multicrystalline
46%
thin-film
7.9%
ribbon crystalline
3.7%
monocrystalline
43%
Source: Strategies Unlimited (2003). Note that Heterojunction with Intrinsic Thin layer (HIT) modules, produced by Sanyo, are composed of
a monocrystalline cell surrounded by thin amorphous-silicon layers. Total shipments for these modules are split evenly between thin-film
and monocrystalline categories. HIT modules offer the highest solar conversion efficiency available for any terrestrial PV technology
(19.5% cell efficiency).
Figure 1. Technology shares of 450 MWp global PV market in 2002 (Dunay, 2003)
1
$100.0
1976
PR=0.80
2
Price (2002$/Wp)
R = 0.99
$10.0
2002
$1.0
$0.1
0
1
10
100
1,000
10,000
cumulative PV production (GWp)
Source: Johnson (2002) and Dunay (2003)
Figure 2. PV experience curve
This figure shows the historical experience curve for crystalline and thin-film power modules (excluding small
consumer cells and modules for space applications) based on average global wholesale prices (Johnson, 2002). The
experience curve indicates a tight fit and a 20 percent decline in price with every doubling of cumulative production
(PR = 0.80). The 95 percent confidence interval ranges from PR = 0.79 to PR = 0.81 and the spread around the
curve for PR = 0.80 is so tight that it is almost visually imperceptible, and therefore not depicted.
2
350
grid-connected
300
off-grid + consumer
MWp
250
200
150
100
50
00
01
20
99
20
97
98
19
19
96
19
95
19
19
94
93
19
91
92
19
19
89
90
19
19
88
19
86
87
19
19
85
19
83
84
19
19
82
19
81
19
19
19
80
0
Source: Demeo et al. , 1999; Johnson, 2002
Figure 3. Global PV markets
Terrestrial PV markets grew at a compound average growth rate of 24 percent from 1980-2001. Off-grid markets
dominated through the mid-1990s except for the early 1980s when subsidized central-station grid projects gained
prominence. Since 1990 off-grid sales have grown substantially but buydown programs have fueled a torrid 45
percent annual growth in grid-connected markets. Small cells used in consumer products held a significant market
share in the mid-1980s, but this sector is now trivial and declining.
3
value of modules ($/Wp)
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
0
0.5
1
1.5
2
2.5
3
GWp per year
Figure 4. Financial breakeven for a-Si PV in new US housing
A detailed bottom-up financial breakeven analysis (Duke, Williams, and Payne, submitted) shows the annual
potential demand for PV modules installed in new single-family homes in the US after 2005, assuming that 50
percent of new homes (housing data are from www.census.gov/const.) offer acceptable shading and orientation. A
point on this curve indicates the PV quantity demanded in new single-family homes for a given PV module price.
This financial breakeven curve was constructed based on a detailed lifecycle analysis that assumes net metering and
accounts for variation in county-level insolation and state-level electricity prices. Homeowners finance their systems
through tax-advantaged home mortgages and incremental homeowner insurance costs are assumed to be trivial.
Finally, it is assumed that states and localities exempt the value of PV systems from property tax assessments to
level the playing field with less capital-intensive conventional electricity technologies. All other existing or planned
tax incentives are excluded—including any mechanisms to reward PV for its environmental advantages relative to
conventional electricity supplies.
4
100
Price (USD(2000)/Wp)
Nitsch 1976-84
PR=.84
Nitsch 1984-87
PR=.53
10
Nitsch 1976-96
PR=.80
Nitsch 1987-96
PR=.79
Harmon (PR=.80)
Strategies Unlimited (PR=.80)
1
0.1
1
10
100
1000
10000
Cumulative Sales (MW)
Figure 5. Spurious microstructure in PV experience curves
Comparing two PV experience curves (Johnson, 2002; Harmon, 2000) with the curve from Nitsch (1998) suggests
that the apparent knee in the latter may be spurious. Nitsch (1998) uses European price data for crystalline modules,
raising the possibility of an exchange rate anomaly or a shift in the price survey methods during 1984-1987 (e.g.
towards a sample definition that is more heavily weighted towards wholesale prices rather than retail). In any case,
the long-term experience curve for the Nitsch data has the same progress ratio (PR = 0.80) as the other two curves.
.
5
PV module break-even value ($/Wp)
$30.00
$25.00
$20.00
$15.00
X=7.5P-2.5
R2 = 0.99
$10.00
$5.00
$0.00
0
1
2
3
4
5
6
7
8
9
10
GWp per year
Figure 6. PV demand elasticity estimation
The square data points plot historical PV prices versus unsubsidized off-grid sales levels from 1980-2000
(Johnson, 2002). The triangles represent 20 points taken from Figure 4 (with the quantities multiplied by a factor of
4 to account for retrofit and international markets) at evenly spaced quantity intervals. The best-fit isoelastic
demand schedule consistent with these data has an elasticity of 2.5; however, some of this historical demand growth
reflects diffusion effects rather than price effects, so the base case analysis assumes an elasticity of 2.
6
$5.00
break-even value of modules ($/Wp)
$4.50
$4.00
$3.50
$3.00
$2.50
$2.00
X(50)=(25/(1+exp(-0.09*50+2))*P^-2
$1.50
X(10)=(25/(1+exp(-0.09*10+2))*P^-2
$1.00
$0.50
X(1)=(25/(1+exp(-0.09*2+2))*P^-2
$0.00
0
2
4
6
8
10
12
GWp per year
14
16
18
20
Figure 7. Logistic demand shift for the optimal path method
This figure compares the logistically shifting all-market PV demand schedule used in the optimal path method
analysis with the annual OECD residential PV demand schedule (i.e. the breakeven schedule for PV demand in new
U.S. homes from Figure 4 increased by roughly a factor of 4 to account for retrofits as well as markets in Europe
and Japan). In the first year of the analysis (i.e. 2003) annual demand falls short of the breakeven schedule, but the
two schedules overlap by year 10 after markets have matured (i.e. after a doubling of the coefficient on the isoelastic
demand). After 50 years, demand shifts out by another factor of four due to growth in commercial buildings and
developing country markets. At the price floor of $0.50/Wp, this yields a mature sales rate of 100 GWp/y.
Even in the first year, the all-market demand schedule exceeds the OECD residential PV schedule for sales levels
below 1 GWp/y because it includes off-grid PV markets for which the willingness to pay is much greater than for
distributed grid-connected PV (although the potential non-grid market is small). Similarly, the all-market demand
schedule extends beyond 10 GWp/y (at which point the OECD residential PV demand schedule tapers off) because
other markets open up at these low prices—including commercial buildings and a full range of grid-connected
applications in developing countries.
7
$ billions per year (r=0.05)
$4
$3
$2
$1
$0
0
10
20
30
40
50
60
70
80
90
100
70
80
90
100
70
80
buydown year
minimum subsidies + transfer subsidies
minimum subsidies
GWp per year
100
90
80
70
60
50
40
30
20
10
0
0
10
20
30
40
50
60
buydown year
buydow n
NSS
50
60
$5
$/Wp
$4
$3
$2
$1
$0
0
10
20
30
40
90
100
buydown year
buydown price
buydown net price
NSS price
Figure 8. Optimal path method base case scenario (MEB = 0)
The top panel shows the expenditure rate ($ billions/year) for an optimal global PV buydown considering both
minimum possible subsidies and minimum possible subsidies plus transfer subsidies (both are illustrated in Figure
9). The middle panel shows the output path under the optimal buydown and the slower sales growth under the no
subsidy scenario (NSS). The bottom panel shows the baseline NSS price trajectory, much faster price reductions
under the buydown, and the net price paid by buydown participants (i.e. current buydown price minus unit
subsidies).
8
Year One
$10
quantity demanded
w/o
year-one subsidy
$9
quantity
demanded w/
year-one subsidy
$8
$7
$/Wp
$6
$5
consumer
surplus
current price
$4
$3
free riders
$2
minimum possible subsidy
cost
failure to price
discriminate
TMC
$1
$0
0
0.2
0.4
0.6
0.8
1
1.2
1.4
GWp/y
Year 20
$2
quantity
demanded w/o
year-20 subsidy
quantity
demanded w/
year-20
subsidy
consumer
surplus
$/Wp
current price
$1
free riders
failure to price
discriminate
minimum possible subsidy
cost
TMC
$0
0
5
10
15
20
25
30
GWp/y
Figure 9. Base case (MEB = 0) snapshots for t = 1 and t = 20
The minimum possible subsidy in each period of the buydown equals the integral of current price minus the
willingness to pay schedule for all the buydown participants. There may be additional transfer subsidies: 1) if the
buydown program fails to price discriminate when distributing subsidies and, 2) if the buydown program cannot
exclude free riders. In later years, transfer subsidy costs may account for an increased proportion of total subsidies
because the potential base of free riders is higher.
9
300
Deployment
Demonstration
R&D
millions of 2000$
250
200
150
100
50
ly
Ita
UK
Ko
re
a
Sw
it z
er
la
nd
Au
st
ra
lia
Fr
an
ce
an
y
Ne
th
er
la
nd
s
G
er
m
Source: IEA (2000)
US
A
EU
Ja
pa
n
0
Figure 10. Current PV support allocations by leading IEA countries
The figure shows a break down of PV funding allocations by leading IEA countries for the year 2000. The totals
include federal, state, and local support programs and they highlight strong investment by Japan and rapidly growing
support by Germany, which spends nearly twice as much as the U.S. on a per capita basis.
10
600
Deployment
Demonstration
R&D
millions of constant 2000$
500
400
300
200
100
0
1994
1995
1996
1997
1998
1999
2000
Source: IEA (2000)
Figure 11. Trends in PV support among IEA countries
These figures reflect total funding at the federal, state, and local level by seventeen major industrialized countries
in the International Energy Agency. Funding for R&D and demonstration programs has been relatively stable (aside
from a dip in 1996), but buydown funding increased sharply over the seven-year period shown.
11
500
450
400
Other
German residential buydown
350
Japanese residential buydown
MWp
300
250
200
150
100
50
0
1993
1994
1995
1996
1997
1998
1999
2000
2001
Source: Berger (2001); Weiss and Sprau (2001); Hirschman and Takano (2003); Krampitz and Schmela (2003)
Figure 12. PV buydown sales trends in Germany and Japan
Germany and Japan have scaled up large buydown programs primarily targeting grid-connected residential
customers. By 2000, these combined programs accounted for more than half of global module sales and were
expected to drive global PV sales growth through at least 2003.
12
2002
.
$35
US$/Wp (120Yen/$)
$30
Installation
Balance of systems
Modules
$25
$20
$15
$10
$5
$0
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
Source: Kurokawa and Ikki (2001); NEF (2001); Hirshman and Takano (2003)
Figure 13. Japanese residential PV system price trends
Installed residential PV systems have dropped from over $30/Wp in 1993 when the Japanese buydown began to
under $7/Wp by 2001 (in constant 2000 dollars). System prices can be broken down into modules, balance of
systems (BOS) equipment, and installation costs. The associated progress ratios are roughly similar for all three (PR
= 0.80 for modules, PR = 0.78 for BOS, and PR = 0.84 for installations) but installation costs have fallen by a factor
of five (while module prices dropped by just over a factor of two) because the local experience base for installations
was initially minimal. BOS prices have fallen even faster (by a factor of 8) because the associated progress ratio is
better than for modules. Note that inverters are global commodities—but even for this internationally traded
component of BOS costs, manufacturers still had to tailor new models to the particular needs of the Japanese market
(e.g. eliminating battery backup charging capability).
13