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Contract No. DE-AC36-08GO28308

An Economic Analysis of 

Photovoltaics Versus 

Traditional Energy Sources: 

Where Are We Now and Where 

Might We Be in the Near Future?

Preprint

Michael Woodhouse, Ted James, 

Robert Margolis, David Feldman, Tony Merkel, 

and Alan Goodrich 

Presented at the 37th IEEE Photovoltaic Specialists Conference 

(PVSC 37)

Seattle, Washington

June 19-24, 2011

Conference Paper

NREL/CP-6A20-50714

July 2011
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1

AN ECONOMIC ANALYSIS OF PHOTOVOLTAICS VERSUS TRADITIONAL 

ENERGY SOURCES: WHERE ARE WE NOW AND WHERE 

MIGHT WE BE IN THE NEAR FUTURE?

Michael Woodhouse, Ted James, Robert Margolis, David Feldman, Tony Merkel, and Alan Goodrich

National Renewable Energy Laboratory, Golden, Colorado, USA

ABSTRACT

A precipitous drop in the price of the crystalline silicon 

solar photovoltaic (PV) modules typically employed for 

residential applications has recently been observed: The 

typical sales price for modules was around $4/WP DC in 

2008 but could easily approach $1.50/W WP DC by the end 

of this year1

. As module price declines continue, and as 

gains are also realized in balance-of-system costs, the 

economics of PV systems for power generation become 

increasingly competitive. In this presentation, we will 

examine whether solar will reach grid parity in the United 

States if monocrystalline silicon modules achieve an 

optimistic-case scenario in efficiency and cost. The 

analysis suggests that PV systems are already 

economically viable in select markets, but further cost 

reductions and efficiency improvements above and 

beyond the monocrystalline optimistic-case scenarios are 

necessary in order to be competitive against incumbent 

electricity production in most markets across the United 

States.

ANALYSIS

In close consultation with U.S.-based residential PV 

installation firms, NREL has constructed a detailed 

analysis of PV system prices2

. In this system, it is 

assumed that the available residential rooftop area (35 m2

) 

can accommodate 21 standard size (1.64 m2

) 

monocrystalline silicon PV modules. With 14.5% efficiency 

for each module—meant to represent the current typical 

industry average and not necessarily the “best in class”—

the modeled system size is 4.9 kWP DC. The results of the 

analysis for a typical monocrystalline silicon solar 

installation are shown below in Figure 1.

This analysis is based upon national average labor rates, 

and an understanding of the time required to install each 

component in the system’s bill-of-materials (BoM), to 

arrive at an estimate for the labor costs of the installation. 

Overhead costs (including permitting, grid connection, 

sales taxes, installer operating overhead and profit margin, 

etc.) are based upon values most often reported by 

collaborating installers.

Figure 1 Estimated costs for residential PV systems installed in the United States: current (left) and a modeled 

system with lower-cost and higher-efficiency modules (right) as described in the text. Source: Goodrich et al2.
2

We estimate the optimistic-case future price for 

monocrystalline-silicon modules to be $0.68/WP DC. This 

estimate is based upon a wafer thickness of 80 μm 

(kerfless) with $32/kg polysilicon3

; the cell processing 

costs are based upon interdigitated back contact (IBC) 

architecture, standard module materials (glass front, EVA, 

standard wafer interconnections, etc.), and a module 

efficiency of 21.5%. Using this module without any 

changes to the installation BoM costs or methods—quite 

arguably a conservative assumption—the resulting system 

costs may be reduced from around $5.70/ WP DC to around 

$3.50/WP DC.

These system costs can be used to estimate the levelized 

cost of electricity (LCOE) for the system4

:

For a residential rooftop system, there are typically only 

two scheduled operating and maintenance (O&M) events. 

The first is an end-of-year-one check of the system by the 

installer, which takes about two hours. The second event 

consists of a standard 10-year inverter replacement that 

requires around four hours of labor. The depreciation 

benefit can only be realized for leased systems; however,

the leased system LCOE is not expected to be 

significantly different from that of system financed by the 

homeowner using a standard mortgage loan because the 

investor-backed discount rate is generally significantly 

higher for the leased systems (approximately 12% vs 7%)

and because leased solar projects must also pay taxes on 

the electricity that is generated and sold.

If PV systems were able to produce electricity at the same 

price as that produced by predominately fossil fuel based 

sources, their deployment would be expected to increase. 

This price goal can be significantly different across the 

globe; furthermore, due to differing solar irradiation profiles 

and intensities, different deployment sites for a PV system 

are expected to return very different expectations of 

LCOE, even if the system price were the same. Figure 2 

Figure 2: Levelized Cost of Electricity (LCOE) estimates from NREL’s Solar Advisory Model for residential PV 

systems deployed at three locations in the US. These estimates are based upon the same system price ($/Wp DC) 

in each location. The tallest bars in blue represent 2011 costs: the estimated LCOE with the current federal 

investment tax credit (ITC) of 30% is shown in white, while the fully unsubsidized cost estimates are indicated in 

black. The green bars represent the corresponding future case after system costs are reduced along the 

technology pathway described in the text; the LCOE at a 10% ITC subsidy level is shown for the future case as

the sunset date for the 30% benefit is 2016 (after which systems are still set to receive a 10% ITC under current 

federal tax law). For comparison to convential electricity prices, the EIA’s estimates for January 2011 average 

residential electricity rates within the respective states are indicated by the solid horizontal bars.5

LCOE ($/ kWh) = Total Life Cycle Cost ($/ Wp )

Total Lifetime Energy Production (kWh/ Wp )

=

Initial Investment + Annual O & M Costsn

(1+ Discount Rate)

n

n=1

N

∑ − Depreciation n

(1+ Discount Rate)

n x(Tax Rate)

n=1

N

∑

Rated kWh/ Wp x Capacity Factor

(1+ Discount Rate)

n x(1 - System Degradation Rate)n

n=1

N

∑
3 

shows our estimates of LCOE, with and without the federal 

investment tax credit (ITC), for the 2011 and the future 

silicon module (price, efficiency) cases and compares 

them to residential electricity rates within the respective 

states. The 30% ITC used in 2011 differs from the 10% 

ITC used in the future case because the ITC will revert to 

the lower level in 2016. While deployment in certain 

“transitional” markets-- such as California-- already 

appears to be at price parity with statewide average 

electricity rates, and compares even more favorably when 

looking at the tiered pricing structures used throughout 

that state, most of the power generated in the United 

States is currently available at a lower cost than can be 

expected from the PV technology system described here. 

Because the majority of residential systems are based 

upon this technology, it is clear that advances in system 

costs (particularly in the non-module categories) are 

needed in order for PV to become competitive at an 

unsubsidized level across the United States.

REFERENCES

[1] Goldstein, A.; Feldman, D. Q4 2010 Solar Industry 

Update; Department of Energy, Solar Energy 

Technologies Program: Washington, DC, 2011.

[2] Goodrich, A.; James, T.; Woodhouse, M. Installed

Solar PV System Prices; NREL: Golden, CO, 2011; 

http://www.nrel.gov/docs/fy11osti/50955.pdf

[3] Goodrich, A.; Hsu, D.; Woodhouse, M., 2011, In 

Preparation.

[4] Campbell, M. ; Blunden, J.; Smeloff, E.; Wright, S.; The 

Drivers of the Levelized Cost of Electricity for Utility-Scale 

hotovoltaics; SunPower Corporation: 2008.

[5]http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_a

.html