the range 

of $8,000 to $8,500/kWDC in 2008, and then decline to approximately $4,000/kWDC by 

2035. More specifically, costs are approximately $7,100 (crystalline) and $7,300 (thinfilm) in 2010. These costs fall to approximately $4,000/kWDC (crystalline) and 

$4,100/kWDC (thin-film) by 2035. 
 

32 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2000 2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

Crystalline 5 kW

Thin-film 5 kW

Figure 18. Residential Installed Capital Costs, Reference Case 

Figure 19 includes both historical residential PV installed costs along with 

recommended residential costs. Historical costs have fluctuated, but the trend over the 

next 5-10 years in recommended PV costs is generally consistent with historical cost 

trends over the past decade. As the market matures, PV costs begin to stabilize and 

decline at lower rates. 
 

33 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

2000 2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

Historical, < 10 kW

Crystalline, 5 kW

Thin-film, 5 kW

Figure 19. Historical and Forecast Residential Capital Costs 

Recommended commercial capital costs are shown in Figure 20. This figure includes 

recommended forecast values for four technologies (crystalline 25 kWDC, crystalline 250 

kWDC, thin-film 25 kWDC, and thin-film 250 kWDC). As indicated, installed costs for 

commercial PV installations range from approximately $6,500 to $8,000/kWDC in 2008, 

and then decline to a range between $3,000 and $4,000/kWDC in 2035. More 

specifically, commercial costs in 2010 are approximately $5,500/kWDC (thin-film, 

25kWDC), $5,800/kWDC (thin-film, 250 kWDC), $6,200/kWDC (crystalline, 250 kWDC), and 

$6,800 (crystalline, 25 kWDC). In 2035, the costs are approximately $3,200/kWDC (thinfilm, 25 kWDC and 250 kWDC), $3,500/kWDC (crystalline, 250 kWDC), and $3,800/kWDC

(crystalline, 25 kWDC) 

For perspective, historical and forecast trends are shown in Figure 21. Similar to the 

residential results, historical cost trends have fluctuated, but the recommended cost 

trends over the next 5-10 years are generally consistent with historical trends. Similar 

to residential prices, the commercial prices begin to stabilize as the market matures. 
 

34 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2000 2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

Crystalline, 25 kW

Crystallline, 250 kW

Thin-film, 25 kW

Thin-film, 250 kW

Figure 20. Commercial Installed Capital Costs, Reference Case 
 

35 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2000 2005 2010 2015 2020 2025 2030 2035

Year

Cost (2008$/kW)

Crystalline, 25 kW

Crystalline 250 kW

Thin-film, 25 kW

Thin-film, 250 kW

Historical, >10 kW

Figure 21. Historical and Forecast Commercial Capital Costs 

The forecast of installed capital costs presented in this report was developed based on 

opinions from PV stakeholders and other data sources concerning how costs may 

change over the next couple decades. The forecast was not developed in conjunction 

with a detailed demand forecast. While demand was not formerly considered, it is 

interesting to consider how the installed capital costs projected in this report might be 

correlated with a demand forecast. 

Concerning the relationship of demand and PV costs, a recent EPRI report (EPRI 2009) 

presented data showing the global average sales price of PV modules as a function of 

cumulative sales between 1976 and 2008. During this time period, the market size 

grew by approximately a factor of 100,000 and prices fell by more than 90%. Based on 

the historical data, the EPRI report authors concluded that prices have been declining 

by about 20% in recent years for each doubling of market size (i.e., learning rate of 

20%). The authors also concluded that the PV market has been growing by about 20% 

per year in recent years. 

The ICF forecast of installed capital costs turns out to be more conservative compared 

to the results reported by EPRI. In rough terms, the ICF forecast shows a reduction of 

installed capital costs of approximately 50% between 2008 and 2035. This installed 

cost behavior is consistent with a learning rate of 12%, and an annual growth rate of 
 

36 

15%. The EPRI estimates suggest that learning rates and annual growth rates may 

both be closer to 20% over the next two to three decades. 

5.2.3 O&M 

For the purposes of this report, operation and maintenance (O&M) costs are assumed 

to include regular inspection and cleaning. Major maintenance requirements, such as 

replacing an inverter, are not included. 

For PV systems, routine O&M consists primarily of washing the solar panels to ensure 

that electricity production is maximized. In both residential and commercial applications, 

it is possible that systems will not be properly maintained, including periodic washing of 

PV panels, in which case degradation rates will likely exceed the values reported 

previously in this report. However, for forecasting purposes, it is assumed that both 

residential and commercial PV installations will be properly maintained. 

In the case of a commercial PV installation, it is reasonable to assume that a 

maintenance contract will be used to cover O&M. Maintenance contracts for basic 

service of commercial systems have been reported by SunEdison and others to be in 

the range of $15/kW to $25/kW (costs generally declining as system size increases). 

For a residential PV installation, it is likely that a homeowner will take a “do it yourself” 

(DIY) approach for system inspection and cleaning. Even though a cash expense is not 

incurred for a DIY approach, the homeowner does incur an expense in terms of time 

required to complete PV system O&M. In some residential applications, it is possible 

that homeowners will choose to pay for routine PV inspection and cleaning, rather than 

undertaking these chores. In the forecast presented in this report, an O&M cost is 

assigned to residential PV installations to reflect the value of time for a DIY approach, or 

the cost of an O&M contract. 

The O&M forecast was developed by starting with a $20/kW O&M cost for a 25 kW 

crystalline system. Costs were scaled by +/- 20% based on size (5 kW more expensive, 

250 kW less expensive). It was further assumed that O&M will scale with surface area, 

since O&M is primarily associated with panel cleaning. O&M costs were therefore 

scaled using the module efficiencies discussed previously. A summary of the forecast 

parameters is shown in Table 18, and a graph of the O&M costs over time is shown in 

Figure 22. 
 

37 

Table 18. Forecast Parameters, O&M Costs, (2008$ / kWDC / yr) 

PV Cell Technology 

Crystalline Thin-film 

5 kWDC 25 kWDC 250 kWDC 5 kWDC 25 kWDC 250 kWDC

Starting $24.00 $20.00 $16.00 $33.60 $28.00 $22.40 

Value (2008) (20% more 

than 25 kW) 

(20% less 

than 25 kW) 

 

Annual 

Change 

Adjust based on module efficiency (see Table 12 and Figure 10) 

Value in 

2035 

$16.80 $14.00 $11.20 $24.00 $20.00 $16.00 

As indicated, the forecast is for crystalline O&M costs to decline 30% between 2008 and 

2035, reaching levels in the range of $11.20/ kWDC to $$16.80/kWDC (costs decline as 

size increases). For thin-film, costs decline 29%, reaching levels in the range of 

$16.00/kWDC to $24.80/kWDC by 2035. 

0

5

10

15

20

25

30

35

2005 2010 2015 2020 2025 2030 2035 2040

Year

O&M (2008$ / kWDC / yr)

Crystalline, 5 kW

Crystalline, 25 kW

Crystalline, 250 kW

Thin-film, 5 kW

Thin-film, 25 kW

Thin-film, 250 kW

Figure 22. Recommended O&M Costs, Reference Case 
 

38 

6. Forecast of PV Characteristics – Advanced Case 

In this section, PV characteristics for an advanced scenario are described. The 

rationale for the advanced case is that additional R&D investments will drive a high 

degree of technology innovation and accelerated cost improvements. In an advanced 

scenario, both technical characteristics and cost would be expected to improve 

compared with the reference case. However, as an initial step, the advanced case 

discussion in this section is focused on accelerated reductions in capital costs. 

As a first step, a cost trend curve was developed for an advanced case. This cost trend 

is shown in Figure 23. 

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

2005 2010 2015 2020 2025 2030 2035

Year

Cost Trends (2008 = 1)

Forecast, Reference Case

Forecast, Advanced Case

Figure 23. Cost Trends for Reference Case and Advanced Case 

Using the advanced case cost trend, the expected costs for crystalline and thin film 

technologies were computed. The crystalline costs are shown in Table 19, and the thinfilm costs are shown in Table 20. As discussed in greater detail in Section 5.2.2, thinfilm costs appear to show a dis-economy of scale between 25 and 250 kW, which may 

be an artifact of a small sample size. 
 

39 

Table 19. Crystalline Costs, Reference and Advanced Cases 

Cost (2008$ / kWDC) 

5 kWDC 25 kWDC 250 kWDC

Year 

Ref Case Adv 

Case 

Change Ref Case Adv 

Case 

Change Ref Case Adv 

Case 

Change 

2010 $7,075 $7,075 0.0% $6,805 $6,805 0.0% $6,195 $6,195 0.0% 

2015 $5,275 $4,773 9.5% $5,053 $4,573 9.5% $4,587 $4,151 9.5% 

2020 $4,495 $3,820 15.0% $4,294 $3,649 15.0% $3,890 $3,306 15.0% 

2025 $4,233 $3,415 19.3% $4,038 $3,258 19.3% $3,656 $2,949 19.3% 

2030 $4,054 $3,095 23.6% $3,864 $2,951 23.6% $3,496 $2,669 23.6% 

2035 $4,000 $2,909 27.3% $3,812 $2,772 27.3% $3,448 $2,508 27.3% 

Table 20. Thin-film Costs, Reference and Advanced Cases 

Cost (2008$ / kWDC) 

5 kWDC 25 kWDC 250 kWDC

Year 

Ref Case Adv 

Case 

Change Ref Case Adv 

Case 

Change Ref Case Adv 

Case 

Change

2010 $7,330 $7,330 0.0% $5,530 $5,530 0.0% $5,770 $5,770 0.0% 

2015 $5,458 $4,939 9.5% $4,138 $3,745 9.5% $4,282 $3,875 9.5% 

2020 $4,647 $3,949 15.0% $3,535 $3,004 15.0% $3,637 $3,091 15.0% 

2025 $4,374 $3,529 19.3% $3,332 $2,688 19.3% $3,420 $2,759 19.3% 

2030 $4,188 $3,198 23.6% $3,193 $2,438 23.6% $3,272 $2,499 23.6% 

2035 $4,132 $3,005 27.3% $3,152 $2,292 27.3% $3,228 $2,348 27.3% 

In the advanced scenario, installed capital costs begin diverging from the reference 

case in 2011, and fall approximately 27% below reference case values by 2035. In the 

advanced scenario, costs for all components, including the inverter, are reduced at the 

same rate relative to the reference case. 

 
 

40 

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46 

Appendix A. Recommended Characteristics, Crystalline 

Reference Case 

5 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 15.0% 80% 0.58% 26 11 $7,075 $700 2015 17.5% 84% 0.53% 29 14 $5,275 $700 2020 19.2% 86% 0.48% 30 15 $4,495 $700 2025 19.7% 86% 0.43% 30 15 $4,233 $700 2030 20.0% 86% 0.38% 30 15 $4,054 $700 2035 20.0% 86% 0.33% 30 15 $4,000 $700 

25 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 15.0% 82% 0.58% 26 11 $6,805 $600 2015 17.5% 86% 0.53% 29 14 $5,053 $600 2020 19.2% 88% 0.48% 30 15 $4,294 $600 2025 19.7% 88% 0.43% 30 15 $4,038 $600 2030 20.0% 88% 0.38% 30 15 $3,864 $600 2035 20.0% 88% 0.33% 30 15 $3,812 $600 

250 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 15.0% 84% 0.58% 26 11 $6,195 $500 2015 17.5% 88% 0.53% 29 14 $4,587 $500 2020 19.2% 90% 0.48% 30 15 $3,890 $500 2025 19.7% 90% 0.43% 30 15 $3,656 $500 2030 20.0% 90% 0.38% 30 15 $3,496 $500 2035 20.0% 90% 0.33% 30 15 $3,448 $500 
47 

Appendix B. Recommended Characteristics, Thin-film 

Reference Case 

5 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 10.4% 79% 0.98% 26 11 $7,330 $700 2015 11.4% 83% 0.93% 29 14 $5,458 $700 2020 12.4% 85% 0.88% 30 15 $4,647 $700 2025 13.4% 86% 0.83% 30 15 $4,374 $700 2030 14.0% 86% 0.78% 30 15 $4,188 $700 2035 14.0% 86% 0.73% 30 15 $4,132 $700 

25 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 10.4% 81% 0.98% 26 11 $5,530 $600 2015 11.4% 85% 0.93% 29 14 $4,138 $600 2020 12.4% 87% 0.88% 30 15 $3,535 $600 2025 13.4% 88% 0.83% 30 15 $3,332 $600 2030 14.0% 88% 0.78% 30 15 $3,193 $600 2035 14.0% 88% 0.73% 30 15 $3,152 $600 

250 kWDC

Year Module 

Efficiency (%) 

System Efficiency 

Degradation System 

Life 

Inverter Life 

Installed Capital Costs (2008$/kWDC) 

Inverter Cost (2008$/kWDC)

O(2y

2010 10.4% 83% 0.98% 26 11 $5,770 $500 2015 11.4% 87% 0.93% 29 14 $4,282 $500 2020 12.4% 89% 0.88% 30 15 $3,637 $500 2025 13.4% 90% 0.83% 30 15 $3,420 $500 2030 14.0% 90% 0.78% 30 15 $3,272 $500 2035 14.0% 90% 0.73% 30 15 $3,228 $500 
 

48 

Appendix C. GDP Implicit Price Deflator Index 

(Year 2005 = 1) 

Year GDP Index 

1990 0.72201 

1991 0.74760 

1992 0.76533 

1993 0.78224 

1994 0.79872 

1995 0.81536 

1996 0.83088 

1997 0.84555 

1998 0.85511 

1999 0.86768 

2000 0.88647 

2001 0.90650 

2002 0.92118 

2003 0.94100 

2004 0.96770 

2005 1.00000 

2006 1.03257 

2007 1.06214 

2008 1.08483 

2009 1.09777 

2010 1.11100 

Source: 1990 through 2009 data from U.S. Department of Commerce, Bureau of Economic 

Analysis. The 2010 value is from EIA’s January 2010 Short-term Energy Outlook. 

The GDP Implicit Price Deflator index is used in this report to convert costs in constant 

dollars between different basis years. For example, to convert costs that are expressed 

in 2005 dollars to 2008 dollars, multiply the 2005 values by 1.08483 (1.08483 / 

1.00000). 
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