Products & Equipment : Modules

Primary Category: 

Module manufacturers are continuously refining their cell materials, designs and manufacturing processes; optimizing cell and cell-string electrical interconnectivity; and developing specialized glass, encapsulants and structural elements to create large-format, high-power products. These approaches have resulted in the rapid expansion of a high-power module product class that solar professionals commonly delineate as products with outputs of 300 W STC and greater.

Updated for 2017, the following c-Si module specifications table includes detailed electrical and mechanical specifications for 232 models with rated outputs of 300 W STC and greater from 29 manufacturers. The included models are listed and available for deployment in US-based projects. This c-Si specifications table is not intended to be exhaustive or all-inclusive; rather, our goal is to present comparative information on a wide cross-section of high-power PV solutions for utility, commercial and select residential projects.


Joe Schwartz / SolarPro / Ashland, OR /

PV Manufacturer Contact:

Astronergy / 415.802.7399 /

Auxin Solar / 408.868.4380 /

AXITEC / 856.254.9057 /

Boviet Solar / 877.253.2858 /

Canadian Solar / 888.998.7739 /

Centrosolar America / 877.348.2555 /

ET Solar / 925.460.9898 /

Hanwha Q Cells / 949.748.5996 /

Itek Energy / 360.647.9531 /

Jinko Solar / 415.402.0502 /

Kyocera Solar / 800.223.9580 /

LG / 888.865.3026 /

Mission Solar Energy / 210.531.8600 /

Panasonic /

Phono Solar / 855.408.9528 /

REC Group / 877.890.8930 /

Silfab Solar / 905.255.2501 /

Solaria / 510.270.2500 /

SolarTech Universal / 561.440.8000 /

SolarWorld / 503.844.3400 /

Sonali Solar / 888.587.6527 /

Suniva / 404.477.2700 /

SunPower / 408.240.5500 /

Ten K Solar / 877.432.1010 /

Trina Solar / 800.696.7114 /

Upsolar / 415.263.9920 /

Vikram Solar /

WINAICO / 844.946.2426 /

Yingli Solar /

Primary Category: 

Conventional PV modules are monofacial, meaning that their electrical power output is a function of the direct and diffuse radiation captured on the front side of the module only. By contrast, bifacial modules convert light captured on both the front and back sides of the module into electrical power. Bifaciality improves PV system energy capture—dramatically in some cases—and rewrites conventional system design rules in interesting ways.

This article is an introduction to bifacial PV systems. After briefly reviewing the history of bifacial PV cells and providing a high-level overview of bifacial cell technologies, I summarize the potential benefits of bifacial PV modules and systems. I then focus on best practices and applications for designing and deploying systems that integrate bifacial PV modules. Finally, I consider some challenges to adoption and important efforts under way internationally to unlock the full commercial potential of bifacial PV systems.


Research on bifacial PV cells dates back to the dawn of the solar industry, according to Andrés Cuevas’ oft-cited article, “The Early History of Bifacial Solar Cells” (see Resources). Japanese researcher H. Mori proposed a bifacial PV cell design as early as 1960 and had successfully developed a working prototype by 1966. Russian and Spanish researchers proposed uses for bifacial PV cells around the same time. It was the Russians, however, who first deployed bifacial PV modules in the 1970s, as part of their space program. A major milestone occurred in 1980, when Cuevas and some of his colleagues in Spain documented the ability of light-colored surfaces to direct reflected light (albedo) to the back of a bifacial PV cell and increase its power output by 50%.

Due to the high cost of producing bifacial PV cells, the first terrestrial applications for this technology were relatively late to emerge. One of the best-documented early field applications is a north-south–oriented vertical photovoltaic noise barrier that Swiss researchers deployed in 1997 along the A1 motorway in Zurich using 10 kW of bifacial PV modules. The first signs of commercialization, at least in North America, appeared roughly a decade later when Sanyo introduced its first UL-listed HIT Double bifacial PV modules. Though Panasonic, which acquired Sanyo, subsequently discontinued the bifacial product line, as of January 2017, at least eight manufacturers offer bifacial PV modules certified for use in North America (see Table 1).

Cell technology. While bifacial PV cells currently make up an insignificant percentage of worldwide PV cell sales, the technology is in some ways a continuation or logical extension of standard monocrystalline silicon (mc-Si) cell technology. Depending on whether the semiconductor material contains a relative abundance or deficiency of electrons, the industry broadly categorizes mc-Si cells as either n-type or p-type devices, respectively. It is possible to fabricate bifacial cells out of both p-type and n-type wafers, given high-quality silicon material, although the process requires some additional manufacturing steps compared to producing conventional monofacial cells.

In practice, more than 90% of the PV cells sold worldwide are based on a p-type architecture, while the vast majority of the bifacial products in Table 1 are n-type devices. This underscores the fact that many n-type PV cells, which are primarily found in niche high-efficiency modules from companies such as LG, Panasonic and SunPower, are inherently bifacial. (Some people trace the history of bifacial PV cells all the way back to Bell Labs, since its first practical solar cell in 1954 was an n-type device.) P-type devices dominate the market because they are cost-effective to fabricate at scale. While n-type bifacial cells offer the highest efficiency, companies such as SolarWorld are betting that p-type bifacial cells can provide a good balance between performance and cost.

Regardless of the specific cell technology, the rear side of a bifacial PV cell needs to be able to act as a collector, which requires advanced architectures and manufacturing techniques. The authors of the informative Electric Power Research Institute (EPRI) Bifacial Solar Photovoltaic Modules (see Resources) explain: “Today’s crystalline silicon and thin-film monofacial PV cells commonly use a fully metallized backside. This feature involves a moderately thick metal contact for reduced series resistance and is relatively inexpensive to produce. By contrast, bifacial cells incorporate selective-area metallization schemes to allow light between the metallized areas.”

Though thin-film manufacturers are still working out the material science issues necessary for bifacial thin-film modules, many mc-Si manufacturers have successfully produced bifacial cells, which often incorporate thin-film layers, such as the rear passivation layers of amorphous silicon in Figure 1. The next challenge is adapting these technological advances for mass manufacturing. The EPRI report continues: “The lower amount of metal changes how cell performance is optimized, potentially requiring tighter (more expensive) specs on the silicon and thin-film material used and also increasing series resistance concerns. Furthermore, bifacial cells may employ different metals, such as copper and nickel, and/or deposition methods, such as plating or inkjet printing, which, in part, requires different equipment and entails a potentially more complex manufacturing process. Consequently, the backside metal represents a nontrivial impediment to manufacturing bifacial cells with high performance and low cost. This added complexity and cost needs to be offset by the performance gains from increased light collection.”


The rapid growth of the solar industry in recent years has been largely premised on significant up-front cost reductions, especially lower costs for PV modules. Bifacial PV modules run counter to the grain in the market since they are inherently more expensive than conventional monofacial modules. Fabricating bifacial PV cells requires not only high-quality mc-Si wafers, but also anywhere from two to six additional manufacturing steps compared to conventional cells.

The crux of the bifacial value proposition, therefore, is improved production and performance over the life of the system, which is a function of both bifacial energy gains and improved durability. Because bifacial modules offer high conversion efficiencies, they also have the potential to lower BOS costs, which make up an increasing percentage of up-front system costs. The ultimate goal, of course, is a lower levelized cost of energy (LCOE).

Increased energy generation. Unlike PV systems deployed with monofacial modules, bifacial PV systems can convert light that shines off the back of the module into electricity. This additional back-side production increases energy generation over the life of the system. Ongoing research and side-by-side testing suggests that a bifacial PV system could generate 5%–30% more energy than an equivalent monofacial system, depending on how and where you install the modules. Moreover, the manufacturers’ linear performance warranties for bifacial PV modules are some of the best in the industry.

Improved durability. To allow light to shine on the back-side of a bifacial cell, module manufacturers need to use either a UV-resistant transparent backsheet material or an additional layer of solar glass. In most cases, as shown in Table 1, manufacturers have opted for a glass-on-glass package that generally improves field durability as compared to glass-on-film options. Not only is a glass-on-glass package more rigid—which reduces mechanical stress on cells during transportation, handling and installation, or from environmental conditions such as wind or snow—but it is also less permeable to water, which may reduce annual degradation rates. Moreover, many bifacial modules are frameless, and eliminating the aluminum frame effectively reduces opportunities for potential-induced degradation (PID).

Reduced BOS. As prices for modules and interactive inverters have fallen in recent years, BOS costs—specifically, the costs associated with mounting systems—have come to make up an increasing percentage of total PV system costs. An interesting side effect of this trend is that commercializing higher-module efficiencies is beginning to look like one of the best opportunities to squeeze additional value out of PV systems. Higher-efficiency modules not only reduce the area of the mounting system on a per kW basis, but also allow a developer to increase system capacity and energy harvest at a given site with fixed development costs.

Lower LCOE. The LCOE for a power generation asset is found by dividing the total life-cycle costs—both the up-front construction costs and the operational costs over time—by the total lifetime energy production. In the field, bifacial PV modules outperform their nominal power and efficiency ratings, which addresses the energy-generation side of the LCOE calculation. Factoring in the bifacial energy gain, a 19% efficient bifacial 300 W module might harvest energy in a field application equivalent to what a 21% efficient 335 W monofacial module produces. From the manufacturer’s perspective, meanwhile, it is could be more cost-effective to add bifaciality to a 20% efficient mc-Si cell than to mass-produce a monofacial one that is 22% efficient. This balance between performance and cost can make bifaciality an attractive feature for a module manufacturer’s technology roadmap.


Though bifacial PV modules can convert both front- and rear-side irradiance to electrical power, they nevertheless put their best face forward, in the sense that front-side efficiencies are invariably higher than back-side efficiencies, whether due to semiconductor properties or the amount of back contact metallization. The bifacial ratio quantifies the STC-rated power of a bifacial module’s back side in relation to the front-side power. For the products in Table 1, bifacial ratios range between 55% and 95%, which obviously suggests something about the relative energy production for different products in equivalent applications.

Regardless of its specific bifacial ratio value, the field performance of any bifacial PV system is highly dependent on back-side irradiance. Generally speaking, back-side irradiance is light reflected off an adjacent horizontal surface. Therefore, you can optimize bifacial PV systems by following a few simple guidelines: Install bifacial arrays above surfaces that reflect as much light as possible, increase array height or tilt angle to collect more reflected light and avoid shading the back side of the array.

Surface reflectivity. A bifacial PV system will generate more energy when installed over a light-colored rather than a dark-colored surface. This is because the former will reflect more light onto the back of the array, whereas the latter absorbs more of the incident irradiance. Albedo is a dimensionless quantity, usually expressed as a percentage, that describes this ratio between light reflected off a surface and the original incident irradiance. The higher the albedo value, the higher the surface reflectivity.

Table 2 provides representative albedo values for a variety of common ground surface types, as documented in the SolarWorld white paper “How to Maximize Energy Yield with Bifacial Technology” (see Resources). These values suggest that white roofing membranes, which reflect roughly 80% of the incident light when new and unweathered, are an ideal ground cover surface under a bifacial PV array. By contrast, the measured albedo value for raw concrete is only 16%. While the albedo for concrete increases dramatically when it is painted white, SolarWorld’s research indicates that not all light-colored surfaces are created equally. White gravel, for instance, has a relatively low albedo due to an “open-pored structure [that] causes a large amount of light to be lost within the voids.”

While the additional rear-side power output in a bifacial system is clearly proportional to ground surface albedo, the authors of the EPRI article note that this simple relationship “belies the fact that, in practice, energy gain depends on a number of complicated installation-specific factors.” For example, white surfaces reflect light of all colors, whereas other surfaces reflect light preferentially, absorbing some colors and reflecting others. Grass, for instance, absorbs blue and red light and mostly reflects green light. PV cells, meanwhile, vary in their ability to collect and convert different wavelengths of light into electrons.

Height and tilt angle. The closer you install a bifacial array to the ground or roof surface, the more self-shading occurs. Flush mounting, for example, effectively blocks any reflected light from reaching the back of the array. Increasing the height of the array or its tilt angle increases reflected light collection and enhances the bifacial contribution. Generally speaking, the higher you can install a bifacial PV array, the better its bifacial energy gain. However, this does not mean that bifacial modules are suited for carports and awnings only.

SolarWorld simulations suggest that a significant bifacial energy boost is possible with a relatively modest height increase. Not only is the energy boost curve in Figure 2 steepest between 0 and 0.2 meters (7.9 inches), but also the inflection point occurs somewhere around 0.5 meters (19.7 inches), after which point the curve begins to flatten out; the saturation point occurs around 1.0 meter (39.4 inches), meaning that additional energy gains are negligible above this height. These data suggest that bifacial modules are potentially well suited for just about any ground-mounted application, as the leading edge of these arrays is often 18 inches–36 inches above grade.

It is also possible to adapt conventional flat roof– mounting systems for use in bifacial applications. In its bifacial system design guide, for example, Prism Solar recommends a minimum height of just 6 inches above the reflective surface. To facilitate a slight increase in array height in low-slope–roof applications, the company has worked with mounting system manufacturers, most notably Opsun Systems, to develop structural solutions optimized for use with bifacial modules. In addition to a modified ground-mount system, the Bifacial SunGround, Opsun Systems also offers the SunRail Structure Bifacial, a higher-elevation version of its standard commercial rooftop mounting system.

Back-side shading. To optimize bifacial energy gains, system designers also need to avoid shading the back side of the array. Most racking systems have rails that run across the module’s backside, which an opaque white or black film usually covers. These structural components, especially support rails, are potential sources of shade in a bifacial system. As a result, mounting systems optimized for bifacial applications locate mounting rails at the perimeter of the modules, orienting these in parallel with rather than perpendicular to the module frame or the edge of the glass.

Back-side shading is also a concern for bifacial module manufacturers. The junction box on many monofacial modules, for example, is located directly behind one or more PV cells. By contrast, most bifacial modules have a low-profile junction box located at the perimeter of the module to minimize back-side cell shading. Though testing indicates that back-side shading from junction boxes or mounting structures will not damage a bifacial module, it does result in yield losses.


Data from initial test beds and performance simulations—some of which are summarized later in this article—suggest many potential applications for bifacial PV systems. These include most conventional applications such as flat roofs and free fields, where installers deploy monofacial PV modules today, as well as niche applications such as building-integrated PV (BIPV) carports and awnings, where they typically deployed early bifacial modules. Back-side power collection also rewrites the rules that apply to traditional PV system design and performance, which could enable new markets and business models.

Sandia test results. Sandia National Laboratories recently published a report (see Resources) documenting the side-by-side test results for Prism Solar bifacial modules in comparison to reference monofacial modules. Sandia installed modules at the test bed in five orientations over two surfaces at its New Mexico Regional Test Center. Data collected over a 6-month period (between February 15 and August 15, 2016) indicated that the bifacial modules were outproducing the monofacial devices by anywhere from 18% to 136%, depending on the orientation and ground cover. Figure 3 provides the average daily power output curve for each test condition.

The report’s authors draw some interesting conclusions from these data. First, they note that bifacial gains vary throughout the day, depending on the angle of the sun or whether conditions are clear or cloudy. The impacts of sun angle are somewhat intuitive when you consider that the sun is closest to the horizon early in the morning and late in the afternoon, which not only decreases the available incident energy but also increases the amount of reflected light. As a result, the percentage of the instantaneous power output resulting from the bifacial contribution is highest at these times, and the bifacial gains are relatively lower at or around solar noon. The impacts of direct versus diffuse irradiance are similar. During cloudy conditions, the incident energy is relatively low, which increases the percentage of bifacial gain due to reflected light. Under sunny conditions, by comparison, the bifacial contribution is higher in absolute terms (back-side power) but lower in relative terms (percentage of bifacial gain).

The authors also note that bifacial modules are relatively insensitive to changes in array azimuth. As you rotate a bifacial array east or west of true south, the bifacial boost increases, effectively offsetting some of the losses that a monofacial array experiences in non-optimal orientations. As a result, “west-facing bifacial modules tilted at 15° produced a similar amount of energy as south-facing, 15°-tilted bifacial modules and surpassed the energy production of all of the monofacial orientations considered.” Not only did the west-facing, 15°-tilted bifacial array outperform the optimally oriented monofacial arrays, tilted at 15° and 30°, but also the west-facing, vertically oriented (90° tilt) bifacial array “outperformed monofacial modules at any orientation.”

Not surprisingly, the bifacial gains were also greatest in a west-facing, vertically oriented application, which creates an effective collection area for bifacial modules literally double that of monofacial modules. As a result, the bifacial power curve in this application has two peaks, one in the morning and one in the afternoon, whereas the equivalent monofacial power curve has one peak only. An east-west facing array is also effective at shifting solar power production later into the afternoon, when electric demand is often greatest. This configuration is likely well suited to take advantage of certain time-of-use rate structures and could provide additional value to utility operators. (The downside of an east-west vertical orientation is its high susceptibility to horizon shading losses.)


On the one hand, bifacial PV arrays require specialized modules and mounting systems, as compared to conventional PV systems, which invariably increases up-front system costs. On the other, side-by-side field tests, such as those Sandia conducted, clearly reveal a bifacial energy boost. It is entirely possible, therefore, that bifacial PV systems could provide the best value, in terms of LCOE or return on investment, in certain applications. Making that case and taking it to investors, however, remains a barrier to widespread market adoption.

Macroeconomic conditions. In the short term, the low costs for conventional monofacial PV modules represent one of the biggest challenges to the commercialization of bifacial products. Module prices are at an all-time low, largely due to downward price pressure caused by global oversupply. As a result, many manufacturers are operating at low to negative operating margins, which hinders investment in new manufacturing tools and product lines.

The authors of the EPRI report note: “It is financially difficult to sustainably grow manufacturing capacity of existing products, let alone a more innovative concept such as bifacial PV modules. This issue is exacerbated by the more expensive manufacturing tooling and processes required to produce bifacial modules today. The high capital expense and low returns on cell and module production is a bottleneck for adoption by manufacturers.”

Module nameplate power rating. Today, STC ratings for bifacial modules are based on front-side performance only, which obviously fails to capture the effects of bifaciality. To reflect the fact that bifacial electrical properties vary in proportion to back-side irradiance, manufacturers will also provide some version of Table 3, detailing performance characteristics at different levels of bifacial gain. The manufacturers leave it to the designer to decide how to apply these data. Since back-side irradiance has no impact on open-circuit voltage and has a negligible impact on voltage at maximum power, the real design consideration is the potential for higher currents.

Industry stakeholders around the world are actively developing a consensus on standard testing procedures for rating bifacial PV modules that the International Electrotechnical Commission (IEC) will eventually publish as IEC 60904-1-2. Researchers at the National Renewable Energy Laboratory (NREL), for example, have proposed flash-testing both sides of bifacial PV modules and using these flash test data to derive a compensated short-circuit current value. Additional indoor and outdoor testing is under way at NREL and Sandia to determine the accuracy of this approach.

Production modeling. Perhaps more important, the industry needs bankable methodologies for modeling bifacial system energy production in the field, a requirement complicated by the fact that field conditions have an inordinate impact on bifacial system performance. Performance models need to account for rear-side shade effects associated with mounting structures and adjacent rows of modules, which will vary considerably both over the course of a day and from one application to the next. Ground-surface albedo is another consideration. This can change seasonally, when snow covers grass or dirt, or over time, due to soiling effects. The albedo for a white roof membrane, for example, might be 80% when the membrane is newly installed but only 50% after it has spent a few years in the field. Research also indicates that rear-side irradiance is also nonuniform, meaning that it varies across the back of the array.

Because of all these factors, field test results are essential for developing and verifying the accuracy of bifacial performance models. Unfortunately, many laboratory test beds consist of only a few rows of modules, which are often spaced out to minimize self-shading. These results tend to overestimate performance in larger systems, especially in applications where rows are more tightly packed together. This creates a chicken-and-egg scenario. To optimize design variables, such as ground-cover or dc-to-ac ratios, you need a sophisticated production-modeling tool. But to develop an accurate production-modeling tool, you need field data—and the more of it, the better.


David Brearley / SolarPro / Ashland, OR /


Cuevas, Andrés, “The Early History of Bifacial Solar Cells,” 20th European Photovoltaic Solar Energy Conference (EU PVSEC) Proceedings, 2005

Electric Power Research Institute (EPRI), Bifacial Solar Photovoltaic Modules, September 2016

Lave, Matthew, et al., “Performance Results for the Prism Solar Installation at the New Mexico Regional Test Center: Field Data from February 15 to August 15, 2016,” Sandia National Laboratories, SAND2016-9253

SolarWorld, “How to Maximize Energy Yield with Bifacial Technology,” white paper, 2016


LG / 855.854.7652 /

Lumos Solar / 877.301.3582 /

Mission Solar Energy / 210.531.8600 /

Opsun Systems / 581.981.9996 /

Prism Solar Technologies / 845.883.4200 /

Silfab Solar / 905.255.2501 /

SolarWorld USA / 503.844.3400 /

Sunpreme / 866.245.1110 /

Yingli Solar / 86.312.8929.800 /

Primary Category: 

Solar carports and canopies have proven to be a successful and marketable approach to PV system siting and deployment. In addition to generating power, these structures add significant value to frequently underutilized parking areas, providing shade during the sunny months and protection from precipitation during the wet ones. This article provides system designers, engineers, and procurement and sales teams with overviews of 17 companies that offer solar carports, canopies or awnings in their product and service portfolios.

Many of the companies profiled have long business histories working with steel structures. As the solar industry gained momentum and entered new geographical markets, these vendors optimized their designs to integrate with PV arrays. As evidenced by the substantial number of companies profiled, a competitive market has developed for solar carports and canopies, driving the designers and fabricators of these structures to advance their designs. Today, project developers, integrators and EPC firms have an impressive range of solutions in this product class with a high level of optimization and refinement.

Absolute Steel

Headquarters: Tempe, Arizona
Contact: • 877.833.3237

Arizona Storage, a privately owned company that also does business under the Absolute Steel brand name, was founded in 1999. At its production facilities on company-owned properties in Arizona and Texas, Absolute Steel fabricates a selection of steel-frame solar-ready carport systems that range from small canopies with two parking spaces to large carport designs suitable for commercial applications. Its showroom in the metropolitan Phoenix area displays its steel buildings, carport systems, barns and storage sheds. Absolute Steel supports customers with site evaluation, structural engineering, on-site management and training, and domestic and international shipping services.

Baja Construction 

Headquarters: Martinez, California
Contact: • 800.366.9600

In operation since 1981, Baja Construction is a privately owned and vertically integrated design and construction firm with an in-house engineering department as well as its own construction crews. The company specializes in prefabricated, pre-engineered, high-tensile light-gauge steel structures that include solar carports, ground mounts and electric vehicle charging stations, as well as nonsolar carports, and RV, boat and self-storage facilities. Its engineering services and custom designs enable Baja to develop structures that meet site-specific wind load, snow load and geotechnical requirements. The company operates regional offices in Fontina, California; Dallas; Holbrook, New York; Las Vegas; and Phoenix.

Baja’s product line includes four standard configurations. Designed to cover a single row of parking spaces, its Braced Single Post carport includes flat, upslope and downslope options. Full Cantilever offers the same slope configurations, with the carport posts located along one of the structure’s eves. Full Cantilever T covers two rows of parking spaces, with posts located along the structure’s centerline between rows, and is available in flat and sloped array options. Finally, Single Post Back to Back couples two single-post configurations installed adjacent to each other to create a common flat or sloped array surface that covers two rows of parking spaces. All four of these configurations allow for customer-specified design requirements such as eve height, array tilt angle and purlin spacing based on module dimensions, and facilitate both portrait and landscape module layouts.

Carport Structures

Headquarters: Oxford, Michigan
Contact: • 800.442.4435

Carport Structures has been providing covered parking solutions and structural steel canopy products for commercial applications for more than 40 years. The privately owned and operated fabrication and construction company specializes in the design, manufacturing and installation of structural steel products such as multi-housing carports, walkway canopies and covers, shade structures, park shelters and RV carports.

In recent years it has developed solutions for commercial and utility PV applications, offering a range of services that include project quoting and presentation, site analysis, regional building code review and analysis, structural design, foundation design and layout, project management, foundation excavation and construction, steel structure erection and field fabrication, field painting, and PV racking and module installation. In addition to creating custom designs, it offers 11 standard carport products including single-column cantilever configurations, two-column configurations and louvered configurations that set each individual module row at a customer-specified tilt angle. All carport solutions are available for single-, double- and multiple-lane elevated structures.

Envision Solar International

Headquarters: San Diego
Contact: • 866.746.0514

Envision Solar International is a San Diego–based technology company with solar solutions for electric vehicle charging, media and branding, and energy security systems. Founded in 2006, the company went public in 2010 (ticker: EVSI). Envision Solar offers two specialty solar canopy lines: the EV ARC and the Solar Tree. Designed for stand-alone PV-powered electric vehicle charging, the EV ARC line includes several models, such as the EV ARC 3, which has a 3.4 kW canopy-mounted array coupled with 22.5 kWh of energy storage, and the EV ARC 4, which has a 4.1 kW array and 30 kWh of energy storage. Both models are equipped with dc chargers for plug-and-play electric vehicle charging. The EV ARC Digital model combines the EV ARC 4 with an outdoor-rated screen for advertising and branding. In addition, Envision Solar developed the EV ARC Bike/Moto, for electric bike and motorcycle charging. Like the EV ARC products, the Solar Tree line handles stand-alone power generation and vehicle charging. The Solar Tree DCFC (DC Fast Charger) is a compelling option for sites where customers desire fast dc charging for electric vehicles but utility power is not present or is expensive to access.

Florian Solar

Headquarters: Georgetown, South Carolina
Contact: • 800.356.7426

Florian Solar is a designer and manufacturer of integrated solar structures including sunrooms, greenhouses, canopies, awnings, skylights, and residential and small-scale commercial carports. The third-generation privately owned company was founded in 1947. It partnered with Sanyo, an early manufacturer of glass-on-glass bifacial modules, to develop its first line of solar structures in 2007. Florian’s product line features designs with a high level of aesthetic appeal that fill a niche market in the solar industry; for example, its sunroom and awning systems can completely conceal module interconnect and homerun conductors. While Florian can integrate most module types into its integrated structures based on customer preference, it frequently utilizes bifacial modules from Prism Solar Technologies and Sunpreme. Its structural designs do not shade the back side of installed modules, enabling the back-side generation potential of these products to be harnessed.

Lumos Solar

Headquarters: Boulder, Colorado
Contact: • 303.449.2394

Established in 2006, Lumos Solar is a privately held company that designs and manufactures two lines of frameless, glass-on-glass modules, as well as integrated rail systems and wireways that conceal conductors, protecting them from damage while improving the visual aesthetics of the array in the built environment. Integrators commonly deploy Lumos systems in solar awning, canopy and carport systems. The Lumos in-house design and engineering team assists customers with conceptual renderings, PE wet-stamped engineering drawings and packages to streamline project permitting.

Lumos Solar developed the LSX and GSX module and rail systems for integration with elevated solar structures, both of which integrate with most third-party solar carport and canopy structural array support systems. The LSX system includes frameless, glass-on-glass 60-cell modules rated at 265 W, 270 W and 275 W at standard test conditions. These modules integrate with the LSX Rail 1.1 system, which includes an integrated wireway. The recently launched GSX Bifi system uses 60-cell bifacial GSX modules rated at 300 W STC for front-side power production and a combined front-side and back-side rating of 330 W per IEC bifacial measurement standard (IEC 60904-1-2 TS). Its mounting and racking system conceals the module junction box and creates a waterproof array surface.

M Bar C Construction

Headquarters: San Marcos, California
Contact: • 760.744.4131

MBar C Construction is a family-owned and -operated manufacturing and construction firm. The company was founded as M Bar C Carports in 1975 and began developing and installing carports for solar applications in 1997. In 2005, it reestablished itself as M Bar C Construction. The company specializes in both light- and heavy-gauge steel prefabricated and custom parking lot and structure canopies for large-scale projects. It incorporates elevated steel structure design, manufacturing and installation, as well as commercial and industrial electrical services through its M Bar C Electric division. In addition to manufacturing structural steel elements for carports and canopies, M Bar C Construction has developed the SOLAR F.I.T. (Fast Install Track) SYSTEM, which uses a channel system rather than top-mount clamps to secure modules to a substructure. This approach allows installers to mount modules from below and eliminates some of the OSHA safety concerns associated with typical top-mount systems. M Bar C Construction primarily serves the Western US, including Arizona, California, Colorado, Hawaii, Nevada and Oregon. Approximately 90% of its installations are design-and-build projects.

Orion Solar Racking

Headquarters: Commerce, California
Contact: • 310.409.4616

Founded in 2009, the privately owned Orion Solar Racking develops and manufactures solar-mounting solutions for residential, commercial, industrial, agricultural and utility-scale projects. Orion Solar offers three standard product models for carport systems: KRONOS, LETO and TITAN. The KRONOS model is primarily intended for single-parking-space residential systems and is available with clearance heights from 8 feet, 5 inches, to 11 feet, 5 inches. Custom colors are available. Its galvanized steel, curved single-post design supports six or eight modules in portrait orientation at tilt angles of 0°, 5° or 10°. The LETO carport system is a steel double-column single-cantilever carport designed to span two parking spots for a total of 18 feet. Intended for commercial applications, LETO structures allow side-by-side installation to shade larger areas. The system’s columns and beams are available with galvanized or primed finishes. Orion Solar’s TITAN carport system is a double-column, double-cantilever tee-style carport designed to cover four parking spots in a two-by-two parking configuration. The LETO and TITAN systems are available with an array tilt angle of 0°, 5° or 10° and feature purlins that allow slide-in module mounting. Options include area lighting under the canopy and electric vehicle charging stations. Orion Solar also offers custom-designed solar carport solutions.

Quest Renewables

Headquarters: Atlanta
Contact: • 404.536.5787

Quest Renewables is a privately owned company launched in 2014 to commercialize solar racking products developed by the Georgia Tech Research Institute under the US Department of Energy’s SunShot Initiative. The company’s QuadPod Solar Canopy uses steel top and bottom chords connected with a series of tubular web struts to create 3-D trusses, which support elevated-structure solar arrays such as carports and canopies. This design can handle 60-foot spans between piers, 30-foot cantilevers and array capacities of 30 kW per pier.

The QuadPod’s modular design streamlines shipping costs and provides flexibility on-site. Installers assemble the truss components using bolted hardware, and they then secure and prewire modules on-site at ground level. They use a crane to lift the completed assemblies atop the piers’ tubular support columns. This pick-and-place approach minimizes overhead work and improves jobsite safety. Quest Renewables offers an east-west configuration of its QuadPod system that enables a 15% higher power density than south-facing QuadPod canopies provide and that allows integrators to optimize inverter capacities when sizing for east-west array production curves.

Powers Solar Frames

Headquarters: Phoenix
Contact: • 888.525.0180

Powers Solar Frames is a division of privately owned Powers Steel and Wire, a manufacturer of steel structures, lintels, masonry products, rebar and solar racking systems. The solar product line includes driven-pile and ballasted racking systems for commercial, industrial and utility-scale projects, as well as solar carport frames. Powers Solar Frames’ carports use galvanized structural elements (columns, rafters and purlins) that do not require on-site painting. In addition, all structural members have bolted connections that eliminate field welding and weld inspections.

Power Solar Frames offers two carport designs, its semi-cantilever box-beam model and its tee box-beam model. Both systems use 10-gauge 16-inch-by-8-inch galvanized structural members for the carport’s columns and rafters. The tee box-beam model’s rafter can span up to 39 feet. Both carport models permit modification for tilt angle, clearance height and site-specific requirements such as snow load, wind load, and geotechnical and seismic requirements. Power Solar Frames’ carport structures feature its patented steel Super Purlin. The purlin’s profile creates a channel that allows installers to slide in modules from the carport system’s gable ends. This approach eliminates top-down module-mounting hardware and fall hazards associated with working above the array plane. Each module requires four UL 2703–certified gator clamps that install from the underside of the array to secure the module to the adjacent purlin.

RBI Solar

Headquarters: Cincinnati
Contact: • 513.242.2051

RBI Solar designs, engineers, manufactures and installs solar mounting systems for commercial and utility-scale solar projects. The privately owned company operates US offices in Atlanta; Temecula, California; and Washington, North Carolina. It completed two notable acquisitions in 2014, including PV carport manufacturer and installer ProtekPark Solar, and Renusol GmbH and its subsidiary, Renusol America. RBI Solar’s services include design, engineering drawings for all 50 states, project management and nationwide installation.

RBI Solar offers pre-engineered solar carport structures, including single-slope, gable, inverted and full-coverage designs. It typically utilizes the two-slope gable configuration for north-south orientation with panels sloping 5° on the east and west array faces. This inverted design provides increased clearance at the structure’s eaves while promoting water and snow movement toward the center column row of the structure. RBI Solar also offers a full-coverage design suitable for protecting large parking areas, including the drive aisles between parking rows. Typical applications for the full-coverage carport configuration are parking garages, drive-throughs, and bus or truck loading and unloading zones. RBI Solar carport systems do not require field welding, drilling or other on-site fabrication. The company offers customized designs as well as numerous options including galvanized and epoxy-coated finishes.


Headquarters: Shelby, North Carolina
Contact: • 888.608.0234

Schletter GmbH has a 40-year history in the design and manufacture of steel and aluminum products. The privately owned company founded its US subsidiary in 2008 with the launch of a sales and manufacturing facility in Tucson, Arizona. Its solar product portfolio includes mounting structures for carports, roofs and ground-mounted PV applications in the utility, commercial, industrial and residential markets.

Schletter’s Park@Sol carport line includes three standard configurations that accommodate single and double rows of parking. Its carport structures do not require on-site welding or cutting. Multiple foundation options are available, such as cast-in-place concrete ballasts, concrete pillars and micropiles. The micropile foundation, which allows a streamlined foundation design, uses a hollow metal rod that the construction team installs to an engineered depth to minimize concrete requirements while meeting high wind- and snow-load requirements. Schletter has an in-house staff of engineers and geotechnicians to assist with site-specific carport system engineering. It offers multiple options for its Park@Sol structures, including cable management, subdecking, inverter mounts, custom designs and color options, and branding solutions.


US Headquarters: Denver
Contact: • 303.522.3974

With its global headquarters in Hamburg, Germany, privately owned S:FLEX GmbH was founded in 2009. S:FLEX’s product lineup includes solutions for pitched and low-slope rooftops, ground-mounted systems and solar carport applications. Its standard carport products include full cantilever, partial cantilever, and tee upslope and downslope configurations, as well as an inverted configuration that channels precipitation runoff to the structure’s center. S:FLEX carport systems provide several module-row configuration options and are compatible with both framed and frameless modules mounted in portrait or landscape orientation. Standard array tilt angles of up to 15° are available

While S:FLEX engineers its column spacing and spans based on site-specific wind, snow and seismic load requirements, designs typically space columns at 27 feet on center and place them between every three parking bays, creating individual parking spaces that are 9 feet wide. Its carports are compatible with multiple foundation types, including spread footings and foundations with embedded helical piers. Carport options include integrated electrical grounding and industrial painting of steel structural components. S:FLEX supports carport projects with project-specific design and engineering, as well as installation support.

Skyline Solar

Headquarters: Gilbert, Arizona
Contact: • 480.926.0122

Skyline Solar is a division of Gilbert, Arizona–based Skyline Steel. Founded in 1983, Skyline Steel designs, manufactures and installs commercial covered parking structures. It recognized the added value that solar offered many of its carport customers and entered the solar industry in 2002, establishing Skyline Solar in 2009.

Skyline Solar offers products for solar applications including carports; large-area canopies for parking garages; bus and truck parking; RV, boat and self-storage facilities; electric vehicle charging stations; and commercial and utility-scale low-slope–roof and ground-mount structures. A design-build firm, Skyline Solar typically provides products and services to integrators, developers and EPC firms that are responsible for the installation and commissioning of solar power systems. Its services include project estimating and management, conceptual project renderings, structural plan sets and certifications in all 50 states, foundations, steel construction and erection, and PV module installation.

Skyline Solar offers a wide range of standard solar carport and canopy models as well as custom designs. Its prefabricated one-column SkyTree shade structure, supporting array capacities of up to 18 kW at a tilt angle of 5° or 10°, is well suited for small covered-parking installations. For large-scale projects, Skyline Solar offers single- and double-cantilever tee designs that support modules at tilt angles of 5°, 10° or 15° in portrait or landscape orientation. Its dual- and multiple-post solar canopies are intended for large parking areas, garage tops, school playgrounds and bus parking lots, and they allow module-mounting options including flat canopy, 5° canopy or louvered module installations at tilt angles of 5°, 10° or 15°. Skyline Solar also offers fastener solutions such as its SkyBite clip (ETL certified to UL 467), which permits installers to secure and electrically bond modules to the carport or canopy structure’s purlins from underneath the array.

Solar Carports

Headquarters: Sarasota, Florida
Contact: • 941.702.2342

With manufacturing facilities in California and Virginia, Solar Carports specializes in the design and installation of structural canopies to support solar power systems. It offers several pre-engineered designs as well as custom carport and canopy designs. Standard models include partial cantilever, full cantilever and tee upslope and downslope configurations, as well as inverted configurations. Options include galvanized and painted finishes, watertight canopies, gutters, downspouts, and LED canopy under lighting. Solar Carports’ affiliate, Sarasota-headquartered Region Solar, provides full EPC and project management services for installations deploying Solar Carport’s structures.

Structural Solar

Headquarters: Chicago
Contact: • 708.275.9030

Structural Solar provides solar carport and canopy design-build and contract manufacturing services to solar developers, integrators and EPCs based on site-specific and project-specific requirements. Its services range from solar structure design and engineering to fully manufactured and installed structural systems in locations nationwide, including Hawaii and Puerto Rico. In addition to providing carport and canopy designs, Structural Solar offers waterproof structures for frameless glass-on-glass bifacial PV module installations.


Headquarters: San Jose, California
Contact: • 800.786.7693

Publicly held SunPower designs, manufactures and deploys high-efficiency PV modules and systems worldwide for residential, commercial and utility-scale projects. Founded in 1985, SunPower announced its initial public stock offering in 2005 (ticker: SPWR). In 2015, SunPower acquired Solaire Generation, a well-established solar carport and canopy design, fabrication and installation firm founded in 2008.

Solaire by SunPower’s product line includes patented solutions for large-scale parking lot and garage-top applications. Its carport configurations include single-column, single-cantilever and double-cantilever tee designs on a single incline; dual-incline inverted designs; and dual-column long-span designs. For example, its Long Span 360 product covers two parallel parking rows and an internal drive aisle with one contiguous PV-covered canopy that has an array inclination angle of 1°–10°. Another example is its 360 D model, which has a dual-incline configuration that safely directs snow and ice to the center of the structure. It features a standard minimum drive aisle clearance of 13 feet, 6 inches, and is available in widths of 34 feet to 41 feet, column-to-column spacing of 18 feet to 32 feet and inclination angles of 1° to 15°.

In 2015, SunPower launched its highly integrated Helix PV system platform for commercial and industrial low-slope rooftop, carport and tracked PV systems. The system is standardized but configurable. It incorporates five major value-engineered component groups: modules, mounting hardware, cable management, power stations and energy analytics. Several configurations of the Helix Carport Structure are available, and all feature the Helix platform’s integrated approach. Components and features include high-efficiency SunPower panels, a mechanical mounting and electrical system, a column-mounted plug-and-play inverter power station, SunPower EnergyLink Monitoring hardware and software, and LED lighting. Design options include painted columns and beams, snow guards, and decking and branding solutions.

Primary Category: 

[Boulder, CO] Lumos Solar has announced its new module system, which combines bifacial cells and frameless glass-on-glass module construction with an integrated weatherproof mounting system that completely conceals junction boxes and conductors. The tamper-resistant mounting approach locates the GSX module junction boxes and whips within the racking system’s mullions. Module front-side maximum power electrical specifications are 275 W STC, 8.88 Imp and 31.8 Vmp. The 60-cell modules have a 12-year power-output warranty at 90% and a 25-year power-output warranty at 80%.

Lumos Solar / 877.301.3582 /

Primary Category: 

How much revenue is a soiled PV array losing, and at what point does it make sense to wash the array?

Owners, developers, bankers and O&M providers all want to know when it makes sense to clean a PV array to recapture revenue that it would otherwise lose due to soiled modules. On the one hand, an overly soiled array represents a loss of money. On the other, a premature cleaning represents a waste of money. While you must consider many variables to reach a definitive washing decision, the economics of module washing are not complex: If having a clean array saves more money than it costs to wash the array, then washing it probably makes sense.

This article shares some of our analyses and observations on array soiling drawn from many years of operational experience. We have had successes and failures, which have led to interesting discoveries and some dead ends. We have based most of our research on utility-scale PV plants with high dc-to-ac ratios in sunny, arid locations. These plants are subject to a unique set of circumstances: They spend a lot of time at full power, have relatively steady soiling rates and are rarely exposed to enough rain to significantly clean the modules.

Energy Recapture

It is difficult to assess soiling and to determine when to wash an array because doing so requires a multi-variable equation. Every analysis is unique, based on a host of project-specific mitigating factors such as technology choices, racking configuration, inverter loading, PPA rates, time-of-day profiles, interconnection agreements and so forth. This means that there is no single right answer when it comes to the economics of washing. The methods for soiling analysis are as varied as the business model behind the PV plant, so each solution uses a unique combination of people, tools and number crunching. What all effective soiling analyses have in common, however, is that they distinguish between percent soiling and percent energy loss due to soiling. While the former is easier to quantify, it may not correlate to unrealized revenue.

For the purposes of this article, we define percent soiling as the reduction of expected output power between soiled dc source circuits (modules, strings, arrays) compared to the same source circuits under clean conditions. In field terms, percent soiling describes the ratio of dirty to clean IV-curve traces, extrapolated to nameplate power under standard test conditions (STC). Meanwhile, we define percent energy loss due to soiling as the difference between the metered energy for a given time period compared to the energy that could have been harvested over the same time period with a fully clean array. This term describes the energy that is available for recapture, which correlates directly to unrealized revenue. To differentiate between these two concepts, we need to quantify the amount of time that a PV power plant spends at or near full power.

Power limiting in PV arrays. It is common practice to deploy PV systems with a high array-to-inverter power ratio in an attempt to capture more energy and revenue. As a result of these high dc-to-ac loading ratios, many inverters spend a lot of time operating at full power, which forces the array off its maximum power point.

Extended periods of power limiting result in a characteristic flat-topped power curve, which people commonly refer to as power clipping. The more time a PV system operates at full power, the less concern is warranted over soiling. Soiling abatement is effective only if you can recapture the lost energy, which requires unused inverter capacity. The returns are diminished in PV systems with chronically clipped power profiles, because an inverter operating at full power cannot increase its output power based on an incremental increase in irradiance. If soiling is viewed as an effective reduction in plane-of-array (POA) irradiance, then a 5% increase in irradiance can overcome a 5% soiling level. For example, if a given inverter hits maximum output at a POA irradiance of 800 W/m2 under clean array conditions, then it follows that power clipping will start at 840 W/m2 in the 5% soiled case. Above 840 W/m2, the percent soiling literally becomes a moot point.

Figure 1 illustrates this point by comparing seasonal POA irradiance and plant production curves for the same PV system. The flat-topped curves on the left, labeled “Day 1 (August),” illustrate how the plant operates at full power for extended periods of time under high POA irradiance typical of summer. The curves on the right, labeled “Day 2 (November),” illustrate how the array operates below full power all day long under partially overcast conditions in the autumn. To compare the percent energy loss due to soiling for Day 1 versus Day 2, we first have to filter out the time spent at full power, as no energy is available for recapture during these hours.

Table 1 presents these filtered results. Compared to baseline values for a clean array, the percent soiling is roughly the same on Day 1 and Day 2 (3.7% versus 3.6%). However, we can recapture energy only during hours when the PV plant is not power limiting. This leads to a slightly counterintuitive result: Even though the incident energy on Day 1 is nearly twice that on Day 2 (10.4 kWh/m2 versus 5.3 kWh/m2), the percent energy lost and the net energy lost due to soiling are greater on Day 2. This means that Day 2 presents the better opportunity for revenue recapture via washing, even though the available solar resource value is lower.

The challenge associated with soiling assessment is that we need to extrapolate this analysis to the near operational future for a PV power plant. The estimate concerning the future mix of clear, cloudy or overcast days is what determines the economics of module washing. A host of models and methods are available to predict and back-calculate the energy available for recapture, including hourly energy models, exceedance probability calculations and regression analyses. Regardless of the methodology used, you must account for inverter power limiting and have an accurate estimate of percent soiling.

Direct Soiling Measurements

The best way to estimate percent soiling is to measure it directly: Test the array, wash it, and test it again. While the process is time-consuming, there is no disputing the results. Soiling sensors and IV-curve tracers are proven tools for getting an accurate answer to the question “How dirty are my modules?” It is also possible to use other devices, such as short-circuit testers, to get a general estimate of soiling levels. Just keep in mind that additional data analysis and filtering is required to extrapolate from percent soiling to percent energy loss due to soiling.

Soiling sensors. Soiling sensors are essentially stand-alone evaluation tools that compare the actual output of a naturally soiled PV reference module to the expected output of a clean PV reference device. Some soiling sensors use short-circuit current (Isc) as the basis of comparison; others incorporate a microinverter and compare maximum power point values (Vmp, Imp, Pmp); some devices use a hybrid technique that compensates for temperature and normalizes results to STC. All of these approaches yield a high-quality data stream that you can easily use to assess the soiling level of the modules in the test rig.

IV-curve tracers. To get the best possible in situ soiling measurements, put a good IV-curve tracer in the hands of a competent technician. Curve tracing is slow but definitive. You can compare PV source-circuit curve traces to STC or use a dirty versus clean approach. As long as technicians capture a representative set of IV-curve traces under roughly the same conditions, the results of the study will be accurate and useful. While it is quick and easy to analyze these IV-curve data, it is incumbent on the technicians to choose representative strings to test in the field.

Other devices. Another option that works well is to use instruments that measure short-circuit current or operating current, or that can extrapolate measured data to a baseline condition—such as PVUSA Test Conditions (PTC) or STC—to estimate percent soiling. Since these devices are not explicitly intended to perform soiling measurements, the correlation process is left to you. However, the process does not need to be complex. A simple multimeter with a current loop sensor is sufficient to get a general idea of soiling conditions. If necessary, you can assess soiling with a Fluke meter, a few gallons of water and a squeegee.


Soiling stations, IV-curve traces and other assessments that compare “before” (dirty) and “after” (clean) conditions give an excellent indication of the soiling conditions on a specific set of modules or test array. The trick is to take data from these devices and extrapolate it twice: once to generalize the entire plant’s soiling condition, and once more to infer how much the measured soiling will affect energy production or performance. We call this the soiling transfer function. Direct soiling measurement is a great start, but it is a rare instance where the estimated percent soiling value will reflect an equal (or even proportional) percent decrease in production. As illustrated in Table 1, percent soiling does not correlate directly to energy lost due to soiling when PV plants spend a lot of time operating at maximum power.

To complete the soiling transfer function from percent soiling to percent energy loss due to soiling, you need to filter the operational data strategically. The data filtering process can be as simple as removing power clipping points, which has the effect of constraining the evaluation to periods of MPPT operation. You can also apply additional filters to remove spurious data points that may muddy the results, such as measurements associated with low POA irradiance, unstable irradiance or excessive wind speeds. Once you have obtained field measurements and filtered the operational data, you just need something with which to compare these to estimate percent energy loss due to soiling.


The best way to estimate the impact of soiling is to compare operational data to plant performance under clean conditions, which we refer to as the plant baseline. Obtaining a performance baseline is a process of characterizing the electrical performance of source circuits, combiners, inverters or an entire plant and isolating these data for frequent comparison. The goal of establishing a baseline is to understand how the system or subsystem performs under known operating conditions when the array is free of faults and unsoiled. Generally speaking, a rough plant baseline is good enough.

Establishing a clean plant baseline is more of a process than an event. The logical opportunity to obtain a baseline for an entire plant is at the time of initial back-feed, testing and commissioning. If you want to get two detailed answers at once, you can perform a full-plant baseline characterization in parallel with performance testing, which is ideal. However, you can establish a baseline at any system level, over any duration of time and under any operating conditions. Nothing is lost if you are unable to characterize some parts and pieces at commissioning. You can always revisit and recalibrate these parts later and make sure that they fit the general performance trend once they are up and running. As long as you restore malfunctioning blocks to operation and characterize their performance using the same measurement methods, the baseline will be accurate and useful despite its piecemeal assembly.

There are various means of applying the baseline. The simplest form—comparing dirty versus clean performance—is effective for both long- and short-term analyses. By characterizing the plant according to its big pieces, such as inverters, skids or ac collection circuits, you can compare these results to one another, normalize dirty results against the clean baseline and make informed decisions about soil abatement. You can express the baseline in whatever terms best suit your goals, such as specific yield (kWh/kW) or energy output in relation to POA irradiance. The latter is useful if you need to tie actual performance back to expected performance based on an energy model.

Since assumptions, data resolution and as-built conditions constrain energy models, we strongly recommend that you use operational data rather than modeled plant behavior as the basis of comparison. Whereas an energy model describes how the plant is supposed to behave, measured data describe how the plant actually behaves. In broad terms, energy modeling software applies soiling assumptions as an effective monthly reduction in POA irradiance and essentially stops there. One-month averages for soiling levels can shore up production and revenue models, but they have little to say about soiling events, differential energy impacts or soiling rates in general. As a result, the input/output resolution for an energy model is far less precise than it is for most operational datasets.


End use and accuracy drive the baseline characterization method. Production losses can be very subtle, typically only a few percentage points, before they become noticeable, so accuracy is vitally important to tying production losses specifically to soiling.

The simplest characterization method is to catalog plant production at the meter as well as measured irradiance in the plane of array. Since this obviously ignores thermal differences within the array, for increased accuracy you may need to apply a temperature compensation to account for deviations from weather station conditions. You also need to remove or ignore performance issues that are not related to soiling, such as module degradation, equipment failures and configuration differences. Soiling analysis has to quantify or transcend these factors to reach a reasonable conclusion.

To illustrate the challenge: A POA irradiance sensor might have an accuracy of ±1.0%; ac power measurement transducers are typically accurate within ±0.2%; dc transducers are rarely better than ±1.0% accurate; secondary measurements, such as temperature and wind speed, have ±2% accuracies at best. These measurement errors typically compound rather than cancel one other. Compounded, these uncertainties suggest that isolating a few percentage points of performance loss using gear with measurement errors of a few percent can produce dubious results.

The net result is that a thorough soiling analysis could very well estimate that modules are 4.5% soiled, plus or minus 2%. Given these uncertainties, module washing may or may not be cost effective. While no one likes this type of answer, it is often the case that soiling analysis results have a high degree of uncertainty.

Practical Application

We recommend a relatively simple five-step approach for isolating the effects of soiling on energy production based on measured data from operating PV plants. The methodology uses a comparison to a baseline as a means of assessing the production that the array might have achieved if it had been completely clean and operating perfectly. The specific implementation of this methodology depends on plant type, capacity and the monitoring solution. However, you can apply this method at almost any plant level using similar techniques.

Step 1: Catalog all IV-curve traces and other string-level commissioning tests to establish source-circuit behavior with respect to nameplate power. This step provides a consistent reference dataset that you can revisit when using periodic string testing for performance assessments.

Step 2: When commissioning the array and conducting energy performance tests, establish plant-level and inverter-level baselines using high-resolution data. These baselines should isolate trend data for clipping and nonclipping production as a function of POA irradiance and should be normalized to dc capacity by inverter. You can complete this step in pieces, if need be, updating the baselines as more datasets become available. The key is to characterize a clean, fully operational plant.

Step 3: Track plant performance using trend data from the time of (clean) commissioning through operations. Using the same filters employed to establish the baseline, determine approximate soiling levels while the plant operates (as time, data and weather allow). 

Step 4: If you suspect excessive soiling, perform a series of string-level field measurements before and after washing, and compare these results to the commissioning data. Next, compare these measured results to the soiling estimates generated from trend data with the appropriate clipping filters applied. Establish the correlation between the measured and modeled results for future use.

Step 5: When field measurements and data analysis align—and when the comparison to baseline indicates that energy recapture will be cost effective—then it is time to schedule a wash. Over time, take advantage of these full-array washing opportunities to recalibrate the baseline, the energy model and so forth.


The following examples illustrate how you can use baseline comparisons to isolate soiling conditions. We have taken all examples from utility-scale plants with multiple central inverters in sunny, arid locations. We have summarized and annotated each case to show how you can apply the same methodology at various scales.

Plant level. Figure 2 shows an example of a long-duration soiling analysis. We cataloged these data over an 8-month period, and they capture a few isolated rain events as well as a complete array cleaning. We have filtered the datasets from each for clipping and reported them as percent of baseline. Although these daily values have quite a bit of variance and error, the soiling accumulation trend is undeniable. While the rain events mitigated soiling only marginally, the wash effectively rehabilitated the arrays to full potential. 

With any macro-level assessment, especially on larger plants, you must level out or ignore some asymmetries and performance issues with strategic math. The end result is an accurate model of how the plant turns photons at the modules into energy at the meter. You can parse this type of baseline into subsections, perhaps by combiner, inverter, skid or ac collection circuit. Regardless of the scale, the concept is the same and provides an adequate assessment of performance in an ongoing manner. You can employ and repeat this dirty versus clean comparison to baseline under any circumstance and recalibrate the whole process after a full array cleaning.

Inverter level. Inverter-level assessments are a subset of whole-plant characterization but with higher data resolution. The key to this level of analysis is to establish a unique baseline for each inverter under clean and fully operational conditions. Inverter-level comparisons are useful for identifying the impacts of differential soiling across the whole plant.

For example, Table 2 compares inverter-level data, reported as “percent inverter-specific energy compared to baseline,” for a large-scale PV plant with differential soiling. Most, but not all, of the arrays at this site are subject to rapid soiling from an adjacent road and farm field. By tracking inverter-level data, we can isolate soiling by location or overall contribution to lost energy. In this particular case, the soiling was profound enough to trigger a full wash cycle. If the differential soiling analysis had indicated that soiling affected less of the plant overall, we could have focused our maintenance activities more selectively, perhaps electing to wash only arrays associated with specific inverters.

Combiner level. We can further increase data granularity and resolution by evaluating dc input current at the subarray level, which effectively facilitates combiner-level assessments. While this approach makes it easy to diagnose the effects of differential soiling on an individual inverter, the real beauty of combiner analysis is that it provides a built-in method of validation. If all of the subarray inputs are showing the same thing, as in Figure 3, our confidence in soiling assessments improves. The increased granularity also makes it easier to track incremental changes from the baseline.

String level. Because it provides the highest-resolution data possible, string-level analysis is the alpha and the omega—the first step and the final step—of an effective performance assessment. Since most large-scale PV systems do not have string-level monitoring, cataloging source-circuit performance generally requires field tests. Though string-level testing demands high-quality tools and competent technicians, the data produced are effective for establishing a baseline or calibrating the energy metrics and assumptions used at all other levels of analysis.

You can use these string-level data to calibrate independent soiling sensors. You can also apply string-level dirty versus clean results, such as those shown in Figure 4, to historical data or to a before-and-after cleaning analysis. In this figure, the raw trace data, based on in situ irradiance, are shown in green; the curves in red correct these field measurements to STC; the blue curves, meanwhile, show the ideal I-V curve for the source circuit at STC. These dirty versus clean traces provide a good indication of the energy available for recapture at the string level, which we can extrapolate to larger performance blocks.

An ideal use for field measurements is to calibrate soiling analyses in relation to operational data. This process involves comparing IV-curves to soiling station data and other soiling metrics. To the extent that we can draw correlations, we can triangulate these datasets and better inform our washing decisions. This process of continuous improvement is essential to effective soiling assessment.


Dust storms, intermittent construction activity, unusually heavy traffic and sporadic agricultural activity are examples of event-based soiling. When soiling gets very bad—or when it gets a lot worse in a hurry due to a soiling event—strange things start to happen in terms of plant behavior. Module soiling can reach a point where the fundamental electrical characteristics of the dc array change dramatically, so much so that it sometimes forces inverters out of maximum power point tracking. These results are most common in neglected PV plants where extreme soiling causes blocking diodes in the modules to engage, which can completely confuse the inverter.

Really bad soiling almost precludes analysis. The electrical behavior of a PV plant becomes less predictable and performance suffers, but it can be difficult to quantify how bad the problem is and how much energy the plant is losing. Such conditions combine significant energy shortfall with chaotic behavior. While we can measure the lost energy, we cannot directly discern the reasons for the loss. This complicates the process of troubleshooting any problems not related to soiling.

Soiling events are a constant source of panic. Everyone wants to know how bad the problem is, but making even a rough estimate takes at least a day. Rather than rushing to get a washing crew in place based on incomplete information, the best approach to soiling events is to send technicians to the site to assess the problem via dirty versus clean testing. These strategic test results will quickly provide the answers needed and frequently trigger a wash cycle.

Soiling events can also be localized, a situation we call asymmetrical soiling. This occurs when some arrays get a lot dirtier than others. Exterior arrays next to dirt roads or agricultural activity are the most common culprits. Differential soiling across the whole plant skews bulk numbers, especially when you take the soiling assessment measurements from a relatively clean or dirty array.

Since soil detection is intended to generalize soiling conditions, you cannot trust the numbers it yields when you are adapting a general model to an asymmetrical problem. We call this phenomenon forced mismatch, meaning that uneven soil deposition creates an imbalanced electrical condition. Here again, the best response is to send out a crew to assess the situation, and then back up the findings by comparing filtered operational data to a clean baseline. Asymmetrical soiling may make selective module washing a viable option.


The next case studies represent rigorous analyses using high-resolution data applied to fully operational plants that all ended up with dubious results. Some may call these war stories; we call them analytical head-scratchers. We present them here to illustrate the chaotic nature of soiling measurements and the unpredictability of the results.

Case 1. After measuring overall soiling of a PV plant at around 4%, the owner scheduled washing. Before the wash, a short-duration rain event occurred, so the owner asked us to investigate to see whether the rain had cleaned the modules enough to justify delaying the capital expense of a full wash. By our calculations, the rain event actually increased soiling to more than 5%, calling the entire chain of decisions, as well as our analytical approach, into question.

Case 2. In an attempt to quantify soiling, we conducted a series of before-and-after IV-curve traces across a plant. Our strategic plan called for washing selected strings of modules across a representative set of arrays on assorted inverters to quantify a measurable difference. The curve traces showed less than 1% soiling on some strings and more than 7% on others, with a relatively even distribution between these extremes. We recommended a full cleaning, and the net performance results after washing showed a similar distribution of results. However, the overall performance increase was only about 33% of the expected result, netting a 1.9% increase in production. We had a hard time trusting the results, the analysis approach and the wisdom of our recommendation to wash.

Case 3. Cleaners fully washed a plant at night to prevent production losses, which is a reasonable approach. The next morning, while the modules were still cool and wet, the farmer on the upwind side of the plant starting tilling fields, which spread a thick dust cloud onto an otherwise clean array. In this case, unforeseen farmwork forced another wash cycle.

These case studies illustrate that attempts to isolate the effects of soiling can be elusive. Soiling effects are design dependent; geographically varied; simultaneously localized and vastly different between arrays; dependent on geometry, orientation and array racking configuration; and variable based on the weather or off-site activities. In addition, rain does not necessarily clean modules very well, if at all. These factors are not necessarily bad news. Rather, they are limiting assumptions that you need to categorize, isolate, quantify and remove from the analysis to begin a valid assessment. Once you accept that soiling is a chaotic phenomenon, you can begin to see patterns and to learn from the more predictable parts of the problem.


Sanjay Shrestha / SOLV Performance Team / San Diego, CA /

Mat Taylor / SOLV Performance Team (retired) / San Diego, CA /

Primary Category: 

More than 600 solar equipment and service providers will display their products at the Solar Power International conference and expo in Las Vegas September 13–15. In this preview article, I highlight 17 companies that provide a wide range of solutions for system integrators. Some of the equipment detailed here recently launched or is set to launch at the event. Some is time-tested in fielded systems across the US. And some represents new or out-of-the-box ideas that may or may not take hold, but that nonetheless represent the dynamic innovation that keeps the solar industry moving forward.

Modeling, Measurement and Testing

Aurora Solar - Booth WSUA12

Aurora Solar develops cloud-based software that enables sophisticated solar project engineering design, provides workflow management functionality, and facilitates sales and customer acquisition for solar installers and financers. The company launched in 2013 with the backing of the US Department of Energy’s SunShot Initiative. The Aurora design platform includes features such as 2-D and 3-D modeling, 3-D visualizations, irradiance maps and annual shade values, automatic roof setbacks, electric bill and financial analysis, sales proposals and remote shading analysis, as well as engineering features such as performance simulations. Monthly and annual per seat pricing is available, as are enterprise-scale packages. The basic subscription is $159 per month, per seat, and includes the features listed. The premium-level product costs $259 per month, per seat, and offers additional features including monthly shade values, site modeling with LIDAR, NEC validation, single-line diagrams, BOS components and detailed bills of materials.
Aurora Solar /

Curb - Booth W902

Launched in 2012, Curb is a new entrant to the solar and energy efficiency market. Its home energy monitoring system offers integrators a compelling option for circuit-by-circuit energy use monitoring and visualization at a low price point ($399). Curb designed its data acquisition system for mounting in a home’s load center. The system includes 18 CT sensors for individual circuit monitoring. This level of monitoring granularity facilitates specialized tasks—for example, determining how much energy electric vehicle charging is consuming. The Curb system can measure on-site energy generation from PV systems and integrate production values with home consumption data. Curb includes a variety of notifications for events, such as when a user has accidentally left on a given appliance. Additional features include a power budget manager that allows users to track progress against a monthly energy budget. The software identifies changes in consumption and provides suggestions for conserving energy and money. With the upcoming launch of its home energy intelligence product, Curb plans to take its platform a step further with functionality that aims to predict appliance failure and identify required maintenance for components such as HVAC or refrigerator compressors.
Curb / 844.629.2872 /

Folsom Labs - Booth 3053

At the core of San Francisco–based Folsom Labs’ design efforts is the principle that every PV system design decision can and should be quantified in terms of its yield and financial implications. To further this goal, Folsom Labs develops HelioScope, a PV system design tool that integrates system layout and performance modeling to simplify the process of engineering and selling solar projects. The platform integrates easy-to-use design tools and bankable energy yield calculations. A core differentiator for HelioScope is that it is designed on a component-based model, which separately models each piece of the system (individual module, conductor or inverter, for example). Folsom Labs offers both monthly and yearly subscription rates. The cost of a single-seat monthly subscription is $79 and includes automatic CAD export, energy simulation, shade optimization, one-click sharing, a component library of 45,000 items, global weather data and PAN file support. Solar professionals can use HelioScope to design and model PV plants with capacities of up to 5 MW.
Folsom Labs /

Seaward Solar - Booth W824

Seaward Solar is a division of the UK-based Seaward Group. Its line of PV test equipment is one of the more recent development efforts in the company’s 75-year history in electrical safety test measurement instruments. Seaward Solar’s offerings include products used in PV system commissioning and operation verification, such as conductor insulation testers, irradiance meters and I-V curve tracers. The company recently announced the launch of its new PV210 multipurpose PV tester, which combines installation and commissioning tests with the ability to perform I-V curve analysis. Simple push-button operation allows users to conduct all the electrical commissioning tests required by IEC 62446, including open-circuit voltage, short-circuit current, maximum power point voltage, current and power, and insulation resistance. In addition, the PV210 performs I-V curve measurements in accordance with IEC 61829 to determine whether the measured curve deviates from the expected profile. For full, detailed analysis, users can transfer measured data from the test instrument to an accompanying PVMobile Android app to create high-definition color displays of the I-V and power curves for individual PV modules or strings.
Seaward Solar / 813.886.2775 /


LG Solar - Booth 1447

LG’s activity in solar module development dates back to 1985, when it (under the brand GoldStar Electronics) conducted its initial multicrystalline PV cell R&D. Since then the South Korean company, part of the global LG Group, has rebranded and become a household name in appliances and personal electronics. Another LG Group subsidiary, LG Chem, is on the front lines of designing and manufacturing lithium-ion batteries for use in stationary solar-plus-storage systems. LG Solar initiated mass production of its PV technology in 2010. It recently announced the US availability of its NeON 2 72-cell module models, developed for commercial and utility-scale installations. The three models—LG365N2W-G4, LG370N2W-G4 and LG375N2W-G4—have rated power outputs ranging from 365 W to 375 W. The new models expand LG’s high-efficiency PV lineup, which includes the 60-cell NeON 2, with rated power outputs of 305 W–320 W and module efficiencies of 18.6%–19.5%.
LG Solar /

SolarWorld - Booth 911

SolarWorld has more than 40 years of history in solar module design and manufacturing, dating back to Bill Yerkes’ founding of Solar Technology International and ARCO Solar’s development efforts in the 1970s, the assets of which SolarWorld acquired. Today, SolarWorld offers a full line of Sunmodule products, including two glass-on-glass bifacial Bisun models, as well as system packages that incorporate Quick Mount PV’s railless Quick Rack system and power electronics from vendors such as ABB, Enphase and SMA America. In July, SolarWorld announced the launch of its 1,500 Vdc–rated 72-cell SW 340–350 XL MONO module line, which is available with 340 W, 345 W and 350 W maximum power. The introduction of the high-voltage XL product positions SolarWorld to take advantage of the expanding deployment of 1,500-Vdc PV power plants in the US.
SolarWorld / 503.844.3400 /

Sunpreme - Booth 2125

Headquartered in Sunnyvale, California, and launched in 2009, Sunpreme is differentiating itself from commodity module vendors with the development of thin-film, high-efficiency, bifacial, double-glass frameless modules. The company bases its unique cell architecture on its patented Hybrid Cell Technology (HCT) platform, which utilizes four amorphous silicon thin-film depositions on surface-engineered silicon substrate. The frameless double-glass module design does not require electrical grounding. Sunpreme’s Maxima GxB module line includes five modules, two of which integrate Tigo Energy’s TS4-L (long-string) dc optimizers. The highest-power module, the GxB 370W, has a power output of 370 W STC and a module efficiency of 19.1%. Sunpreme specifies a bifacial output for the GxB 370W of 444 W, with a 20% boost in power from the module backside and a resulting module efficiency of 22.9%.
Sunpreme / 866.245.1110 /

Ten K Solar - Booth 759

Ten K Solar, founded in 2008, leverages a unique nonserial architecture with its module and integrated system design.  Its Apex module line includes the Apex 500W Mono (500 W monocrystalline) and the Apex 440W Poly (440 W polycrystalline). Both modules utilize 200 half-cells connected in a matrix (serial and parallel connections). This structure allows current to flow through multiple pathways within a module, improving partial shade performance, reducing the impact of soiling and hot spots, and eliminating a single point of potential failure within the module. Module-level power electronics convert the internal module voltage (<18 Vdc) to an operating voltage of 35 Vdc–59 Vdc. Ten K expands on this shade- and fault-tolerant low-voltage parallel architecture with its ballasted DUO PV system for low-slope roofs and ground-mounted arrays. The DUO system configuration, which integrates groups of parallel-connected microinverters on a shared dc bus, places rows of modules in tandem, back-to-back, to maximize power density and energy yield per square foot.
Ten K Solar / 952.303.7600 /

Power Electronics

Delta - Booth 2259

Delta Group is the world’s largest provider of switching power supplies and dc brushless fans, as well as power management equipment, networking products and renewable energy solutions, including solar inverters. Historically, Delta has positioned itself somewhat behind the scenes in the US solar market, as other vendors have rebranded the OEM’s inverter products. However, Delta is developing its presence in the US, introducing new solutions to the market. Two recent examples are its 7 kW RPI H7U single-phase inverter and its 80 kW M80U 3-phase string inverter. The UL-certified RPI H7U features a secure power supply for limited daytime power production when the grid is not present, and 4 MPP trackers with a full-power MPPT range of 185 V–470 V at 240 Vac and a wide operating voltage range of 30 V–500 V. Integrators continue to deploy high-power 3-phase string inverters in increasingly large multimegawatt PV plants. Delta’s 80 kW M80U inverter will support this upward capacity trend. The inverter has a maximum input voltage rating of 1,100 V, a full-power MPPT range of 600 V–800 V and an operating voltage range of 200 V–1,000 V. Options for connection on the dc side include 16 source-circuit fuseholders, two 3/0 AWG terminal blocks and 18 pairs of MC4 connectors for wire harness compatibility. With a unit weight of 180.6 pounds or less, depending on configuration, the M80U is light enough to permit a two-person installation.
Delta /

OutBack Power - Booth 2825

OutBack Power designs and manufactures inverter/chargers, charge controllers, integration equipment and monitoring solutions for stand-alone and utility-interactive battery-based renewable energy systems. Currently a member of the Alpha Group, OutBack was founded in 2001. Battery-based PV systems are inherently more complicated than grid-direct ones. The accumulated experience of established power electronics companies such as OutBack is a valuable asset for integrators when applications require advanced system configurations. In 2011, OutBack released its Radian series of hybrid, utility-interactive split-phase 120/240 Vac inverter/chargers. Available in 4,000 W and 8,000 W power classes, the Radian features two ac inputs for grid and ac generator connectivity and a high degree of component integration. With the recent introduction of four VRLA storage batteries optimized for specific applications such as float service or regular deep cycling, OutBack now offers a comprehensive product family for energy storage applications listed to the relevant UL standards.
OutBack Power / 360.435.6030 /

SMA America - Booth 959

SMA Solar Technology was founded in 1981. Its US subsidiary, SMA America, was the first inverter manufacturer to offer high-voltage string inverter models in the US market. In addition to developing single- and 3-phase string inverters, SMA has also devoted significant resources to the development of high-power central inverters for multi-megawatt medium-voltage utility-scale PV plants. As the US and global inverter markets have evolved, more manufacturers are focusing on either string inverters or central inverters. SMA is one of a shrinking group of inverter vendors that continue to create solutions in both product classes for utility-interactive applications. One example is its second-generation Medium Voltage Block for utility-scale applications deploying its Sunny Central 1850-US, 2200-US and 2500-EV central inverters. SMA’s 3-phase inverter lineup, the Sunny Tripower series, currently includes six models with rated power capacities of 12 kW–60 kW and 480 Vac output. The company has also been redesigning its single-phase inverter family. It recently launched updated Sunny Boy 3.0-US, 3.8-US, 7.0-US and 7.7-US models, which join the 5.0-US and 6.0-US models it introduced earlier this year, to provide integrators with greater design and installation flexibility. SMA plans to release a high-voltage Tesla-compatible battery inverter for the US market in early 2017. It has also made a significant investment in incorporating MLPE technology from Tigo Energy into its systems, in anticipation of module-level rapid-shutdown requirements in NEC 2017.
SMA America / 916.625.0870 /

Trackers, Racking and Mounting

Array Technologies - Booth 2805

Array Technologies (ATI) began manufacturing solar trackers in Albuquerque, New Mexico, in 1992 and has continually evolved, redesigned and scaled its solar tracking equipment, systems and services in step with the solar industry, especially in the utility-scale PV plant market. ATI launched its third-generation centralized DuraTrack HZ v3 horizontal single-axis tracker in 2015 and continues to be a strong proponent of centralized tracking systems. The DuraTrack HZ v3 has an algorithm with a GPS input tracking method and a ±52° tracking range of motion with backtracking functionality. The system’s drivetrain has sealed gearboxes designed to be maintenance-free for the life of the plant. The DuraTrack HZ v3 has a 135 mph 3-second-gust exposure-C allowable wind-load rating. A passive mechanical wind protection system that does not require power to operate safeguards the tracker during high-wind events and eliminates the maintenance requirements associated with active stow components. Configurations for c-Si modules include one-up in portrait orientation and two-up in landscape orientation, as well as four-up in landscape for thin-film modules. To speed module installation, ATI has developed an innovative single-fastener module clamp with integrated grounding.
Array Technologies / 855.872.2578 /

Beamreach Solar - Booth 2941

Beamreach Solar (formerly Solexel, founded in 2007) showed the demo installation of its Sprint PV system to big crowds of curious onlookers at July’s Intersolar North America event in San Francisco. Developed specifically for weight-constrained, low-slope commercial rooftops with TPO membranes, the system integrates a 60-cell monocrystalline 290 W, 295 W or 300 W module with a composite frame and an integrated racking system. The weight per module, including its racking components, is 38 pounds. The system is not ballasted or penetrating, but rather adheres directly to the TPO roofing membrane. Each row of modules simply snaps into the back feet of the previous row. The lack of metal components eliminates the need for equipment grounding. For shipping, Beamreach packs 26 modules with integrated racking components on a single pallet. Time will tell whether the Beamreach Sprint system will gain traction in the field; however, its design clearly exemplifies the innovation that is happening across the PV industry.
Beamreach Solar / 408.240.3800 /

SunLink - Booth 2037

SunLink launched its first racking systems for commercial rooftops in 2004 and helped pioneer the design and deployment of ballasted PV array mounting systems. More recently, the company has been expanding its product portfolio and expertise to include project development and O&M, SCADA and data monitoring services, and PV tracker systems. SunLink will launch its TechTrack Distributed single-axis tracker in Q3 2016. The self-powered tracker uses a slew drive, a 24 Vdc motor, a lithium-iron phosphate battery and an integrated PV module to drive the tracker. Its tracking range of motion is ±60°. Installers can mount modules one-high in portrait orientation, and array configurations are optimized for 90 modules per 30 kWdc row. A secure modified Zigbee mesh network provides on-site communication between the tracker controllers. The TechTrack Distributed system reacts intelligently to real-time conditions to increase generation and reduce the risk of damage to the power plant. Dynamic stabilization provides damping during critical events such as high winds. The tracker is designed for 105 mph and 5 psf standard loads and is configurable for wind loads of up to 150 mph and snow loads of up to 60 psf.
SunLink / 415.925.9650 /

Conductor Aggregation and Management

CAB Solar Booth 311

Under its CAB Solar brand, the Cambria County Association for the Blind and Handicapped manufactures a range of products that include cable rings and saddles for PV cable management, while providing rehabilitation and employment services to persons with disabilities living in Cambria County, Pennsylvania. Elevated cable systems are gaining popularity in utility-scale PV plants, and CAB was an early supplier to these projects. CAB Solar’s PVC-coated rings and saddles feature a high–dielectric grade, flame-retardant and UV-stabilized coating, applied to 100% of the product’s surface. The resulting rings and hangers are electrically insulated and durable in corrosive environments. CAB offers an extensive range of PV wire management solutions, including multicarrier hangers that provide physical separation between dc source-circuit conductors, ac cables and data transmission circuits. The company also manufactures high-visibility safety vests, bags, pouches and holders for the safe organization and transport of hand tools, cordless tool batteries, meters and communication devices in rooftop and other environments.
CAB Solar / 814.472.5077 /

HellermannTyton - Booth 625

HellermannTyton is a global manufacturer of cable management, identification and network connectivity products. Its North American headquarters are located in Milwaukee, Wisconsin. Its products for PV applications include Solar Ties and Solar E-Clips that enable flexible and secure routing of conductor and cable bundles. HellermannTyton also offers Solar Identification printers, labels and software systems that provide professional and durable PV system labeling. Its Ratchet P Clamp is an innovative solution for cable management. The adjustable ratchet clamp mechanism is available in four sizes for cable bundles or conduit ranging from 0.24 inch to 2 inches. In addition, the product is available with three lengths of mounting plates and 15°, 30°, 90° and 180° angle orientations. The Ratchet P Clamp is designed for easy opening using a small flathead screwdriver. Installers can stack the clamps for parallel cable runs and offset applications.
HellermannTyton / 800.537.1512 /

SolarBOS - Booth 935

Founded in 2004, SolarBOS focused from the start on configurability, with its first product a configurable 600 Vdc source-circuit combiner box that allowed customers to specify the number of circuits and the NEMA rating of the enclosure. This approach remains a core feature of the extensive range of combiner boxes, recombiners, disconnects, battery connection panels and cable assemblies SolarBOS offers today, including many product versions listed for 1,000 Vdc and 1,500 Vdc applications. In 2015, SolarBOS rolled out its Wire Solutions products for deployment in the growing number of commercial and utility-scale systems that use pre-engineered wire harness and cable assemblies. The company’s product family for these applications includes overmolded Y harnesses with or without inline fuses, homerun cable assemblies and combiner box whips. All wire harness assemblies are custom manufactured to client specifications. Customers can choose from various wire gauges and conductor jacket colors, industry-standard connectors and custom labels at each connection point.
SolarBOS / 925.456.7744 /

Primary Category: 

At Solar Power International last year, a sales representative for one of our distribution partners inquired: “Why do so many of my customers order 30 A fuses in their source-circuit combiner boxes?” This is a good question. After all, most crystalline silicon (c-Si) PV modules have a short-circuit current (Isc) rating in the 8–9 A range and carry a 15 A–series fuse rating. This is so common that source-circuit combiners typically come standard with 15 A series fuses. Occasionally, an engineer might specify 20 A fuses to account for thermal derating. However, 30 A fusing assumes an Isc of roughly 18 A, which is an unprecedented series fuse rating for today’s PV modules.

So why do integrators request combiners with 30 A fuses? The answer is not a function of module ratings per se, but rather of how system integrators deploy these modules. Specifically, more and more installation companies use special Y-connector assemblies to parallel PV source circuits in the array field as a way to optimize electrical balance of system (eBOS) costs.

About Y-Connectors

Most industry veterans have seen parallel branch connectors or Y-connector assemblies at conferences or pictured in trade publications or product catalogues. For example, both Amphenol and Multi-Contact offer male and female branch connectors rated for 30 A, as well as overmolded Y-connector assemblies with optional inline fuses. Many eBOS companies also offer customizable Y-connector assemblies. What these connectors and assemblies all have in common is that they have two inputs and one output, allowing installers to make plug-and-play parallel connections within the array.

Until recently, paralleling source circuits within an array was most common in thin-film applications. Compared to c-Si PV modules, thin-film technologies tend to have a higher Voc and a lower Isc. As a result, it behooves integrators to use wire harnesses with inline fuses to parallel thin-film PV source circuits prior to landing them in a combiner box. This practice is cost-effective because it improves conductor utilization within the array and limits the number of combiner box inputs.

Designers can apply these same principles to c-Si PV arrays. After all, touch-safe fuseholders in combiner or inverter wiring boxes are generally 30 A rated, whereas most PV modules have a 15 A series fuse–rating. Therefore, integrators may be able to improve project economics by using Y-connectors to parallel a pair of source circuits ahead of these fuseholders. Before evaluating the potential cost savings associated with this approach, let us review some practical considerations.

Code implications. NEC Section 690.9 requires overcurrent protection for PV modules or source circuits, except when there are no external sources of fault current, or when the short-circuit currents from these sources do not exceed the ampacity of the conductors and the maximum series fuse rating. To make a parallel connection ahead of a combiner box, designers need to account for potential sources of fault currents as well as the module manufacturer’s series fuse ratings. Generally speaking, parallel connections within the array require Y-connector assemblies with inline fuses. In effect, designers need to relocate 15 A series fuses from the combiner box out into the array wiring.

Since parallel connections increase current, designers also need to evaluate conductor ampacity between the Y-connector and the dc combiner or inverter-input wiring box. To achieve the desired cost savings, integrators need to be able to parallel source circuits within the array without unnecessarily incurring the expense of larger-diameter conductors. To avoid having to step from 10 AWG to 8 AWG copper conductors, for example, designers should avoid or minimize situations that require conductor ampacity adjustments according to Article 310. The two most common ampacity adjustment scenarios relate to the number of current-carrying conductors (see Table 310.15[B][3][a]) and distance above the roof (see Table 310.15[B][3][c]). When paralleling source circuits within the array, therefore, it generally makes sense to limit the number of conductors bundled or grouped together to no more than three and to maintain a distance above the roof of at least 12 inches.

Manufacturer limitations. While most of the finger-safe fuseholders for 10 mm by 38 mm fuses found in combiner boxes are manufacturer rated for 30 A, the busbars connected to the fuseholders are not always capable of carrying 30 A of current. Integrators should check with the combiner or inverter manufacturer to ensure that the product is compatible with the use of 30 A fuses.

In some cases, equipment manufacturers require an allowance for heat dissipation where fuseholders are fused at 30 A. The concern is that a lack of space between fuseholders can cause a fuseholder to overheat, potentially melting the plastic and causing a fault. This is not an issue when inputs are fused at 15 or 20 A, as is typical of most string inverter or combiner box applications. However, it may become an issue under continuous loading at full power with 30 A fuses. Landing input conductors on alternating fuseholders, as shown in Figure 1, and removing the unused fuses is one way to improve heat dissipation.

Commissioning and maintenance. From a commissioning and maintenance perspective, incorporating Y-connectors into the PV array wiring does compromise convenience somewhat. After all, landing individual source circuits in combiner boxes provides commissioning agents and service technicians with a convenient means of isolating individual circuits, both to validate proper installation and to establish baseline performance parameters. Using Y-connectors pushes some of the parallel connection points into the array, which can complicate some routine maintenance and troubleshooting procedures, such as taking Voc measurements on a single source circuit.

Arrays fielded with Y-connectors may also require specialized diagnostic tools. After array commissioning, source-circuit voltage measurements are less important than I-V curve traces, as the latter provide more insight into array health. To capture I-V curve traces on source circuits paralleled using a Y-connector, service technicians must have access to an I-V curve tracer rated to process the combined short-circuit current of both strings. At present, the Solmetric PVA-1000S is the only handheld I-V curve tracer offered with an optional 30 A measurement capability. With this 30 A–rated PV Analyzer, technicians can perform an I-V curve trace in a combiner box on two paralleled c-Si PV source circuits. If technicians have access to a 15 A–rated I-V curve tracer only, they will need to isolate the source circuits entering a Y-connector and trace each I-V curve individually.

Cost Reductions

The reason system integrators are willing to make a small sacrifice in convenience is that the proper use of Y-connectors reduces installed system costs. The savings are twofold: material savings associated with a reduction in the total length of PV Wire within the array field, and labor savings, since installers do not have to make as many terminations in source-circuit combiners.

To realize the maximum PV Wire savings, installers need to locate both poles of each PV source circuit at roughly the same spot within the array table. Using the leapfrog wiring method illustrated in Figure 2 is a good way to accomplish this. Where module wire whips are long enough to accommodate leapfrog wiring, this method eliminates about 30–60 feet of PV Wire per source circuit compared to daisy-chain wiring, with the reduction depending on string length (which is largely a function of nominal system voltage). Leapfrog wiring alone can reduce material costs by as much as $20,000 on a 5 MW PV system. (See “Cost-Saving PV Source Circuit Wiring Method,” SolarPro, April/May 2014.) Integrators can reduce material costs even further by combining leapfrog wiring with Y-connectors.

Case study. To illustrate, let us consider a hypothetical example where the basic building block for a large-scale PV array is a 50 kW string inverter that is processing power from a 240-module array table. Each array table is mechanically configured two modules high by 120 modules wide and wired electrically with 12 parallel-connected 20-module source circuits. The wire whips are long enough to accommodate leapfrog wiring. A main service road runs north and south along the east edge of the array.

As shown in Figure 3, the total length of PV Wire per array table is a function of both inverter placement and array wiring. Locating the inverter at the east end of an array table, as assumed in Option 1, provides service technicians with optimal inverter access for O&M purposes but requires the most PV Wire per inverter. Mounting the inverter in the middle of an array table, as shown in Option 2, dramatically reduces PV Wire requirements, but complicates array serviceability. Service technicians will have a harder time reaching each inverter. It may also be impractical or undesirable to run ac conductors within the array field. Option 3, which combines leapfrog wiring with Y-connectors, provides the best of both worlds as it allows for optimal inverter placement and reduces the use of PV Wire significantly.

As compared to Option 1, the combination of leapfrog wiring and Y-connectors in Option 3 effectively reduces the homerun conductor length within the array by half. This setup does not offer a free lunch, however, as the cost to purchase Y-connectors and inline fuses offsets some of the PV Wire savings. While it is possible to purchase inline fuseholders and unfused Y-connectors separately and plug them together in the field, it is generally more cost-effective to purchase an integrated assembly. Companies such as Amphenol, Eaton, Shoals Technologies Group and SolarBOS all offer Y-connector assemblies with integral inline fuses. When purchasing an all-in-one solution, integrators should order extra assemblies for O&M purposes; in the rare event that one fuse blows, they will need to replace the entire assembly.

Table 1 estimates the total material and labor savings associated with deploying array-table configuration Option 3 rather than Option 1. Assuming that 10-gauge PV Wire costs $0.20/foot, you can save more than $400 per array table by adding Y-connectors at the end of each adjacent pair of source circuits (2,070 ft. × $0.20/ft.). While it will cost $240 to add six pairs of fused Y-connector assemblies (12 Y-connectors x $20/each), the net material savings per array table are roughly $174 ($414 less $240). Labor savings are estimated at 1 hour per array table and reflect the fact that installers will spend less time managing homerun conductors within the array (saving roughly 45 minutes) and will have to make only half as many dc terminations at the inverter (saving roughly 15 minutes). Assuming a labor rate of $80 per hour, the total material and labor savings are $254 per array table, which extrapolates to $5,080 per MWac ($0.005/W).

Of course, every array is different, and material and labor costs vary from region to region, so results may vary. However, this case study is a good example of the type of analysis that can help reduce costs, improve profits and win more projects. According to GTM Research, the utility-scale solar market in the US will approach 12 GW in 2016. If each one of these large-scale projects could reduce eBOS costs by a half cent per watt, the industry as a whole would save $60 million.

Eric Every / Yaskawa–Solectria Solar / Lawrence, MA /

Primary Category: 

[Newark, NJ] Panasonic Eco Solutions North America announced the availability of two high-power and high-efficiency HIT 96-cell modules. The N330 (330 W) model has a module efficiency of 19.7%. The N325 (325 W) model has a module efficiency of 19.4%. First introduced in 1997, Panasonic’s HIT technology has a unique hetero-junction cell structure constructed of monocrystalline and amorphous silicon layers. Two ultrathin amorphous silicon layers prevent recombinations of electrons, minimizing carrier loss and maximizing module efficiency. The recently released N330 and N325 modules feature Panasonic’s current-generation HIT cells. Electrical specifications for the N330 are 5.7 Imp, 58 Vmp, 6.07 Isc and 69.7 Voc. Electrical specifications for the N325 are 5.65 Imp, 57.6 Vmp, 6.03 Isc and 69.6 Voc. Panasonic backs both models with 15-year workmanship and 25-year power-output warranties.

Panasonic Eco Solutions North America /

Primary Category: 

To the extent that industry stakeholders can optimize fielded module performance by minimizing hard losses due to failures and soft losses due to degradation, they can enhance the solar value proposition for customers and strengthen the position of companies throughout the value chain.

Fielded module performance is essential not only to PV project profitability, but also to the solar industry’s long-term viability. In a report for the Solar America Board for Codes and Standards (see Resources), Mani Tamizh-Mani and Joseph Kuitche note: “Technology risk—the concern that a technology will underperform (durability) or become obsolete prematurely (reliability)—is one of the major barriers to PV diffusion and project financing.” In effect, more than 95% of fielded PV modules need to meet or exceed manufacturers’ product and power warranty terms to satisfy investors.

Given that PV system service life is measured in decades, the acceptable performance standard for PV modules is a high bar to meet. The good news is that the industry literature summarized by TamizhMani and Kuitche suggests that failure rates (reliability losses) and degradation rates (durability losses) are on the order of 0.005% to 0.1% per year and 0.5% to 0.8% per year, respectively. The bad news is that module manufacturers are constantly adapting module construction and design to drive down product costs and the levelized cost of energy, so past performance is no guarantee of future results.

For this article, I reached out to seven subject matter experts—technical due diligence specialists, independent engineers, system risk assessors, researchers, O&M service providers and so forth—to find out what industry stakeholders can do to optimize module reliability and durability in the field and to identify and remedy unavoidable performance problems. Not surprisingly, this is a continuous process that starts with technical due diligence during product procurement, relies heavily on system design and installation best practices, and extends through plant operations.

What steps can industry stakeholders take to mitigate the impacts of PV module failures that originate directly from production, such as product design or manufacturing deficiencies?

PV module reliability is a cycle. New reliability issues develop whenever we introduce new technologies and manufacturing techniques into the industry. In addition, we will see new fault modes develop over time as our PV fleet ages. Since the entire industry relies on innovations to drive the cost reductions that allow solar to thrive, these issues are inevitable.

This does not mean that the industry is experiencing or will experience a crisis of reliability. Rather, industry stakeholders need to be diligent about identifying and correcting module reliability issues early. If we properly communicate field data, module manufacturers can proactively remediate reliability issues. Potential-induced degradation (PID) is a good example of this feedback loop. PID is a failure mode that emerged in PV modules as a consequence of material changes combined with new installation techniques. Because the industry identified and classified this defect, most module manufacturers know how to design products that will not experience this fault mode in the future.

Rob Andrews, chief executive officer, Heliolytics

PV system owners and installers should take two fundamental measures to significantly mitigate the risk of premature PV module failures. First, PV system designers should take a holistic approach to product selection and use only properly vetted products, installation methods and design principles. While innovation is obviously critical to cost reduction, it comes with risk, so due diligence is vital. Equipment manufacturers are increasingly designing products to integrate with other BOS components, and certification protocols are adapting, so coordination among vendors is more important today than ever before. Secondly, given the underlying nature of certain types of PV module defects, a robust supplier-quality program is critical to ensuring long-term quality assurance. This involves not only an initial qualification of the supplier, but also regular witnessing of production and validation testing of randomly sampled finished product at a third-party lab. I’ve seen a lot of variation in test results between initial samples provided by equipment suppliers and random samples selected from inventory by buyers or their representatives.

Brian Grenko, chief executive officer, Amplify Energy

Stakeholders should engage a due diligence firm to vet the supplier before committing large projects to a particular module manufacturer or model number. This could be as simple as selecting a prevetted module, on the one hand, or as involved as conducting third-party tests at the factory, on the other.

Paul Hernday, senior performance engineer, Vivint Solar

Especially with large-scale PV projects, it is important that module-supply agreement negotiations ensure consistent manufacturing quality across the production schedule. This requires factory and product inspections during manufacturing, as well as a clearly defined quality control protocol. Stakeholders can also propose accelerated testing sequences at the early stages of a PV project. While it is difficult to extrapolate test results to real-world performance, the results are valuable for making relative comparisons between different module suppliers and bills of materials. These are just a few examples of the types of technical support services that Enertis provides to industry stakeholders, including financial entities, insurance companies, investment funds, private investors, developers, engineering companies, contractors and equipment suppliers.

Vicente Parra, PhD, head of quality and testing services, Enertis Solar

As an O&M provider to more than 1.5 GW of PV assets, we would like to see stakeholders pay more attention to the quality control of materials used in the manufacturing process. We also recommend that stakeholders implement periodic independent testing, both in the field and at warehouse storage facilities.

Rue Phillips, chief executive officer, True South Renewables

The best way to mitigate the effects of module failures is to try to eliminate them. Manufacturers can do this by implementing a quality management system (QMS) to make sure that they consistently produce a high-quality product. Module buyers can insist on working with a manufacturer that has a strong QMS. At the National Renewable Energy Laboratory (NREL), we are working with stakeholders to develop a module quality technical specification, IEC/TS 62941, which will apply PV-specific requirements on top of ISO 9001 with the objective of improving confidence in the QMS. Qualification tests are not lifetime tests, so the only way to get a real service-lifetime prediction is by using a product-specific test reinforced by field experience and controlled by a QMS.

Should it be impossible to eliminate failures resulting from design or manufacturing deficiencies, we want to manage the effects by detecting the failures as soon as possible. This might include testing a sample set of modules before installation, performing a final acceptance test after the plant is constructed, and performing proactive inspection and performance monitoring as part of the plant’s O&M activities. Early detection of failures means timely replacement of modules and minimal loss of production.

Timothy Silverman, scientist, NREL

Quality assurance and supply chain management are two of the things that we specialize in at Clean Energy Associates (CEA). From our perspective, the best way for stakeholders to mitigate manufacturing deficiencies is to invest in a robust quality assurance program that includes up-front factory audits, 24/7 inline manufacturing oversight, bill-of-material review, process control monitoring, preshipment inspection and careful product-handling practices. Our global engineering services team, which is based in Asia, provides these types of services, often liaising with Nationally Recognized Testing Laboratories to certify and evaluate products and suppliers.

There is plenty of opportunity for error throughout the module production process. We see errors resulting from poor cargo-handling practices, inferior materials, poor soldering, inaccurate backsheet measurements and cuts, and so forth. While the defects associated with these errors may seem small, they can cause serious problems down the line. A lot of different variables factor into quality. Some manufacturers have multiple manufacturing facilities or OEM suppliers, which means that quality can vary dramatically even for products sold under the same brand. Even with a single factory, production quality can vary significantly between the day shift and the night shift. Other factories have a few automated lines and several highly manual lines; the more manual a production line, the more room there is for human error.

George Touloupas, technology and quality director, CEA

What are your preferred methods and tools for detecting and identifying fielded module failures or performance problems?

Historically, companies approach this through data analytics or manual on-site testing. While data analytics are essential to the proper operation of a PV system, most data acquisition configurations have a difficult time identifying a string-level failure, let alone a module fault. In many cases, it is statistically impossible for data analytics to identify distributed module faults. This limitation is due to instrument error and data averaging effects. While asset managers can use manual field techniques—such as combiner-level I-V curve traces, current clamp comparisons or Voc checks—to find module faults, these on-site tests are labor intensive. As a result, technicians generally perform manual tests only on a subset of fielded modules.

To address these issues, Heliolytics developed a module-level thermal audit process, which uses high-resolution infrared and visible imaging to precisely identify module faults in the field. By measuring the temperature of modules using cameras developed specifically for aerial thermal imagery of PV modules, we can detect the full range of module fault modes. In addition, we can complete the assessment for a 10 MW site in approximately 20 minutes. The speed and precision of the assessment allows the direct comparison of thermal properties between array segments. Module-level thermal audits not only allow field personnel to precisely locate faulted modules, ensuring prompt remediation, but also facilitate in-depth analyses that can provide deeper insight into the fault modes. Generally speaking, module faults that correlate to serial numbers are likely due to manufacturing issues, whereas faults that correlate to installation date are likely due to installation issues.

Rob Andrews, Heliolytics

We begin the process of looking for module reliability or durability issues by using our proprietary PVSAT software to remotely examine production and weather data. After scrubbing the data to remove errors and validating applicable system measurement devices, we apply filters as needed and generate a series of automated analyses that characterize PV system performance and durability. We specifically developed our software analytics to allow us to remotely diagnose certain types of performance issues without incurring the costs associated with rolling a truck or removing product for third-party laboratory testing. If the production and weather data are clean and trustworthy, we can, for example, remotely identify certain types of losses—including shading, soiling, PID, incident angle effects and so forth—by looking for characteristic patterns in the data.

We can also provide on-site inspection and testing services to validate PV system safety, quality and performance at a high resolution or granularity. For example, we employ advanced testing methods such as rapid thermal imaging or field EL [electroluminescence] imaging that enable us to identify PV module-level defects conventional O&M protocols often miss. When irradiance and wind speed conditions are favorable, we use IR [infrared] imaging to quickly identify hot spots resulting from cracked cells, failed solder joints or damaged bypass diodes. Since hot spots are sometimes difficult to capture when irradiance levels are below 700 W/m2, our team has developed IR capabilities that use unmanned aerial vehicles or drones. This more automated approach is essential when the on-site inspection time allotment is limited, as in winter months at northern latitudes.

Brian Grenko, Amplify Energy

Good instrumentation is a bit like an X-ray vision superpower. It lets you “see” the electrical and thermal processes going on deep in your PV system components. Of course, one instrument can’t do it all. To measure the performance of a PV module, string or subarray, you can’t beat an I-V curve tracer. It measures all of the PV performance in detail, and it does so faster and more safely than traditional voltmeter and clamp-meter methods. It’s the ultimate tool for array performance verification and troubleshooting. In many cases, you can trace a performance problem back to a particular module without even disconnecting the module interconnection cables within the source circuit.

An IR camera pairs well with I-V curve tracing. When the I-V curve measurement detects a performance anomaly, for example, IR imaging can often locate the cause. Conversely, when IR imaging detects an anomaly, I-V curve tracing can determine its performance impact. Although it’s a great diagnostic tool for PV work, IR imaging has a learning curve. It’s easy to conclude you’re seeing PV hot spots, for example, when you’re actually detecting reflections, soiling or debris. Also, the field of view of IR imagers is still relatively narrow, so you need to stand quite far from the array to image multiple modules, which isn’t always a possibility based on conditions in the field.

Paul Hernday, Vivint Solar

The most suitable ways to identify module failures and underperformance in the field are still classic methods such as conducting a visual assessment, determining the maximum power, analyzing IR thermographs and inspecting EL. All of the equipment used for these tests must meet calibration requirements to authenticate the test results and meet industry standards. This ensures that the test measurements are accurate for all types of PV modules. Mobile PV test solutions equipped with high-quality solar simulators, such as our PV Mobile Lab, are very practical assets in this context.

Vicente Parra, Enertis Solar

High-quality module-level thermal audits using commercial-grade thermal cameras are the most effective method for identifying module losses. Our approach to annual testing varies from contract to contract. Some contracts require that we test 100% of the PV source circuits, while others require that we test only a subset of source circuits. Personally, I advocate for electrical testing on every source circuit and thermal scanning on every PV module. In my opinion, commissioning, validation and acceptance tests need to play a far more important role in the technical and financial diligence process for PV assets.

Rue Phillips, True South Renewables

We normally start with an analysis of any available historical performance data. On production systems, this is often limited to yield, which is such a noisy measurement that it can be difficult to identify specific problems. We are developing more-advanced monitoring techniques that will allow us to detect problems within that noisy signal before they become major losses in production. If the performance data suggest there’s a problem, we proceed with a formal visual inspection, which usually produces some leads about what could be going wrong. From there, we may select modules on which to perform outdoor I-V curve measurements, IR thermography and outdoor photoluminescence imaging. These techniques usually get to the bottom of any remaining mysteries.

Timothy Silverman, NREL

A good monitoring system with data analysis software should be able to indicate problems in the field and trigger field-testing actions. However, there are cases where problems may lay hidden for a long time before they set off a low-performance alarm. An ideal approach is to take proactive steps to identify these types of latent issues, while being budget conscious. Since most failed modules release thermal energy, regular thermal imaging is a reliable method for identifying a large percentage of potential module problems. We recommend routine IR thermal imaging as part of a well-designed preventive maintenance package. Technicians can complete these IR tests on the ground or use unmanned aerial drones, depending on the scale of the system.

Portable EL imaging systems are useful for a more-detailed analysis of performance issues. This method is minimally disruptive to plant operations, as technicians can test modules without removing them from the racking. While sending modules to an independent laboratory for analysis is another option, it is both costly and time consuming. Moreover, concerns about damage resulting from module removal, packing and transport can complicate warranty claim procedures. A mobile truck-mounted lab is a potential solution in cases where a large number of modules need to be tested for the purpose of backing warranty claims.

George Touloupas, CEA

In your experience, what are the most common failure modes or performance problems for fielded PV modules?

The majority of the faulted modules in our scans are due to string outages. The remaining faults are due to module-related failure mechanisms, which we categorize as hot spots, submodule faults or module faults. Hot spots indicate some type of cell or solder issue, the most common of which is cell cracking. Submodule faults include a range of failure mechanisms—cell or solder issues, junction box wiring or diode failure—that engage a bypass diode and cause module output to drop by at least 33%. Finally, module faults refer to failure modes that de-activate an entire module, such as advanced cell damage across an entire module or damaged junction box wiring.

It is important to point out that in the case of hot spots and diode faults, the module is still capable of producing power, though likely less than the warrantied output. However, all of the module failure modes will decrease the effective string voltage and will de-rate the output of the remaining modules in the source circuit. Thus, module-level faults can have a greater impact on system energy production than just the loss of the module itself.

Rob Andrews, Heliolytics

In my tenure working for various PV module manufacturers over the years, junction box problems perennially topped the list of common failure modes. While improvements in materials, ingress protection and electrical contacts have reduced the risk of design-related junction box failures, damaged bypass diodes remain a common failure mode. PV modules with broken glass also represent a large percentage of reported failures. These failures are often site induced—whether due to lightning strikes or contact damage from debris—and occur on a low but regular basis over time.

Unfortunately, some defects in PV module design, materials and workmanship are not easily detected at the time of project commissioning and manifest over time based on site conditions. Prolonged UV exposure activates premature EVA or backsheet yellowing. Snail trails evolve from solar cell microcracks after exposure to humidity. PV modules prone to PID degrade prematurely in warm, wet or salty environments, depending on the PV system grounding configuration. Improved durability test standards have made it easier to detect these problems, most of which are an unintended consequence of product design optimization.

Brian Grenko, Amplify Energy

Within the first 2 years of operation, there are three failures or defects that we detect most often in the field: potential-induced degradation, which is most common in hot and humid climates; polymer discoloration; and snail trails, which are associated with internal cell cracks. We also find module junction box failures in module infancy. As systems age, we start to see hot spots, the effects of environmental corrosion and simple electrical insulation losses, such as scratched backsheets, caused by mishandling during module installation.

Vicente Parra, Enertis Solar

We mainly examine systems that are at least 10 years old, so we often see cracked cells, failed diodes and delaminations. Some systems have widespread hot spots due to failed interconnects. We have also seen broken glass due both to internal electrical failures and to impacts. We often encounter performance problems due to soiling, shade and snow. Sometimes different system design or O&M practices could have reduced these losses, but they are unavoidable in some cases based on location and climate.

Timothy Silverman, NREL

The module defects that we discover most often on-site include potential-induced degradation, cell microcracks, hotspots, cell or cell-string spacing issues, polymer delamination, busbar and connector oxidation or corrosion, encapsulant discoloration, sealant failure and frame corrosion. The majority of these defects will lead to performance degradation over time. We also see junction box and connector failures that can lead to arcing and pose a fire hazard. 

George Touloupas, CEA

What types of PV module failures are most likely to result from mishandling or from system design deficiencies? Do you have any recommended best practices for avoiding these issues?

We have seen two fault mechanisms where installation or design practices clearly led to cell damage. We traced the first fault mechanism to overtightened module-mounting clamps, which caused cell damage near the module frame. We traced the second fault mechanism to a lack of access pathways, which caused technicians to walk on the flush-mounted modules. In this case, we were able to see the technicians’ favorite walking routes in the hot-spot patterns associated with the cracked cells.

Rob Andrews, Heliolytics

Physical damage to the glass, frame or backsheet that is easy to identify through visual inspection reveals many shipping and handling issues. However, mishandling can also result in cell microcracks, which are significantly more difficult to detect. While PV module manufacturers usually conduct EL imaging in the factory to identify microcracks for quality assurance purposes, few industry players have the capability to do so in the field. Over time, microcracks in fielded PV modules can develop into hot spots. Generally accepted best practices for mitigating shipping damage include packaging PV modules vertically to reduce vibrational stress and designing structurally sound pallets optimized for packing into shipping containers.

Ergonomically, two people are needed to handle a PV module properly. I always cringe when I see someone balancing a 72-cell PV module overhead by resting it on a hard hat. This practice is not only a safety concern, but also causes dendritic microcracks in cells.

Brian Grenko, Amplify Energy

It is well documented that most PV modules leave the factory with some degree of microcracking, and that transportation and handling induce additional cell cracking. Mishandling can also gouge the module backplanes, allowing greater moisture ingress and possibly contributing to PID. Installers should never stand on modules or module frames. It’s important to realize that cell cracks are not immediately visible to the eye and are not audible. Evidence of cell cracks—such as snail trails or hot spots—might not appear for many months.

Paul Hernday, Vivint Solar

Unfortunately, it’s not uncommon to see module glass breakage or internal cell cracking due to improper handling, both in the field and during transit to the site on a pallet. At the commissioning stage, we see damage reports associated with backsheet scratches. These are easy to detect via EL since perforations damage the back surface field of the PV cell. On-site training is a good way to mitigate these problems. You can also implement quality control activities at different project stages, such as preshipment, post-shipment (seaport or on-site), during installation and after mounting.

Vicente Parra, Enertis Solar

Mishandling leads primarily to cracked cells. These cracks are not visible to the eye and do not cause a detectable loss of performance until thermal cycling causes the gridlines bridging the cracks to break. This delay makes it difficult to definitively attribute the performance degradation to mishandling. The solution is to communicate to installers that stepping on modules, dropping modules or dropping objects onto modules can cause invisible, permanent damage. In some cases, the selection of mounting hardware can determine whether an installer is forced to step on a module.

Timothy Silverman, NREL

The primary defects caused by module mishandling include microcracks, backsheet punctures, broken glass and frame damage. Over time, these defects cause a range of failures such as electrical leakage, low-power output, hot spots and arcing faults. Simple measures can prevent many of these defects.

Well-organized logistics can assure that modules are not subjected to excessive shocks during transportation. Use inexpensive shock stickers, for example, to raise rough-handling alarms that initiate on-site screening procedures, such as EL testing. It is also very important to follow the manufacturer’s installation instructions, as failure to do so may cause serious problems and invalidate the warranty. Installers should always work in pairs when handling modules. They should never walk on modules and should avoid leaning on them. Installers should also torque mounting clamps to manufacturer-specified values and avoid placing strain on junction box cables.

System design deficiencies may also directly or indirectly cause modules to fail. For example, incorrect string length will lead to arcing damage due to excessive voltage. Wrong material interface between module frame and racking or grounding gear will cause electrochemical corrosion. One way to avoid these issues is to engage a third-party agency, in the early stages of a project, to evaluate system design and installation practices.

George Touloupas, CEA

What steps can project stakeholders take to expedite PV module warranty claims?

We have found that it is possible to expedite warranty return processes by combining full-site coverage for module fault detection activities with strong, consistent documentation. On one project, for example, our module-level thermal audit detected a large number of submodule faults. By analyzing serial numbers, we found a strong correlation between these faults and a specific manufacturing batch, which suggested a manufacturing defect. Since we knew the exact locations of the faulty modules, we collected a sample set of faulted modules for follow-up testing. When these tests revealed that the sample modules exhibited a common fault mode, we used our high-resolution thermal audit dataset to initiate a warranty return process for all of the modules exhibiting these particular submodule fault characteristics. Highly consistent data made this claims process possible. We collected all of the data at the same time, using the same instrument.

Rob Andrews, Heliolytics

I recommend that PV system operators familiarize themselves with the PV module warranty, which should clearly define each party’s responsibilities and the process for obtaining service in the event of a claim. It’s reasonable for manufacturers to request certain information about the claim to expedite processing, such as a detailed explanation of the problem and affected serial numbers. In previous roles, I was able to administer many customer claims quickly and remotely, provided the quality of data was sufficient. At Amplify Energy, we often identify PV module defects when conducting on-site inspection and testing. To address these issues in a safe, efficient and cost-effective manner, we work with PV module manufacturers to make authorized immediate repairs on their behalf, such as bypass diode replacement and backsheet repair. Certain solar operations and maintenance firms provide a similar service for inverters.

Brian Grenko, Amplify Energy

At Solmetric, which is a wholly owned subsidiary of Vivint, we occasionally hear from customers who indicate that manufacturers respond more positively to module warranty claims that are accompanied by carefully measured I-V curves. This makes sense, because when a PV module company sends a performance engineer out to the field to examine a problem array, their main tool is an I-V curve tracer. IR imaging can also substantiate claims. The most common example of this is hot spots at failing bonds between cells or at solder bonds between ribbon busbars. Another best practice is to compile statistics about trends in module performance or the appearance of physical defects. Sometimes a module maker recognizes a pattern it has seen before, and replaces a batch of modules without waiting for more modules to fail.

Paul Hernday, Vivint Solar

It would expedite claims and generally improve the warranty process if OEMs documented an accepted process for testing and confirming failures in the field. On one project, the OEM insisted that the system owner purchase replacement modules before they would provide a refund against the faulty modules returned for failure confirmation.

Rue Phillips, True South Renewables

Manufacturer warranties are limited and generally biased unfavorably against the buyers. As a result, the claim process may prove lengthy, complicated and costly. Resolution times depend on the nature of the defect, which may complicate the proof, as well as the commercial policy and general standing of the manufacturer. No two cases are alike, and there is no general rule that describes the course of a warranty claim. Tier 1 manufacturers are not necessarily more efficient in honoring their warranties than smaller suppliers. The best things buyers can do are to choose modules that have been extensively tested and preventatively implement quality assurance measures throughout project development. The earlier a problem is identified, the easier it is for the manufacturer to provide a remedy.

George Touloupas, CEA


David Brearley / SolarPro / Ashland, OR /


TamizhMani, GovindaSamy (Mani) and Joseph Kuitche, “Accelerated Lifetime Testing of Photovoltaic Modules,” Solar America Board for Codes and Standards, July 2013

Primary Category: 

Accurate and reliable back-of-module temperature measurements are essential for evaluating PV array performance. When you include other electrical and meteorological data, you can use back-of-module temperature measurements in concert with module temperature coefficients to monitor PV system performance, model predicted power output or assess warranty claims. (See “PV System Energy Performance Evaluations,SolarPro magazine, October/November 2014.)

Many parameters drive back-of-module measurement accuracy and reliability, including sensor placement on the module, sensor technology, attachment method, and the balance of components in the data acquisition system. The better you understand the impacts of various measurement decisions—particularly, sensor type and attachment method—the more you can improve the accuracy and reliability of these measurements. Here I provide background on the topic and detail some best practices for measuring back-of-module temperature with improved confidence.

Measured vs. Actual Temperature

In considering the thermal environment of a photovoltaic cell, you are primarily interested in the temperature of the semiconductor (p-n junction). This is a difficult temperature to measure, since you cannot directly probe operating PV cells in fielded modules. As a proxy, you can use an open-circuit reference cell—which is a similarly packaged PV cell of the same technology—and extrapolate cell temperature from changes in open-circuit voltage. However, reference cells are built typically for measuring irradiance and are not readily available for measuring cell temperature.

As a result, you generally measure back-of-module temperature using traditional technologies, such as external temperature probes, and use these data as an approximation of the temperature at the semiconductor junction. Since multiple materials lie between the measurement probe and the p-n junction—including backsheet, encapsulant and semiconductor material—your back-of-module temperature measurements never perfectly reflect the temperature at the junction itself. Therefore, you must minimize the differential between the measured back-of-module temperature and the actual temperature at the semiconductor junction.

On one hand, the temperature coefficient of power for PV modules is a negative value, meaning that higher cell temperatures result in lower power output. On the other, poorly executed back-of-module temperature measurements usually result in measured temperature values that are lower than actual temperature values. If you inaccurately report the apparent back-of-module temperature as lower than it is in reality, you will overpredict the expected power output. As an example, the relative temperature coefficient of power for crystalline silicon modules is typically -0.45% per degree Celsius; therefore, if your measured back-of-module temperature is 7°C low, you will overpredict the expected dc power output by about 3.2%, which is a significant amount for large PV systems.

Sensor Selection

The sensors you are most likely to use for measuring back-of-module temperature include thermocouples, thermistors, resistive temperature detectors (RTDs) and infrared thermocouples. While each technology is theoretically capable of delivering reliable measurements over the lifetime of the device, I generally recommend Type T or Type E thin-film thermocouples for measuring back-of-module temperature. Within each device class, however, you must select among the available types or models to identify the specific sensors most suitable to the temperature range and environmental conditions that the fielded modules experience. Regardless of sensor technology, you must also pay attention to the sensor wire gauge or thickness. The data acquisition system (DAS) itself may also influence component specification.

Thermocouples. Thermocouples are constructed out of dissimilar metals or semiconductor materials, and they produce voltage in a predictable relation to temperature. While you may choose among many styles, thin-film and beaded thermocouples are most applicable for measuring back-of-module temperature. Thin-film thermocouples are formed from flattened or deposited metal traces on a plastic carrier. Beaded thermocouples are formed from twisted and soldered wire ends or by crimping the wires within a metal bead. As detailed in “Empirical Testing at NREL and Beyond,” test results indicate that thin-film thermocouples are typically more accurate than beaded thermocouples for back-of-module applications.

You want to select a thermocouple type where the temperature range of interest constitutes the highest proportion of the overall temperature range for that device. Therefore, Type T thermocouples, which have a measurement range of −200°C to 300°C, are generally best suited for back-of-module applications. Type E thermocouples, which have a measurement range of −200°C to 900°C, are also an option. Do not use probes encased in cylindrical metal sleeves, as these are not designed to measure surface temperatures.

Thermistors and RTDs. Thermistors and RTDs are resistive devices that change their resistance in relation to temperature. While thermocouples generate a signal voltage, both thermistors and RTDs require excitation. The DAS must provide an excitation signal to the thermistor or RTD to measure the variable resistance across the device. Like thermocouples, thermistors and RTDs are available in packages that are suitable for measuring the surface temperature on the back of a PV module, such as a flat element sandwiched between layers of plastic.

You may need to install a completion resistor when using thermistors or RTDs with some DAS. Where required, use a high-accuracy completion resistor with a low temperature coefficient of resistance. For example,  low-cost completion resistors rated at 10 parts per million per degree Celsius (ppm/°C) are readily available.

Infrared thermocouples. Infrared thermocouples use optical elements to measure the temperature of a surface. The color and reflectivity of the surface at which they are aimed impact the accuracy of these devices. I do not recommend infrared thermocouples for long-term surface temperature measurements on fielded modules because extensive maintenance is required to keep these devices clean.

Environmental ratings. In accordance with the product qualification standards for crystalline silicon and thin-film PV modules (IEC 61215 and IEC 61646, respectively), Nationally Recognized Testing Laboratories conduct thermal cycle tests for PV modules across a temperature range of −40°C to 85°C. It is safe to assume that back-of-module sensors experience similar temperatures, so the sensors should be rated to this range. They should also be rated to experience 0%–100% relative humidity (condensing and noncondensing); UV radiation of varying intensity and duration; and exposure to dirt, sand and nonneutral pH (for instance, acid rain). For long-term reliability, all the associated temperature measurement system components and accessories—connectors, extension cables, weather protection boots and so forth—must be appropriately rated for these temperature and environmental conditions. Note that corrosion within connectors is a significant reliability concern.

Wire gauge. Wires in the 30–20-gauge range are generally well suited for back-of-module applications, as these provide a balance between response time and mechanical strength. While a fine-gauge thermocouple—such as one constructed of 40-gauge wire—is very responsive to back-of-module surface temperature changes, it is also highly susceptible to breakage, even from ordinary handling. The same is true of fine-gauge leads on resistive measurement devices.

DAS considerations. Select temperature sensors that the DAS natively accommodates and consider the measurement system as a whole. For example, if the on-site DAS is capable of directly measuring low-level voltage signals but does not produce an excitation signal, then a thermocouple may be a better sensor option than an RTD. However, if the thermocouple is located a significant distance from the DAS, then the installation may be susceptible to noise, which will show up in the data. For the DAS to accurately measure the signal voltage from the thermocouple, you may need to install and properly ground shielded extension cables to eliminate the stray noise associated with the long cable run. In some cases, you will need additional signal conditioning components to complete the system.

Sensor Attachment

Regardless of measurement device accuracy, a temperature sensor’s utility for back-of-module applications is directly related to the quality and longevity of the attachment method. I have reviewed a wide variety of attachment methods, both in the field and in controlled tests, and I have found that many of these methods experience significant physical degradation over time. Invariably, attachment degradation leads to measurement inaccuracies, which manifest as increasingly large deviations from the actual semiconductor junction temperature and an increase in the range of these deviations.

The most common methods for attaching temperature sensors to the back of a PV module include various kinds of tapes or adhesives. I recommend using UV-resistant polyester tape for sensor attachment, as it outperforms most other types of tape and is easier to use in the field than adhesives. The shape of the attachment method also impacts its long-term field performance.

Tape. Technicians use a wide variety of tapes to attach temperature sensors to module backsheets in residential and commercial PV systems, including electrical tape, packing tape, aluminum foil tape, duct tape, polyimide-film tape and polyester tape. The vast majority of these products are not intended for continuous outdoor exposure to moisture, UV radiation and elevated temperatures. When used incorrectly, tape can lose its adhesive properties, which eventually results in a loss of contact between the temperature sensor and the module backsheet.

Electrical tape, which is constructed of vinyl backing with a rubber adhesive, releases from the backsheet at common module operating temperatures. Packing tape, which is constructed of a polyester or polypropylene film backing with a low-strength adhesive, becomes brittle over time and may release from the module. Aluminum foil tape tears easily and may pose a safety concern since it is electrically conductive. The plastic coating on duct tape becomes brittle, and the adhesive also tends to degrade over time at elevated temperatures. None of these products should ever be used in back-of-module applications.

While polyimide-film tape—most commonly sold under the brand name Kapton—is ideal for high- and low-temperature applications, it performs best in the low-oxygen environments experienced by spacecraft. In a summary of product properties, DuPont notes: “There is a synergistic effect upon Kapton if it is directly exposed to some combinations of ultraviolet radiation, oxygen and water.” These effects can cause polyimide tapes to become brittle in back-of-module applications. In fact, since many vendors encase thin-film thermocouples in polyimide-film tape, you should select an attachment method that protects this sensor package.

Given that many backsheets are constructed of multiple layers of polyester, polyester tape is the most appropriate for attaching temperature sensors to the back surface of a PV module. This tape typically is composed of a translucent green polyester backing material with a silicone adhesive. While polyester tape holds up well against moisture, temperature and UV radiation, it does not conform to the shape of the sensors well. Therefore, you need to use relatively flat temperature sensors with this type of tape.

Adhesives. It is also possible to bond temperature measurement devices directly to module backsheets, most commonly with silicone adhesives or epoxies. To use silicone adhesives successfully, you must minimize the thickness of the silicone layer, which can insulate the sensor from the back of the module. This insulating effect tends to result in a low apparent temperature measurement and a wide spread in the data. At the same time, you must not introduce bubbles into the silicone between the sensor package and the backsheet, as this can lead to delamination and long-term measurement drift.

Because they are thermally conductive, thermal epoxies are well suited for these applications. Other types of epoxies may not be appropriate, however. Avoid clear epoxies, for example, as these tend to degrade when exposed to back-of-module environmental conditions. Pourable low-viscosity epoxies tend to drip and allow for sensor movement during the curing process. Regardless of adhesive type, you must secure the sensor and cable in place while the material hardens and cures. You can use temporary strips of tape for this purpose or, better yet, die-cut adhesive discs or overlays.

Shape of attachment. Field testing indicates that the shape of the attachment impacts its longevity in the field. While many industries use rectangular polymeric films to attach surface measurement devices, the corners of these films tend to detach from the adhesive over time. Once this process starts, the film continues to slowly delaminate. This same process happens when you use rectangular polymeric film to attach a temperature sensor to a module backsheet.

One way to reduce the likelihood of this type of delamination is to trim the film or tape into a round shape, which eliminates the corners where the degradation first manifests. Die-cut polyester dots or round overlays are particularly immune to this type of failure, and quite affordable as well. Multiple vendors sell green polyester dots in a variety of diameters as masking discs for powder coaters; these products work well for attaching temperature sensors to module backsheets.

Recommended Best Practices

The most successful way to measure the back surface temperature of fielded modules is to use a thin layer of silicone adhesive to attach a 30-gauge thin-film Type-T thermocouple to the backsheet, and then cover the sensor package with a round disc of green polyester tape to protect the sensor against UV damage and to provide a modest amount of insulation to temper the effects of wind. This specific configuration of components illustrates three best practices that generally improve measurement reliability. First, it uses a sensing element with a small physical package that is designed for surface measurements. Second, it ensures that the sensing element is firmly in contact with the backsheet. Third, it minimizes the amount of adhesive required, which limits insulating layers between the sensor and the backsheet.

My preference is to locate sensors near the middle of the most central PV cell and to secure the sensor leads with round polyester discs in a manner that provides some measure of strain relief. For sites that require multiple measurements, use the same sensors and attachment methods where possible. This consistency can help you differentiate between a sensor that is failing or drifting and an actual system performance issue. It is important that the module backsheet be clean and dry before you attach any sensors. Sterile 70% isopropyl alcohol wipes work well for this purpose.

Ryan Smith / Pordis / Austin, TX /


Subscribe to Modules