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We present an evaluation of the ac capacity factor to estimate the reliability and performance trends of existing plants in the United States. The capacity factor is a metric that is widely used in the electrical power sector to estimate operational consistency. We show that the ac capacity factor provides useful insight to assess the system productivity. We analyze U.S. Energy Information Administration data for more than 2300 plants, showing that both ac capacity factor and inverter-loading ratios have increased in recent years, and that the capacity factor tends to increase for larger systems and increases as would be expected for mounting configurations and locations associated with high insolation. Evaluation of the data for reliable (consistent) performance concludes that inconsistent operation causes much more variation in reported electricity generation than linear degradation.

Richard E. Smalley, in 2003, defined the Terawatt (TW) Challenge as “Adapting our energy infrastructure to simultaneously address diminishing oil resources and rising levels of atmospheric CO 2.” Smalley, best known for the discovery of C 60, for which he received the 1996 Nobel Prize in Chemistry, continued to address the challenges of anthropomorphic and natural global energy flows until he passed away in 2005. Smalley challenged the world to transform the energy sector. He envisioned electricity transmitted by high-voltage direct current (DC) lines from massively deployed solar plants in sunny areas and remotely sited nuclear plants. He also envisioned using advanced batteries for local storage of energy. To meet the needs of ~10 people in a world with a dwindling oil supply, Smalley asserted that the world would need to transform its fossil-fuel-driven 14-TW (average power) energy used in 2003 to a largely renewable-energy-driven 30–60 TW (average power) in 2050. This would be possible only if solar-electricity costs could be drastically reduced. The challenges associated with this transition have been called the “Terawatt Challenge.” Fifteen years later, solar-module costs have been reduced by tenfold and annual deployment of solar photovoltaic (PV) modules has grown by a factor of 100,from ~1 gigawatt (GW) in 2004 to ~100 GW in 2018, with a total of 500 GW installed worldwide, producing 2% of the planet’s electricity. As global installed solar generating capacity approaches1 TW, we revisit Smalley’s TW challenge to identify what has changed and quantify the TW Challenge for a baseline scenario and for two scenarios designed as upper and lower bounds determined by the degree we implement electrification and storage. In this paper, we show that the energy choices we make today will dramatically affect the magnitude of future global energy requirements.

As solar electricity generation increases, the daytime net load (total load less solar generation) decreases, reducing prices in the middle of the day. These low prices reduce motivation to invest in more solar electricity. In this study, the correlation between net load and price is quantified on a seasonal average basis, and used to predict resulting hourly price changes if demand can be shifted from evening peak hours to mid-day when solar generation is greatest. The results suggest such a strategy will be of economic benefit to solar generators by increasing the price at mid-day for all electricity delivered, while reducing the price and thus total expenditures for energy during evening peak hours, with a net overall savings for energy consumers. These financial benefits motivate solar plant owners and developers to promote load-shifting, both to increase the revenue from current solar plants and to create demand for more solar plants.

Today resource adequacy is most often maintained by installing natural gas plants to meet the peak load. In California, the current risk of inadequate electricity supply is highest around sunset in late summer. In a zero-carbon grid, resource adequacy will increasingly require adequate stored energy throughout the entire year. Here we seek to develop an intuition about the times of the year when resource adequacy may be most challenged for a solar-dominant system. We use a simplified approach and show that the month of the biggest challenge occurs in winter and can shift by more than two months depending on the amount of solar and storage that are built.

Summary What role have batteries to play in the transition toward terawatt levels of photovoltaics? In this perspective, we attempt to answer this question by looking at technical, economic, and ecological features of PV-battery systems. We argue that the window of opportunity for batteries lies in the capacities of a few kWh/kWP, the exact amount depending on various factors including battery cost, degradation rate, location, load profile, diversification of renewable energy sources, and interconnections. Using a simple PV plus battery model, we illustrate that such storage capacities efficiently reduce fluctuations in electricity generation, enabling higher PV adoption rates at competitive costs, and with a carbon footprint that is at least five times lower than that of the current energy mixes. Using sensible capacities, batteries are a powerful companion for solar energy, yet technical, economic, and policy innovations are needed to expand adoption. We see longer battery lifetimes and low capacity degradation rates are the most impactful technological parameters. Economic efforts should aim to reduce balance of plant costs and create better market opportunities for stationary storage, whereas policies should provide a strong regulatory framework to facilitate multipurpose usage and sector coupling.

Noah Kittner is an assistant professor in energy in the Department of Environmental Sciences and Engineering, Gillings School of Global Public Health and in the Environment, Ecology, and Energy Program at the University of North Carolina at Chapel Hill. His research examines the role of energy storage in the transition to low-carbon energy systems and deep decarbonization. Sergio Castellanos is an assistant professor in the Department of Civil, Architectural and Environmental Engineering at the University of Texas at Austin, where he leads the Rapid, Equitable & Sustainable Energy Transitions (RESET) Lab focusing on equitable pathways for decarbonized energy systems. Patricia Hidalgo-Gonzalez is an assistant professor in the Jacobs School of Engineering and an affiliate member in the Center for Energy Research at the University of California, San Diego. She is the director of the Renewable Energy and Advanced Mathematics Laboratory. She is one of the academic co-leads of the IEEE Power & Energy Society Task Force “Data-Driven Controls for Distributed Systems.” Her research focuses on high penetration of renewable energy using optimization, control theory, and machine learning with safety guarantees. Daniel M Kammen is the James and Katherine Lau Distinguished Chair in Sustainability, and Chair of the Energy and Resources Group, Professor in the Goldman School of Public Policy, and Professor of Nuclear Engineering at the University of California, Berkeley. He has served as Chief Technical Specialist for Renewable Energy and Energy Efficiency at the World Bank, and Science Envoy in the US Department of State. His work is focused on the science and policy of decarbonization at scales from homes to villages to large utility-scale systems. He has been a Coordinating Lead Author for the IPCC since 1999. Sarah Kurtz is a Professor at the University of California Merced. She spent more than 30 years at the National Renewable Energy Laboratory studying multi-junction III-V solar cells, reliability of photovoltaic modules and systems, and other solar-related projects. She is now leading a study of the value of long-duration storage, funded by the California Energy Commission.

For each geographical region, one of the biggest challenges in reaching a zero-carbon grid is identifying sources of electricity that match the seasonal profile of the load. Summer-dominant solar electricity generation can often be balanced by winter-dominant wind electricity generation. Together with long-duration storage, balanced solar and wind generation are well positioned to provide reliable renewable electricity. However, in some locations the wind may not complement solar energy so well. For example, currently California's wind turbines produce more electricity during summer than winter, raising the question of whether all future wind plants in California will exhibit the same seasonality. As a response to this question, in this paper, we analyzed the generation from existing California wind plants and simulated potential onshore wind resource for the whole state using a metric that reflects the relative wind resource in winter. Our results indicate that the seasonality of the wind can vary for very small spatial difference with more than half of California showing stronger wind resource in the winter compared with the summer despite the current observation of the opposite trend. This study differentiates the seasonality of potential wind resources to inform the creation of a reliable, 100%-renewable-driven grid.

The paper describes a proposed qualification standard for photovoltaic concentrator modules. The standard's purpose is to provide stress tests and procedures to identify any component weakness in photovoltaic concentrator modules intended for power generation applications. If no weaknesses are identified during qualification, both the manufacturer and the customer can expect a more reliable product. The qualification test program for the standard includes thermal cycles, humidity-freeze cycles, water spray, off-axis beam damage, hail impact, hot-spot endurance, as well as electrical tests for performance, ground continuity, isolation, wet insulation resistance, and bypass diodes. Because concentrator module performance can not be verified using solar simulator and reference cell procedures suitable for flat-plate modules, the standard specifies an outdoor I-V test analysis allowing a performance comparison before and after a test procedure. Two options to this complex analysis are the use of a reference concentrator module for side-by-side outdoor comparison with modules undergoing various tests and a dark I-V performance check.

The following footnote should be included in this article [1]: This paper was commissioned for publication by David Cahen, who served as Editor-in-Chief of this journal from 2014-2018.

In "The 100 Percent Clean Energy Act of 2018" the California legislature set a target of 100\% of California's electricity generated from renewable and zero-carbon sources by 2045. The California Public Utility Commission (CPUC) and other state entities now have the task of planning to meet that target. The California Energy Commission (CEC) has sponsored multiple studies and sought public input on the pathways that they are exploring. A key result of that planning process is a Reference System Portfolio (RSP) based on existing and planned electricity generating capabilities, and modeled grid build out to meet the planned targets by 2045 at the lowest cost. Although this RSP has been discussed by the CEC in a public forum, to our knowledge, it has not been presented to the photovoltaic community.Here we document the CEC’s current RSP, with emphasis on understanding their expectations for build out of solar as well as the associated need for storage and curtailment.

Optimization models can be quite powerful in identifying a pathway to lowest cost zero-carbon energy systems. However, it is less obvious how to invert the models to calculate the target cost and duration of storage needed for that storage to be a significant solution. Storage is a dispatchable and flexible resource with the ability to perform many functions of grid support, further complicating the analysis. This paper complements existing papers by presenting an academic study of a simplified energy system, demonstrating a method for quantifying cost and duration targets for storage. The simplified analysis also helps to gain intuition about the synergistic relationship between storage and solar energy in a location like the state of California.

The standardization of VIPV (Vehicle-integrated photovoltaic) has been driven by the international discussion among scientists and engineers, from photovoltaic research, photovoltaic industries, automobile and other industries, and testing laboratories. Since the VIPV is not flat and fixed installation, as well as a wide variety of designs, the knowledge of CPV (Concentrator Photovoltaic) technology, has been useful for developing testing technologies. This paper took two examples in the performance testing and the test for the tolerance for the partial/dynamic shading, utilizing various techniques exclusively used in CPV technologies.

A car-roof photovoltaic (PV) has significant potential. The activities of international standardization through a series of web meetings have been done by 51 volunteer scientists and engineers from 15 different countries with a good mixture of scientists, manufacturers, and testing laboratories. Specifically, it covered (1) Irradiance modeling onto the car-roof; (2) Curve correction of the PV output; (3) Quantification of partial shading loss; (4)Performance testing conditions; (5) Effective solar resource on the car-roof impacted by shadows of surrounding buildings; (6) Environmental testing conditions.

The degradation rate plays an important role in predicting and assessing the long-term energy generation of photovoltaics (PV) systems. Many methods have been proposed for extracting the degradation rate from operational data of PV systems, but most of the published approaches are susceptible to bias due to inverter clipping, module soiling, temporary outages, seasonality, and sensor degradation. In this paper, we propose a methodology for determining PV degradation leveraging available modeled clear-sky irradiance data rather than site sensor data, and a robust year-over-year rate calculation. We show the method to provide reliable degradation rate estimates even in the case of sensor drift, data shifts, and soiling. Compared with alternate methods, we demonstrate that the proposed method delivers the lowest uncertainty in degradation rate estimates for a fleet of 486 PV systems.

Champion photovoltaic (PV) cell and module efficiencies have been reported in Progress in PV since 1993. Following the evolution of these efficiencies enables researchers to track the progress of various technologies. National Renewable Energy Laboratory has maintained a historical chart of the champion cell efficiencies, but has not published a similar chart of champion module efficiencies. Here, we analyze champion module efficiencies and compare them to champion cell efficiencies to better understand technology trends over the last three decades, highlighting that, in some cases, module efficiencies exceed 90% of cell efficiencies. Recommendations are provided on how to change the data collection and reporting for champion efficiencies to increase the value of these records.

A silicon heterostructure photovoltaic system fielded for 10 years has been investigated in detail. The system has shown degradation, but at a rate similar to an average Si system, and still within the module warranty level. The power decline is dominated by a nonlinear V oc loss rather than more typical changes in I sc or Fill Factor. Modules have been evaluated using multiple techniques including: dark and light I – V measurement, Suns- V oc, thermal imaging, and quantitative electroluminescence. All techniques indicate that recombination and series resistance in the cells have increased along with a decrease of factor 2 in minority carrier lifetime. Performance changes are fairly uniform across the module, indicating changes occur primarily within the cells.

The width-tapered cantilever beam method is used to quantify the debond energy (adhesion) of encapsulant and backsheet structures of 32 modules collected from the field. The collected population of modules contains both those that have remained intact and those with instances of either or both encapsulant and backsheet delamination. From this survey, initial threshold values (an adhesion value above which a module should remain intact throughout its lifetime) for encapsulant and backsheet interfaces are proposed. For encapsulants this value is ∼ $160\,{\text{J}\text{/}\text{m}}^{2}$ and for backsheets ∼ $10\,{\text{J}\text{/}\text{m}}^{2}$ . It is expected that these values will continue to be refined and evolve as the width-tapered cantilever beam method gets adopted by the PV industry, and that they may aid in the future improvement of accelerated lifetime tests and the development of new, low-cost materials.

The extensive photovoltaic field reliability literature was analyzed and reviewed. Future work is prioritized based upon information assembled from recent installations, and inconsistencies in degradation mode identification are discussed to help guide future publication on this subject. Reported failure rates of photovoltaic modules fall mostly in the range of other consumer products; however, the long expected useful life of modules may not allow for direct comparison. In general, degradation percentages are reported to decrease appreciably in newer installations that are deployed after the year 2000. However, these trends may be convoluted with varying manufacturing and installation quality world-wide. Modules in hot and humid climates show considerably higher degradation modes than those in desert and moderate climates, which warrants further investigation. Delamination and diode/j-box issues are also more frequent in hot and humid climates than in other climates. The highest concerns of systems installed in the last 10 years appear to be hot spots followed by internal circuitry discoloration. Encapsulant discoloration was the most common degradation mode, particularly in older systems. In newer systems, encapsulant discoloration appears in hotter climates, but to a lesser degree. Thin-film degradation modes are dominated by glass breakage and absorber corrosion, although the breadth of information for thin-film modules is much smaller than for x-Si. Copyright © 2017 John Wiley & Sons, Ltd.

In this issue of Joule, Steffen et al. tackle a challenging topic to quantify and project costs for operation and maintenance (O&M) of solar and wind power plants in Germany. They note that O&M costs can be 20%–25% of overall costs and find that such costs have decreased, resulting in common overestimates of O&M costs.

The photovoltaics industry has grown remarkably in recent decades but as it has grown, quality assurance during the manufacturing and installation processes has become increasingly important. There is often a cultural divide between those who develop and those who implement the designs, motivating partnering of these efforts.

Solar cells can be built directly into the things around us, but they generally aren’t. Is it a missed opportunity? In the early days of photovoltaic (PV) research, a mainstream opinion envisioned the future of PV as building-integrated and that utility-scale installations would be anomalies. As an example, in 1994, PowerLight introduced a solar roofing tile system, touting it as saving money (avoiding the cost of installing a conventional roof) while integrating PV into an attractive roof. However, today, utility-scale PV accounts for more than half of the world’s PV installations, and building-integrated PV (BIPV) is a niche market (with most rooftop systems being “buildingapplied” rather than “building-integrated”). This motivates the question: “Was integrating PV into the desired product a bad idea or is it an idea whose time has not yet come?” Many things have changed since the 1990s including microinverters and other power electronics, PV with lower temperature coefficients, and demonstration of PV as an accepted technology so that it is not such a risk to builders, potentially giving a fresh opportunity. In this article, we explore the potential value of integrating PV into surfaces and the challenges to achieving that value.

We evaluate the feasibility of using various clear-sky models or purchased satellite data for estimating the soiling of a reference cell irradiance sensor. We find results to be more accurate for models that consider local meteorological conditions. We conclude that given the data sets considered, and depending on the requirements of the data analyst, choosing to use purchased satellite irradiance data from Solargis to estimate the soiling of a reference cell sensor tends to yield more accurate results, although there are instances where a clear-sky model performs better. The SOLIS clear-sky model in PVLIB with variable P wat provided useful soiling results, implying that the general method of using a clear-sky model with local meteorological data may provide a low-cost tool for detecting soiling of irradiance sensors.

Solar energy has the potential to play a central role in the future global energy system because of the scale of the solar resource, its predictability, and its ubiquitous nature. Global installed solar photovoltaic (PV) capacity exceeded 500 GW at the end of 2018, and an estimated additional 500 GW of PV capacity is projected to be installed by 2022–2023, bringing us into the era of TW-scale PV. Given the speed of change in the PV industry, both in terms of continued dramatic cost decreases and manufacturing-scale increases, the growth toward TW-scale PV has caught many observers, including many of us (1), by surprise. Two years ago, we focused on the challenges of achieving 3 to 10 TW of PV by 2030. Here, we envision a future with ∼10 TW of PV by 2030 and 30 to 70 TW by 2050, providing a majority of global energy. PV would be not just a key contributor to electricity generation but also a central contributor to all segments of the global energy system. We discuss ramifications and challenges for complementary technologies (e.g., energy storage, power to gas/liquid fuels/chemicals, grid integration, and multiple sector electrification) and summarize what is needed in research in PV performance, reliability, manufacturing, and recycling.

A technical basis for measurement of the operating temperatures of PV modules in vehicle-integrated applications is explored. Convective and radiative heat transfer are modeled to elucidate the methodology. Data reported for sister modules mounted in an experimental black box and in the sun roof of a car show very similar temperatures. The box provides a uniform environment in the closed configuration, but can be adjusted to explore a wider range of operating environments by opening or closing the sides and by insulating the back.

GaAs, monocrystalline Si, and multicrystalline Si modules were tested in a configuration designed to simulate car-roof-integrated mounting. The increase in module temperature above ambient was similar for the four Si modules, but less (~76%) for the GaAs modules. Local temperatures within each module were strongly dependent on the optical properties of the back sheet. The lower operating temperature combined with smaller temperature coefficient of the GaAs modules resulted in higher performance ratios for the GaAs modules even for ambient temperature

Finite element model (FEM) simulations have been performed to elucidate the effect of flat plate photovoltaic (PV) module materials and design on PbSn eutectic solder joint thermal fatigue durability. The statistical method of Latin Hypercube sampling was employed to investigate the sensitivity of simulated damage to each input variable. Variables of laminate material properties and their thicknesses were investigated. Using analysis of variance, we determined that the rate of solder fatigue was most sensitive to solder layer thickness, with copper ribbon and silicon thickness being the next two most sensitive variables. By simulating both accelerated thermal cycles (ATCs) and PV cell temperature histories through two characteristic days of service, we determined that the acceleration factor between the ATC and outdoor service was independent of the variables sampled in this study. This result implies that an ATC test will represent a similar time of outdoor exposure for a wide range of module designs. This is an encouraging result for the standard ATC that must be universally applied across all modules.

This paper presents a model for evaluating the heat-sink and component temperatures of open-rack installed photovoltaic inverters. These temperatures can be used for predicting inverter reliability. Inverter heat-sink temperatures were measured for inverters connected to three grid-connected PV (photovoltaic) test systems in Golden, Colorado, US. A model is proposed for calculating the inverter heat-sink temperature based on the ambient temperature, the ratio of the consumed power to the rated power of the inverter, and the measured wind speed. To verify and study this model, more than one year of inverter DC/AC power, irradiance, wind speed, and heat sink temperature rise data were collected and analyzed. The model is shown to be accurate in predicting average inverter temperatures, but will require further refinement for prediction of transient temperatures.

A progression of potential-induced degradation (PID) mechanisms is observed in CdTe modules, which are dependent on the stress level and moisture ingress. This includes shunting, junction degradation, and two different manifestations of series resistance. The dark I–V method for in situ characterization of P max based on superposition was adapted for the thin-film modules undergoing PID in view of the degradation mechanisms observed. An exponential model based on module temperature and relative humidity (RH) was fit to the PID rate for multiple stress levels in chamber tests and validated by predicting the observed degradation of the module type in the field.

Photovoltaic (PV) reliability and durability have seen increased interest in recent years. Historically, and as a preliminarily reasonable approximation, linear degradation rates have been used to quantify long-term module and system performance. The underlying assumption of linearity can be violated at the beginning of the life, as has been well documented, especially for thin-film technology. Additionally, non-linearities in the wear-out phase can have significant economic impact and appear to be linked to different failure modes. In addition, associating specific degradation and failure modes with specific time series behavior will aid in duplicating these degradation modes in accelerated tests and, eventually, in service life prediction. In this paper, we discuss different degradation modes and how some of these may cause approximately linear degradation within the measurement uncertainty (e.g., modules that were mainly affected by encapsulant discoloration) while other degradation modes lead to distinctly non-linear degradation (e.g., hot spots caused by cracked cells or solder bond failures and corrosion). The various behaviors are summarized with the goal of aiding in predictions of what may be seen in other systems. Published 2016. This article is a U.S. Government work and is in the public domain in the USA.

The typical configuration of monolithic thin-film photovoltaic modules makes it possible for partial shade to place one or more cells in such a module in reverse bias. Reverse bias operation leads to high voltage, current density, and power density conditions, which can act as driving forces for failure. We showed that a brief outdoor shadow event can cause a 7% permanent loss in power. We applied an indoor partial shade durability test that moves beyond the standard hot spot endurance test by using more realistic mask and bias conditions and by carefully quantifying the permanent change in performance due to the stress. With the addition of a pass criterion based on change in maximum power, this procedure will soon be proposed as a part of the module-type qualification test. All six commercial copper indium gallium diselenide and cadmium telluride modules we tested experienced permanent damage due to the indoor partial shade test, ranging from 4% to 14% loss in maximum power. We conclude by summarizing ways to mitigate partial shade stress at the cell, module, and system levels.

The durability of polymeric encapsulation materials was examined using outdoor exposure at the nominal geometric concentration of 500 suns. The results for 36 months cumulative field deployment are presented for materials including: poly(ethylene-co-vinyl acetate), (EVA); polyvinyl butyral (PVB); ionomer; polyethylene/ polyoctene copolymer (PO); thermoplastic polyurethane (TPU); poly(dimethylsiloxane) (PDMS); poly(diphenyl dimethyl siloxane) (PDPDMS); and poly(phenyl-methyl siloxane) (PPMS). Measurements of the field conditions including ambient temperature and ultraviolet (UV) dose were recorded at the test site during the experiment. Measurements for the experiment included optical transmittance (with subsequent analysis of solar-weighted transmittance, UV cut-off wavelength, and yellowness index), mass, visual photography, photoelastic imaging, and fluorescence spectroscopy. While the results to date for EVA are presented and discussed, examination here focuses more on the siloxane materials. A specimen recently observed to fail by thermal decomposition is discussed in terms of the implementation of the experiment as well as its fluorescence signature, which was observed to become more pronounced with age. Modulated thermogravimetry (allowing determination of the activation energy of thermal decomposition) was performed on a subset of the siloxanes to quantify the propensity for decomposition at elevated temperatures. Supplemental, Pt-catalyst- and primer-solutions as well as peroxide-cured PDMS specimens were examined to assess themore » source of the luminescence. The results of the study including the change in optical transmittance, observed failure modes, and subsequent analyses of the failure modes are described in the conclusions.« less

FEM simulations of PbSn solder fatigue damage are used to evaluate seven cities that represent a variety of climatic zones. It is shown that the rate of solder fatigue damage is not ranked with the cities' climate designations. For an accurate ranking, the mean maximum daily temperature, daily temperature change and a characteristic of clouding events are all required. A physics-based empirical equation is presented that accurately calculates solder fatigue damage according to these three factors. An FEM comparison of solder damage accumulated through service and thermal cycling demonstrates the number of cycles required for an equivalent exposure. For an equivalent 25-year exposure, the number of thermal cycles (− 40 °C to 85 °C) required ranged from roughly 100 to 630 for the cities examined. It is demonstrated that increasing the maximum cycle temperature may significantly reduce the number of thermal cycles required for an equivalent exposure.

A side-by-side comparison is made between concentrator photovoltaic module and system direct current aperture efficiency data with a focus on quantifying system performance losses. The individual losses measured/calculated, when combined, are in good agreement with the total loss seen between the module and the system. Results indicate that for the given test period, the largest individual loss of 3.7% relative is due to the baseline performance difference between the individual module and the average for the 200 modules in the system. A basic empirical model is derived based on module spectral performance data and the tabulated losses between the module and the system. The model predicts instantaneous system direct current aperture efficiency with a root mean square error of 2.3% relative.

Published data on photovoltaic (PV) degradation measurements were aggregated and re-examined. The subject has seen an increased interest in recent years resulting in more than 11 000 degradation rates in almost 200 studies from 40 different countries. As studies have grown in number and size, we found an impact from sampling bias attributable to size and accuracy. Because of the correlational nature of this study we examined the data in several ways to minimize this bias. We found median degradation for x-Si technologies in the 0.5–0.6%/year range with the mean in the 0.8–0.9%/year range. Hetero-interface technology (HIT) and microcrystalline silicon (µc-Si) technologies, although not as plentiful, exhibit degradation around 1%/year and resemble thin-film products more closely than x-Si. Several studies showing low degradation for copper indium gallium selenide (CIGS) have emerged. Higher degradation for cadmium telluride (CdTe) has been reported, but these findings could reflect a convolution of less accurate studies and longer stabilization periods for some products. Significant deviations for beginning-of-life measurements with respect to nameplate rating have been documented over the last 35 years. Therefore, degradation rates that use nameplate rating as reference may be significantly impacted. Studies that used nameplate rating as reference but used solar simulators showed less variation than similar studies using outdoor measurements, even when accounting for different climates. This could be associated with confounding effects of measurement uncertainty and soiling that take place outdoors. Hotter climates and mounting configurations that lead to sustained higher temperatures may lead to higher degradation in some, but not all, products. Wear-out non-linearities for the worst performing modules have been documented in a few select studies that took multiple measurements of an ensemble of modules during the lifetime of the system. However, the majority of these modules exhibit a fairly linear decline. Modeling these non-linearities, whether they occur at the beginning-of-life or end-of-life in the PV life cycle, has an important impact on the levelized cost of energy. Copyright © 2016 John Wiley & Sons, Ltd.