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

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

Contract No. DE-AC36-08GO28308

Photovoltaic Degradation 

Rates — An Analytical Review 

Dirk C. Jordan and Sarah R. Kurtz

To be published in Progress in Photovoltaics: Research 

and Applications

Journal Article

NREL/JA-5200-51664

June 2012
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Abstract 

As photovoltaic penetration of the power grid increases, accurate predictions of return on 

investment require accurate prediction of decreased power output over time. Degradation rates 

must be known in order to predict power delivery. This article reviews degradation rates of flatplate terrestrial modules and systems reported in published literature from field testing 

throughout the last 40 years. Nearly 2000 degradation rates, measured on individual modules or 

entire systems, have been assembled from the literature, showing a median value of 0.5%/year. 

The review consists of three parts: a brief historical outline, an analytical summary of 

degradation rates, and a detailed bibliography partitioned by technology. 

Keywords: Photovoltaic modules, photovoltaic systems, performance, outdoor testing, field 

testing, degradation rates 

1. Introduction

The ability to accurately predict power delivery over the course of time is of vital importance to 

the growth of the photovoltaic (PV) industry. Two key cost drivers are the efficiency with which 

sunlight is converted into power and how this relationship changes over time. An accurate 

quantification of power decline over time, also known as degradation rate, is essential to all 

stakeholders—utility companies, integrators, investors, and researchers alike. Financially, 

degradation of a PV module or system is equally important, because a higher degradation rate 

translates directly into less power produced and, therefore, reduces future cash flows [1]. 

Furthermore, inaccuracies in determined degradation rates lead directly to increased financial 

risk [2]. Technically, degradation mechanisms are important to understand because they may 

eventually lead to failure [3]. Typically, a 20% decline is considered a failure, but there is no 

consensus on the definition of failure, because a high-efficiency module degraded by 50% may 

still have a higher efficiency than a non-degraded module from a less efficient technology. The 

identification of the underlying degradation mechanism through experiments and modeling can 

lead directly to lifetime improvements. Outdoor field testing has played a vital role in 

quantifying long-term behavior and lifetime for at least two reasons: it is the typical operating 

environment for PV systems, and it is the only way to correlate indoor accelerated testing to 

outdoor results to forecast field performance. 

Although every reference included in this paper contains a brief to slightly extensive summary of 

degradation rate literature, a comprehensive review could not be found. This article aims to 

provide such a summary by reviewing degradation rates reported globally from field testing 

throughout the last 40 years. After a brief historical outline, it presents a synopsis of reported 

degradation rates to identify statistically significant trends. Although this review is intended to be 

comprehensive, it is possible that a small percentage of the literature may not have been 

included. 

1
2. Historical Overview 

Figure 1 shows a map with degradation rates reported in publications discussed in this article. 

The size of each circle is indicative of the number of degradation rates reported at a given 

location. The four major regions prior to the year 2000 wherein long-term field observations 

have taken place are the USA, Europe, Japan, and Australia. These four regions are discussed 

within their historical context, as understanding the PV history for terrestrial applications 

elucidates time and place of degradation rate field observations. After 2000, a large number of 

observations have been reported with equal diversity in technology and geography. 

2.1. USA

The modern era of PV technology could be claimed to have started in the 1950s at Bell 

Telephone Laboratories [4, 5]. When the Space Age officially started with the launch of the 

Russian Sputnik satellite in 1957, PV technology and satellites were ideally suited for each other. 

The first satellites such as Vanguard I required only moderate power, and the weight of the solar 

panels was low. Reliability was ensured by protecting the cells with a quartz or sapphire cover 

sheet from energetic particles outside the atmosphere and by using n-on-p type cells [6]. The oil 

crisis of 1973 changed the focus of PV from space to terrestrial applications, particularly 

applications in remote locations. Major oil companies were among the first to provide PV a 

terrestrial market in the form of supervisory controls, cathodic well corrosion protection, buoys, 

oil platform lights, and horns [7] that were much more economical than traditional batterypowered solutions for remote locations on land and water [8]. However, with an environment 

drastically different from space applications, the long-term reliability of PV modules faced vastly 

different challenges. These were addressed starting in 1975 through the Flat-Plate Solar Array 

project under the auspices of the Energy Research and Development Administration, which in 

1977 was integrated into the U.S. Department of Energy [9-11]. Because of its PV experience in 

space, the National Aeronautics and Space Administration was involved through two 

laboratories, the Jet Propulsion Laboratory (JPL) in California and the Lewis Research Center in 

Ohio. JPL conducted a block buy program, procuring state-of-the-art modules and testing 

(a) 

Figure 1. Geographical distribution of degradation rates reported in publications, (a) 

worldwide and (b) a large part of Europe. The size of the circle is indicative of the 

number of data points from a given location.

(b) 

2
them [12]. Based on field experience and failure analysis of degraded modules, each of the five 

block buys placed more and more stringent accelerated stress tests on the modules, providing 

valuable information toward later standards such as module qualification standard IEC 

61215 [13, 14]. Field tests were conducted via installation at various sites including the Lewis 

Research Center and the Lincoln Laboratory at MIT, constituting the first systematic outdoor 

testing [15]. While Block I modules did not experience high failure rates in the field, they 

exhibited high degradation rates and provided insights into the various types of outdoor 

degradation mechanisms [16-18]. Roesler et al. also reported high degradation rates for preBlock V modules in a 60-kW plant at the Mt. Laguna Air Force Station; these were probably 

caused by hot spot problems (Wohlgemuth, private communication) [19].

From 1983 to 1985, the Atlantic Richfield Oil company constructed the first large PV site at 

what is known today as the Carrizo Plain National Monument in central California. The 

produced electricity was sold to the Pacific Gas and Electric Company, which also supervised 

the data monitoring. The Carissa Plains project, as it was known at the time, used mirror 

enhancement resulting in high module temperature and ultraviolet exposure. The rapid power 

decline and maintenance experience at this site were initially attributed to the significant 

encapsulant browning [20-22]. Wohlgemuth and Petersen later demonstrated that much of the 

power loss in these modules was due to bad solder bonds, not ethylene vinyl acetate (EVA) 

browning [23]. In 1986, the Photovoltaics for Utility Scale Application (PVUSA) was initiated, a 

cost-sharing collaboration between private companies and government [24]. The project was 

designed to bridge the gap between large utility companies unfamiliar with PV technology and 

the small PV industry unfamiliar with the requirements of large utility companies [25]. The main 

PVUSA sites were Davis, CA, USA, and Maui, HI, USA [26]. In addition to valuable hands-on 

experience and detailed knowledge about maintenance costs, PVUSA also provided a new rating 

methodology that is still used today [27, 28]. The long-term performance of the main sites can be 

found in the PVUSA progress reports [29, 30]. The PVUSA project required qualification to tests 

developed at the National Renewable Energy Laboratory (NREL), Sandia National Laboratories, 

and JPL[30]. In an extensive field survey of systems consisting of pre- and Block V modules, 

Rosenthal et al. found that the failure rates decreased significantly from 45% for pre-Block V to 

less than 0·1% for Block V modules [31]. In addition, degradation rates for 10 selected systems 

were found to be larger than 1%/year. Atmaram et al. reported on Block IV and V 

monocrystalline Si systems deployed in Florida and found degradation rates well below 

1%/year [32].

In 1977, the Department of Energy established the Solar Energy Research Institute in Golden, 

Colorado. In 1991, it was renamed as the NREL. Outdoor testing of modules and submodules 

started at the Solar Energy Research Institute in 1982. When amorphous silicon (a-Si) modules 

first became commercially available, NREL began to report degradation rates that were 

substantially higher than 1%/year for single and tandem junction modules although the 

continuous testing time rarely exceeded 1 year, implying that some of this was the initial lightinduced degradation [33, 34]. Pratt and Burdick reported on the multiyear progress of a 4-kW aSi array commissioned in Michigan in 1987. Although the degradation rate was found to be 

much lower, it still exceeded 1%/year in the first year of operation and then was stable between 

years 2 and 3 [35-37]. Kroposki and Hansen showed similar results (initial light-induced 

3
degradation, followed by a small, ≤1%/year degradation) for four separate single and tandem 

junction 1–2-kW a-Si systems deployed at NREL [38].

2.2. Europe

Akin to almost every country, the terrestrial focus of PV in Europe can be traced to the oil crisis 

of the 1970s. The development and institution of PV sites can be divided into publicly and 

privately funded projects. The publicly funded part in Europe can be additionally divided into the 

umbrella organization of the Commission of the European Communities and individual national 

programs. The Commission of the European Communities actively pursued PV installations 

among its member states beginning in 1975 [39]. The Directorate General (DG XII) initiated a 

PV pilot program with 16 systems installed across Europe from 1982 to 1984 with a total 

capacity of 1 MWp. The Directorate General “Energy” (DG XVII) initiated a demonstration 

program to bridge the gap between research and development and commercialization [40]. A 

minority of these installations were grid-connected applications, with the majority of them being 

for remote applications including housing, lighthouses, warning systems, water pumping, and 

telecommunications. Whereas the PVUSA project in the USA utilized a regression method to 

document the power performance under a set of reference conditions, the European analysis 

more frequently documented the energy output (performance ratio or array yield) as an indicator 

of the ongoing performance of the PV systems [42]. The Joint Research Centre (JRC) in Ispra, 

Italy was founded in 1959 as a research center focusing on nuclear energy. In 1974, part of the 

center, the European Solar Test Installation, was dedicated to solar research [41]. Until 1983, 

JRC was largely concerned with test installations, testing of modules, and developing standard 

test procedures. The focus then shifted to also include data monitoring of pilot and demonstration 

plants [42]. Since 1985, JRC has coordinated a European Working Group on PV plant 

monitoring criteria, plant performance, quality control, analysis, and lessons learned. In the 

monitoring guidelines published by JRC in 1987, the monitoring length is specified to be 2 years 

[43]. Therefore, the literature that immediately followed contained data for at least 2 years. Kaut 

et al. reported on experiences and performance declines for several of these demonstration 

program plants in 1989 [44]. Nentwich et al. showed excellent stability for a plant at a highaltitude location in Austria [45]. The study was updated and expanded to include other highlatitude locations as the Alpsolar project [46]. Häberlin and Beutler also reported good stability 

for a crystalline Si array at a high-altitude location at the Jungfrau in the Swiss Alps [47]. The 

array was installed as a facade and does not experience any snow load. The study was later 

updated, and the system continued to exhibit excellent stability [48]. Berman et al. investigated 

nearly 200 multicrystalline silicon (multi-Si) modules installed in the Negev desert of Israel in 

1995 [49]. The mirror-enhanced modules experienced degradation rates of less than 1%/year 

after 5 years. Further interesting studies before 2000 included reports from Italy [50], Finland 

[51], Switzerland [52], and Spain [53]. 

2.3. Japan

In Japan, the first outdoor installations were carried out by Sharp for lighthouses, the first one 

being on the island of Ogami in the Nagasaki prefecture in 1966. By the 1970s, over 200 

lighthouses were equipped with PV [8]. Further PV development started with the implementation 

of the “Sunshine Program” by the Japanese government in 1974. Beginning in 1982, the Japan 

Quality Assurance Organization, sponsored by the New Energy and Industrial Technology 

Development Organization, conducted outdoor testing at five sites in Japan and four sites abroad. 

4
As part of the “Sunshine Program,” Takigawa et al. found fairly large degradation rates for early 

a-Si prototype modules compared with more advanced models during the 3 years of outdoor 

exposure [54]. After the start of the “New Sunshine” program in 1992, an extensive field testing 

section was integrated into the program. Fukae et al. reported on the performance of triple 

junction a-Si modules and crystalline Si control modules at three different locations in Japan and 

Malaysia [55]. Although the observation time was only around 1 year, Fukae et al. showed that 

the a-Si modules performed better at higher temperatures. In 1997, Akhmad et al. reported a 

much larger degradation rate for a-Si than multi-Si, similarly showing that the performance of 

the a-Si increased during the summer, whereas that of the multi-Si decreased [56]. Ikisawa et al. 

from Japan Quality Assurance Organization reported on a-Si modules at three different sites in 

two different climate zones and found degradation substantially below 1%/year [57]. Machida 

and Yamazaki reported on six module samples taken from a 50-kW array near Tokyo. Outdoor 

exposure was for more than 5 years, with monocrystalline silicon (mono-Si) showing larger 

power decline than multi-Si [58].

2.4. Australia

Australia, with its large geographic size relative to population size, was in need of 

telecommunications from remote locations. PV provided an inexpensive alternative to generators 

and high-maintenance batteries. Therefore, telecommunication companies were the first to install 

PV modules and arrays and also the first to survey the long-term field performance and outcome 

in different climates. Muirhead and Hawkins reported first on the large Telstra PV network 

experience in 1995, including 35 mono-Si modules deployed for 8 years in the Melbourne 

climate, showing an average decline of 0·4%/annum with a normal distribution [59]. One year 

later, the same authors expanded their findings in terms of technologies and sites. Higher 

degradation rates were found for thin-film modules compared with crystalline Si modules [60]. 

2.5. Global Organization

The International Energy Agency established the Photovoltaic Power Systems program in 1993 

to enhance international collaboration. Task 2 of this program was dedicated to the performance, 

reliability, and trend analysis of PV systems. This effort has been continued in Task 13. 

Degradation information can be found in the technical reports and on the web page of the 

International Energy Agency (http://www.iea-pvps.org/) [61]. 

3. Analysis & Discussion

3.1. Synopsis of Degradation Rates

Figure 2 shows a summary histogram of degradation rates reported in this review. The 

summarized rates are long-term degradation rates and do not include short-term, light-induced 

degradation. A decrease in performance is defined as a positive degradation rate. Conversely, a 

negative rate indicates an improvement. Although this histogram needs to be updated frequently 

as new information becomes available, some general insights can be drawn from it. The 

distribution is skewed toward high degradation rates with a mean of 0.8%/year and a median of 

0.5%/year. The majority of these reported rates, 78% of all data, are below a rate of 1%/year 

indicated by a red dashed line. In addition, this histogram is remarkably similar to (though 

slightly narrower than) the assumed degradation rate distribution Darling et al. used for their 

calculations for the levelized cost of energy for PV [62]. In addition, Figures 2(b) and 2(c) show 

5
a similar histogram for crystalline Si-based and thin-film-based technologies, respectively. Color 

coding is provided to distinguish data from installations prior to the year 2000 and after 2000 

indicated by pre-2000 and post-2000. 

0

50

100

150

200

250

300

Frequency

Degradation Rate (%/year)

Median: 0.5 %/year

Average: 0.8 %/year

# reported rates = 1920

Figure 2. Histogram of reported degradation rates for all degradation rates 

(a), for Si only (b), and for thin-film technologies only (c). Median, average 

and number of reported rates are indicated. In addition, Si and thin-film are 

color-coded by date of installation into pre-2000 and post-2000.

 

(a)

(c)

(b)

0

50

100

150

200

250

300

Frequency

Degradation Rate (%/year)

Pre-2000

Post-2000

Median: 0.5 %/year

Average: 0.7 %/year

# reported rates = 1751

0

2

4

6

8

10

12

14

Frequency

Degradation Rate (%/year)

Pre-2000

Post-2000

Median: 1.0 %/year

Average: 1.5 %/year

# reported rates = 169

6
7 

This compilation of degradation rates is a survey of literature results and not a scientific 

sampling. Modules with high degradation rates are unlikely to be left in the field and reported on 

as many times as modules with low degradation rates. This effect can be seen in Figure 3, which 

shows the degradation rates from Figure 2 partitioned by the field exposure length. For studies 

with monitoring times up to 10 years, it can be seen that the distribution has a much more 

pronounced tail and a higher median than for field exposure times of more than 10 years. 

Although an effort was made to eliminate the impact of short-term light-induced degradation, 

especially for thin-film technologies included in this review, its influence cannot be completely 

excluded. In addition, many of the scientific studies include engineering prototypes that would 

not become commercial products based on the high degradation rates that can be observed in 

<2 years of deployment. It would be very interesting to create a similar plot only for crystalline 

Si and thin-film technologies; however, more data points are required, especially for thin films, 

to make the graph meaningful. 

As module durability increased during the last three decades, module warranties increased 

accordingly. Figure 4 shows the outdoor exposure length versus the publication year. A typical 

module manufacturer warranty [63], shown for comparison, exceeds the field-testing length for 

most of the last 25 years. Only in the last 5 years have there been studies that meet or exceed a 

typical module warranty. 

0

50

100

150

Frequency

Degradation Rate (%/year)

>20 years

10-20 years

0-10 years

Figure 3. Degradation rate histogram grouped by outdoor exposure length. 

The median rate for exposure length up to 10 years is significantly higher than 

for studies of 10 years and longer. 
Further insight can be gained when the individual degradation rates are partitioned by technology 

and by date of installation, as shown in Figure 5. The denotations “pre” and “post” refer to a date

of installation prior to and after the year 2000, respectively. The choice of the year 2000 is 

somewhat arbitrary and was mostly driven by the decision to have an approximately equal 

number of data points for each category. The crossbars of the diamonds indicate the mean of 

each category, and the extent of the diamonds indicates the 95% confidence interval. Figure 5(a) 

shows the results for all data collected, whereas module-only data and system-only data are 

given in Figure 5(b) and 5(c), respectively. The crystalline Si technologies show similar low 

degradation rates for pre-2000 and post-2000 categories for all data and module-only data. 

However, a one-way analysis of variance reveals a significant decrease in degradation rates from 

the pre-2000 to post-2000 installations for thin-film technologies. Similarly to the module trends, 

the systems also show a significant pre-2000 to post-2000 decrease in degradation for all 

technologies. In addition, a multiway analysis of variance reveals a significant difference 

between modules and systems for the same time frame only in two categories: the mono-Si and 

cadmium telluride (CdTe) technology before 2000. Each case demonstrates the confounding 

effects when comparing module to system degradation. For the mono-Si category (pre-2000), the 

system degradation is significantly higher than the module degradation. In general, systems 

degradation will also include balance-of-system effects, which can be most clearly seen for 

mono-Si (the category with the greatest amount of data). 

Figure 4. Outdoor field exposure in years versus date of publication. 

Module warranty from one manufacturer is shown as comparison.

0

5

10

15

20

25

30

35

1985 1990 1995 2000 2005 2010

Outdoor Exposure Length 

(years)

Publication Date

Degradation Rate Publication

Typical Module Warranty

8
Figure 5. Degradation rates partitioned by technology for (a) all data, (b) only 

modules, and (c) only systems. Dates of installation prior to the year 2000 and after 

2000 are indicated by “pre” and “post,” respectively. The crossbars denote the 

mean for each category, and the diamond, the 95% confidence interval. a-Si, 

amorphous silicon; CdTe, cadmium telluride; CIGS, copper indium gallium selenide; 

mono-Si, monocrystalline silicon; multi-Si, multicrystalline silicon.

(a)

(b)

(c)

Pre Post Pre Post Pre Post Pre Post Pre Post

Pre Post Pre Post Pre Post Pre Post Pre Post

Pre Post Pre Post Pre Post Pre Post Pre Post

(a)

(b)

(c)

9
In addition, it seems likely that a module investigation would also include a cleaning of the 

modules, whereas a systems investigation most likely would also include soiling effects. On the 

other hand, in the CdTe category (pre-2000), the systems degradation rate is much lower than the 

module degradation. The likely confounding effect revealed here is that module investigations 

often focus on prototypes, whereas system investigations are more likely comprised of 

commercial products. The modules were prototype modules from the early to mid-1990s, while 

the system category consisted of commercially available modules from the late 1990s. This 

effect may be revealed here because of the small sample size. Table 1 also shows that the outdoor 

exposure time for pre-2000 modules and systems is considerably longer than for newer 

investigation, therefore increasing the accuracy for the pre-2000 categories. Another observation 

that can be made from Table 1 is that before 2000, crystalline Si technologies dominated the 

literature, whereas after 2000, thin-film technologies have become increasingly common. 

Degradation rates have been determined from both continuous and discrete data sets. In the 

continuous data category are the PVUSA or the performance ratio (PR)[64] methodologies. Both 

methodologies display strong seasonality that can affect reported rates and uncertainties. I–

V curves are typically taken at discrete time intervals either indoors on a solar simulator or 

outdoors. Figure 6 shows a pie chart of the methodologies used to determine degradation rates 

pre-2000 and post-2000. The greatest change is that before 2000, indoor measurements were not 

very frequently used to determine degradation rates. However, after 2000, that percentage has 

grown almost to the levels of outdoor I–V and performance ratio methods. This trend is readily 

explainable by the more widespread availability of solar simulators. Figure 7 indicates the 

number of measurements that were taken to measure degradation rates. It is noteworthy that a 

high percentage of references take only one or two measurements to report degradation rates. 

This situation is often encountered when baseline measurements were never taken or no longer 

exist today. Thus, modern measurements need to be compared with the original manufacturer's 

standard test condition (STC) ratings.1 This approach can add significant error to the measured 

degradation rates [65, 66]. The accuracy of STC measurements has significantly improved 

during the last three decades. A 10% deviation was added to the 759 of the 1920 degradation 

rates based on original power and the analyses recreated to estimate the impact of more accurate 

STC measurements on the presented results. The effect is limited to the third significant digit for 

the median and average in Figures 2 and 3. 

An interesting approach to mitigate the problem of one measurement was presented by Becker et 

al. [67] Eight- to 12-year-old arrays were measured for the first time. The following year, 

another measurement was taken, bringing the total measurements to two and increasing the 

confidence level over the case where only one measurement was taken. However, such a strategy 

may not always be practical, especially for systems in remote locations.

Another opportunity for improvement in reporting degradation rates is to place more emphasis 

on comprehensive uncertainty analysis, as uncertainty is directly correlated to financial risk [2]. 

In addition, manufacturers often expose their products to tests in addition to the certification 

procedure. The lack of knowledge as to what accelerated testing modules have been exposed to, 

prior to outdoor deployment compounds, the difficulty in correlating indoor with outdoor testing. 

1 STC: irradiance = 1000W/m2, air mass = 1.5, module temperature = 25°C.

10
42%

18% 12%

28% Continuous

Discrete

2

1

44%

11% 4%

41%

Outdoor IV

Indoor IV

PVUSA

PR

31%

14% 24%

32%

Outdoor IV

Indoor IV

PVUSA

PR

(a)

(b)

N = 27

N = 101

Before 2000

After 2000

Figure 6. Pie chart of the number of references deploying the 

indicated methods to determine degradation rates, (a) prior to and 

(b) following the year 2000. PVUSA, Photovoltaics for Utility Scale 

Application; PR, performance ratio.

Figure 7. Percentage pie chart indicating the number of 

measurements taken to determine degradation rates.

11
Detailed Bibliography

Multiple Technologies

Degradation rate studies that compare multiple technologies are of particular interest because 

they exclude the effect of local conditions. Cereghetti et al. reported a relatively low average 

degradation rate of 0·3%/year for various technologies. However, the outdoor exposure time was 

less than 2 years [68]. Similar rates for crystalline technologies were found by Eikelboom and 

Jansen [69]. The exposure time was also relatively short: between 1 and 2 years, although high 

potential yields for thin-film modules in the Dutch climate are indicated. Osterwald et al. 

reported on a direct module-to-module comparison for various technologies in the same climate 

for 17 different modules [70]. Degradation rates were calculated from continuous data using the 

PVUSA method and compared with literature values. Most mono-Si exhibited degradation rates 

below 1%/year, while thin-film technologies showed rates above 1%/year. Raghuraman et al. 

investigated mono-Si, multi-Si, and a-Si module technologies from eight different 

manufacturers. Amorphous Si modules showed higher performance scatter [71]. Marion et al. 

not only compared degradation rate results for different technologies but also compared rates 

obtained using the PVUSA method with rates obtained from the performance ratio [72]. Both 

methodologies seemed to agree well for different technologies. Granata et al. investigated eight 

systems, and almost all degradation rates were within the experimental uncertainty [73]. Another 

important lesson learned was that proper commissioning is required to discover improperly 

installed systems early and prevent reliability issues. This may require sensitive monitoring at the 

string level. In 2008, Vázquez and Rey-Stolle presented results of reliability modeling based on 

literature degradation results and demonstrated that a degradation rate of less than 0·5%/year is 

required to satisfy long-term warranties [74]. Several crystalline and thin-film technologies were 

compared by Tetsuyuki et al. [75]. The multicrystalline silicon modules were found to exhibit 

systematically smaller degradation rates than the mono-Si modules and substantially lower rates 

than the a-Si modules. Copper indium gallium selenide (CIGS) modules were found to show a 

slight improvement over the measuring period of 3 years; the improvement was attributed to light 

soaking. Vaassen, in 2005, reported on the performance of six modules over 4 years, finding 

degradation rates slightly below 0·5%/year in the temperate climate of Germany [76]. Similarly, 

Becker and Bettinger presented results from 36 modules of various technologies with an overall 

degradation rate of approximately 0·5%/year in the same climate [77]. Makrides et al. examined 

the outdoor performance of several modules and technologies in Cyprus [78, 79]. A substantial 

difference in results was observed when comparing the PR and the PVUSA methodologies, 

possibly due to the combination of seasonality and relatively short monitoring time of 2 to 

3 years [80]. Jordan et al. compared more than 44 modules of various technologies side by 

side [81]. It was found that technology and date of installation were the most important factors 

determining degradation rates. Thus, modules were equally divided into modules installed prior 

to and after the year 2000. While the crystalline Si technologies appear to have stayed at 

degradation rates below 1%/year, thin-film technologies appear to have improved significantly, 

although some categories were limited by the small sample size.

Other degradation rate studies containing multiple technologies are more focused on 

methodology improvement rather than technology comparison. Jordan and Kurtz showed how 

analytical methods can be employed to reduce seasonal effects and therefore improve accuracy 

and the required length of monitoring time for multiple technologies [82]. Another important 

12
effect to consider for continuous data collection is the effect of data filtering on the 

determination of degradation rates. Kimber et al. showed that using only sunny days, provided 

the data size is not greatly reduced, may lead to reduced uncertainty in degradation rates [83]. 

Zhu et al. proposed a different filtering approach based on short-circuit current (Isc) as a measure 

of irradiance [84, 85]. 

After identification and elimination of outliers, module degradation rates are determined from 

the evolution of probability density functions instead of averages, thus providing more 

information on the degradation modes. Pulver et al. developed a methodology to determine 

degradation rates when no local irradiance measurement exists [86]. A number of systems at the 

same location can be used to calculate degradation rates with respect to an average of all 

systems. A statistical correction procedure could be used to deduce absolute degradation rates. 

Additional studies of interest comparing multiple technologies have been reported in 

Australia [87], France [88], Switzerland [89], South Korea [90], and USA [91]. 

Crystalline Silicon

Because crystalline Si technology is the oldest module technology, several outdoor studies 

exceeding 20 years in length can be found [90, 92, 101-105, 107-116, 125, 131, 136]. Quintana et 

al. documented the increased degradation rate for an entire system compared with module 

degradation for the Natural Bridges National Park PV system in Utah, USA. The module 

degradation rate for these Block II modules was a remarkable 0·5%/year; however, the system 

degradation rate was a much higher 2·5%/year, highlighting the above-mentioned balance-ofsystem and soiling effects in long-term field investigations [92]. Reis et al. investigated 192 

mono-Si modules in Arcata, CA, USA, over 11 years of exposure and found on average a low 

0·4%/year degradation rate. Most of these losses were losses in Isc [93]. Osterwald et al. made 

similar observations for a set of two monocrystalline and two multicrystalline modules. The 

rapid initial degradation was attributed to oxygen contamination in the bulk of the Si junction, 

whereas the slow long-term degradation correlated linearly with ultraviolet exposure. However, 

it appeared unlikely that the slow loss was due to EVA browning [94]. Morita et al. found the 

increase in series resistance as the cause for degradation [95]. Sakamoto and Oshiro confirmed 

similar findings through the inspection of more than 2000 modules, 150 of which were studied in 

more detail. The average degradation rate was less than 0·5%/year with dominant losses in fill 

factor (FF) and Isc [96]. Hishikawa et al. also reported Isc losses on 2400 investigated modules in 

Japan [97]. Kinget al. found a median degradation rate of 0·5%/year in a mono-Si system and 

traced the decline to the solder joints in the modules [98]. Similarly, Wohlgemuth et al., in an 

extensive survey of field returns of more than 4000 modules, found that more than 90% of field 

failures were caused by corrosion and interconnect breakage. High degradation rates in a system 

were usually due to individual module failures or other electrical components [99, 100]. 

Dunlop et al. initially investigated 40 modules installed at the European Solar Test Installation 

over the period of 1982–1984 [101, 102]. The analysis was then expanded by Skoczek et al. to a 

total of 204 modules installed between 1982 and 1986 [103-105]. No statistical difference was 

found between mono-Si and multi-Si technologies; however, modules left in open-circuit 

conditions exhibited lower degradation rates than modules connected to an inverter. The 

observation is attributed to the thermomechanical fatigue of the interconnects. Furthermore, 

modules incorporating silicone encapsulant showed lower degradation than EVA and polyvinyl 

butyral encapsulants. Glass–glass modules exhibited larger degradation rates than glass–polymer 

13
modules. High degradation rates were attributed to high losses in FF, i.e., significant increases in 

series resistance, while moderate degradation rates were due to optical losses in Isc. In addition, 

visual appearance is not indicative of electrical behavior. Sanchez-Friera et al. found a fairly 

large degradation rate of almost 1%/year over 12 years in Spain, with most of the losses in Isc. 

One of the potential loss mechanisms is ascribed to the antireflective coating, in addition to front 

delamination and inherent junction degradation [106]. Another important question is whether 

long-term degradation rates are inherently linear or nonlinear. De Lia et al. reported on the 

efficiency degradation of an array in Italy after 22 years of field exposure. The degradation 

appeared to be linear; however, in a retest of the same array after 30 years, it was found that the 

failure rates appeared to increase nonlinearly. A similar statement about the degradation rate 

cannot necessarily be made because of the low number of data points [107-110]. Realini et al. 

reported on a 10-kW system in Southern Switzerland that showed only a small 0·2%/year system 

degradation after approximately 20 years [111, 112]. Later, Sample provided measurements on 

the individual modules for the same system [105]. Different climate conditions may have an 

important influence on degradation rate. Therefore, degradation rate studies from diverse 

geographical locations are of great interest. Hedström and Palmblad presented data on 20 

modules exposed for more than 25 years at a northern latitude in Sweden. The average 

degradation rate was a remarkably low 0·17%/year [113]. Bing also observed good stability for 

two separate systems in the similar continental climate of Massachusetts, USA, after more than 

20 years [114]. In contrast, Saleh et al. found a degradation rate of approximately 1%/year for a 

stand-alone system in the desert climate of Libya after 30 years [115]. Tang et al. found a similar 

degradation rate for a system of approximately the same age located in the similar climate of 

Phoenix, AZ, USA [116]. Bogdanski et al. reported on a systematic study of crystalline modules 

in four different climates: the moderate temperate climate of Germany, the alpine climate of the 

German Alps, the hot and humid climate of Indonesia, and the hot and dry climate of 

Israel [117]. Evidence indicated that not only weathering but also failure mechanisms are 

location dependent. The highest degradation rates were observed in the polar/alpine climate, 

apparently because of high snow and wind loads. It is of interest to note that two other studies of 

crystalline Si technologies in the polar/alpine climate, one in the Canadian Arctic[118] and the 

other at a very high altitude in the European Alps, [48] found very low degradation rates. In both 

cases, the systems were installed in a facade and therefore bear no snow load. Marion and 

Adelstein found a decline of approximately 1%/year for two separate mono-Si arrays in Golden, 

CO, USA; most of that loss was attributed to the array. A small part originated from the 

maximum power tracking of the inverter, highlighting the importance of taking array decline into 

account for appropriate sizing [119]. Kiefer et al. surveyed several sites and found no 

degradation within the measurement uncertainty. To avoid the influence of seasonality, they only 

used the data from the same time period of the year for the evaluation [120]. The need for 

accurate measurements is pointed out by Vignola et al., who observed degradation rates between 

0·6% and 1·5%/year in Oregon, USA [121]. Given accurate measurements, a degradation rate of 

1%/year may be detected in as little as 2 years. Davis et al. determined degradation rates from 

several systems in Florida, USA, and employed different analytical methods to determine 

uncertainties [122]. Bunea et al. presented results of a side-by-side comparison of an array with 

and without an antireflective coating. The multiyear stability of the two arrays is comparable 

within the uncertainty [123].

14
Alonso-Abella et al. measured over 3000 modules from a 1-MW plant near Toledo, Spain, that 

was mentioned above and estimated degradation rates below 0·5%/year for one type of module 

and above 1%/year for another [53, 124]. Guastella provided an update on the Vulcano, Italy, 

plant and found degradation rates close to zero after 20 years of field exposure [125]. Additional 

studies on mono-Si in diverse geographical locations and climates from Mongolia [126], 

India [127], Spain [128], Brazil [129, 130], Tunisia [131], Japan [132], South Korea [133, 134], 

Saudi Arabia [135, 136], and Greece [137] have been reported.

Amorphous-Si

Rüther et al. reported on a round-robin study of four dual junction and one triple junction a-Si 

modules deployed simultaneously at three different sites in three different climates: Colorado 

and Arizona, USA, and Brazil [138]. Over the course of 4 years, all modules were exposed for 

1 year at each of the locations and investigated [139, 140]. Outdoor minimum temperature was 

found to be the determining factor for long-term stabilized performance. Fanni et al. investigated 

the annealing and degradation processes in flexible triple junction a-Si modules [141]. The 

degradation depended on the electric load: it was faster in open-circuit conditions than in shortcircuit conditions.

Dhere et al. examined a triple junction system in the hot and humid climate of Florida, USA. The 

reported degradation rate was 0·5%/year [142, 143]. Gottschalg et al. examined five different 

dual junction systems in different climate zones [144]. Seasonal effects commonly observed for 

a-Si systems were not attributed to seasonal annealing effects but due to incident spectra. 

Adelstein and Sekulic found a degradation rate of approximately 1%/year for a triple junction 

roof shingle a-Si system over 6 years [145]. The performance was assessed with the PVUSA and 

PR methods. McNutt et al. found a degradation rate above 1%/year after a 1-year stabilization 

period for a dual junction system that was decommissioned soon afterwards [146, 147]. Gregg et 

al. demonstrated a degradation rate of less than 1%/year for a triple junction system [148]. Davis 

and Moaveni compared the economics of a mono-Si with an a-Si system in the hot and humid 

climate of Florida, USA [149]. While the degradation rate for the a-Si system was significantly 

larger than that for the mono-Si system, lower upfront costs resulted in two closely matched 

systems. Comparable economics was also pointed out by Osborn for degradation rates below 

1%/year [150, 151]. Abete et al. reported a fairly high degradation rate for a dual junction a-Si 

12-kW system near Torino, Italy. A one-diode model was used to simulate the beginning of life 

performance as a baseline [152]. Apicella et al. reported a degradation rate of approximately 

1%/year for a single junction a-Si system in Italy [153]. A much higher rate was found for a 

microcrystalline Si system, possibly reflecting the maturity of the technology. Pietruszko et al. 

analyzed the performance of a dual junction a-Si system in the continental climate of Poland and 

observed a degradation rate of less than 1%/year [154]. Dirnberger et al. compared the 

degradation rates of several thin-film systems [155]. Degradation rates were close to zero and 

within the measurement uncertainty except in the moderate climate of Germany for a CdTe 

system. Single, double, and triple junction a-Si systems were investigated that displayed the 

predictable early light-induced degradation. Long-term stability depended more on module type 

than on technology. Häberlin and Schärf found the performance of several a-Si and a CIGS 

system comparable with that of mono-Si plants in the same location of Switzerland[156]. 

Guastella found very small degradation for an a-Si plant in Italy [157], as did Rüther et al. for an 

a-Si system in Brazil [158, 159]. Other long-term tests of interest include comparison of CIGS to 

15
a-Si and of single to triple junction a-Si in South Africa [160, 161] and for single junction a-Si 

modules in the Kenyan market [162].

Copper Indium Gallium Sellenide (CIS) 

Tarrant et al. reported on CIGS systems deployed at different sites in the USA [163]. On the 

basis of engineering modules, degradation rates were examined with respect to two different 

frame configurations. Del Cueto et al. detailed CIGS outdoor stability over two decades, utilizing 

three different testbeds in Colorado, USA [164]. It was shown that degradation rates can vary 

significantly depending on module type. The primary loss mechanism appears to be in the FF 

that is associated with an increase in series resistance. Musikowski and Styczynski demonstrated 

virtual stability of a CIGS array in Germany [165]. The performance was evaluated for different 

temperature and irradiance windows and showed no measureable degradation after 6 years of 

operation. A comparable observation was made by Jordan et al. at NREL in Colorado, 

USA [166]. Outdoor observation showed no significant decline after 5 years of operation. This 

was confirmed by indoor measurements. Only one out of 14 modules showed appreciable 

degradation owing to an initial manufacturing defect. 

Cadmium Telluride (CdTe)

Marion et al. analyzed a CdTe system at NREL in Colorado, USA [167]. Individual module 

efficiencies varied widely, with some improving by more than 10% while others degraded by 

more than 10% over a 5.5-year test period. However, the overall system degraded by 

approximately 0·6%/year. Ross et al. found a similar degradation rate for a system located in the 

hot and dry climate of Tucson, AZ, USA, over 3 years [168]. In addition, a system in the 

moderate climate of Germany was found to be virtually stable. Foster et al. found degradation 

rates ranging from close to zero to 1%/year for several systems installed in a hot and humid 

climate of Mexico [169]. 

Conclusion

A history of degradation rates using field tests reported in the literature during the last 40 years 

has been summarized. Nearly 2000 degradation rates, measured on individual modules or entire 

systems, have been assembled from the literature and show a mean degradation rate of 0·8%/year 

and a median value of 0·5%/year. The majority, 78% of all data, reported a degradation rate of 

<1%/year. Thin-film degradation rates have improved significantly during the last decade, 

although they are statistically closer to 1%/year than to the 0·5%/year necessary to meet the 25-

year commercial warranties. The significant difference between module and system degradation 

rates observed early on has narrowed, implying that substantial improvement toward the stability 

of the balance-of-system components has been achieved.

Despite the progress achieved in the last decade, several interesting questions, such as the 

linearity and the precise impact of climate, have not been satisfactorily answered. Nevertheless, 

the number of publications on long-term performance has been growing rapidly in recent years, 

reflecting the importance of the subject. It is the hope of the authors that this trend continues 

such that the increased information can better guide the development of accelerated tests. 

Finally, there may now be cumulative field experience to support long-term warranties, both 

16
because there are now products in the field for more than 25 years and because the average 

degradation rate still allows reasonable performance after 25 years.

Acknowledgement 

We would like to thank John Wohlgemuth for the review of the manuscript and the rest of 

NREL’s Reliability group for helpful discussions. This work was supported by the U.S. 

Department of Energy under Contract No. DE-AC36-08-GO28308 with the National Renewable 

Energy Laboratory. 

17
Number of. 

references

No. of Data 

Points

Median Exposure 

time (years)

Rd median 

(%/year) Reference

Technolo

gy

Configurat

ion Pre Post Pre Post Pre Post Pre Post Pre & Post

a-Si Module 10 12 45 31 7 2 0.96 0.87 34, 55-57, 61, 71-74, 78, 81-84, 87, 

88, 90-92, 141-145, 163-165 

System 14 9 21 14 5 4 1.30 0.95 31, 35-39, 75, 85, 94, 147, 146-162

CdTe Module 3 4 7 6 3 2 3.33 0.40 61, 73, 81-84, 91, 92

System 3 2 3 6 10 3 0.69 0.30 75, 85, 170, 171

CIGS Module 2 6 20 10 8 3 1.44 0.96 71-73, 78, 84, 90, 91, 163, 166, 

168, 169 

System 1 5 1 5 4 6 3.50 0.02 89, 158, 159, 169

mono-Si Module 31 11 1133 55 21 3 0.47 0.36 54, 59-61, 70-74, 77-84, 90-93, 95-

99, 102-118, 120, 129-134 

System 19 13 42 37 7 5 0.90 0.23 

19-23, 30-33, 46-49, 51-54, 62, 75, 

76, 86, 89, 94, 95, 100, 101, 113, 

119, 121-128, 135-139 

multi-Si Module 15 9 409 36 10 3 0.61 0.64 50, 51, 57, 59, 61, 71, 74, 78-84, 90, 

92, 97-99, 102-108, 117, 120, 129 

System 6 8 5 21 9 5 0.60 0.59 31, 47, 51, 62, 63, 76, 85, 86, 89, 

94, 123-125, 129, 140 

Table 1. Summary of the median degradation rate, number of data points reported, and number of publications partitioned by date of 

installation, technology, and configuration. “Pre” and “post” refer to installations prior to and post 2000.

18
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