From pv magazine Global

A new white paper from research and consulting firm Exawatt examines and contrasts key module parameters across various technologies to assess the potential value these technologies may offer for residential and commercial applications. The white paper, authored by Molly Morgan and Alex Barrows of Exawatt, draws on analyses from the company’s Solar Technology and Cost Service.

The paper reveals that, in the modelling performed, back contact (xBC), heterojunction (HJT), and tunnel oxide passivated contact (TOPCon) technologies may exhibit meaningful improvements in lifetime energy generation compared to mono passivated emitter rear contact (PERC) technologies. Through detailed modelling exercises, the document evaluates how xBC, HJT, and TOPCon contribute to increased clean energy generation and potential financial savings depending on specific system parameters.

In both residential and commercial system modelling scenarios, the authors found that xBC stands out as the top performer, showing an average increase of 16.0% over mono PERC, while HJT and TOPCon offer generation gains of 11.4% and 8.2%, respectively.

Furthermore, the white paper delves into the profitability of residential and commercial installations through assessments of payback time and levelized cost of electricity (LCOE). Despite their premium pricing, xBC, HJT, and TOPCon technologies demonstrate enhanced profitability in both modelling scenarios in comparison to the previously mainstream mono PERC. Among these technologies, xBC emerges as the frontrunner, boasting an average 9.7% shorter payback time and 10.7% lower LCOE across all modelled locations.

While small cost reductions may still be achieved in the current PV industry, the white paper outlines that these are relatively minor in comparison to the potential efficiency gains offered by advanced technologies. High module efficiency is key to driving down system cost-per-watt, payback time, and LCOE, since it can drive down the per-watt costs of many key non-module costs such as labor and mounting.

The white paper underscores the importance for distributors, installers, and system owners to grasp the value proposition of high-performance technologies for informed decision-making on which technology has the greatest value for a specific application.

The authors conclude that as the industry continues to prioritize performance improvements over cost reductions, embracing high-performance PV technologies can pave the way for enhanced efficiency, cost savings, and sustainable energy solutions.

The Renewable Energy Test Center (RETC) released its 2024 PV Module Index report, evaluating the reliability, quality, and performance of solar panels.

Solar modules are put through a variety of accelerated stress tests to evaluate these parameters. Through comparative test results, project stakeholders can select products best suited for a particular environment, location, or portfolio.

To identify the best of the best, RETC reviewed and ranked the overall data distributions across three disciplines: quality, performance, and reliability. Find the overall top performers at the end of this report.

Reliability

Backsheet ultraviolet durability

Top performers: JA Solar, Longi Solar, SolarSpace

Backsheet ultraviolet durability (BUDT) incorporates a durability testing sequence to probe glass-on-backsheet PV module designs for vulnerabilities to UV exposure and prevent backsheet-related failures. This BUDT sequence starts with 1,000 hours of damp heat exposure to weaken polymeric bonds.

Highlighted top performers experience no backsheet cracking in the test.

Damp heat test

Top performers: Astronergy, ES Foundry, Longi Solar, Runergy, and Trina Solar

The RETC thresher test includes a damp heat test that exposes modules for 2,000 hours, double the amount required for product certification. The test evaluates a module’s ability to withstand prolonged exposure to humid, high-temperature environments. Taking place inside an environmental chamber, the test exposes modules to a controlled temperature of 85 C (185 F) and a relative humidity of 85% for a set amount of time.

RETC highlighted performers that experienced less than 2% degradation after this exposure.

Hail durability

Top performers: JA Solar, Longi Solar

RETC’s hail durability test takes UL and IEC standards testing a step further, exposing solar modules to higher kinetic impact to reflect the risk posed by hail over a 25 or 30-year operating life. In addition to ballistic impact testing, RETC runs thermal cycle and hot-spot tests to reveal potential long-term module degradation.

The top performers in this category withstood an effective kinetic energy of 20 Joules or more. These modules effectively demonstrated resistance to a 45 mm (1.8 in.) iceball traveling at a terminal velocity of 30.7 m/s (68.7 mph).

Potential induced degradation (PID) 

Top performers: Astronergy, ES Foundry, GEP VN, Gstar, JA Solar, Longi Solar, Qcells, REC Solar, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, and Yingli Solar

Potential induced degradation (PID) resistance tests rack-mounted modules in an environmental chamber, which controls temperature and humidity and exposes them to a voltage bias of several hundred volts with respect to the mounting structure for 192 hours (PID192 exposure). PID testing characterizes a module’s ability to withstand degradation due to voltage and current leakage resulting from ion mobility between the semiconductor and other elements in module packaging.

RETC required that PV module models withstand PID192 exposure with less than 2% degradation in maximum power. At the other end of the spectrum, it considered maximum power degradation greater than or equal to 5% a red-flag result.

Static and dynamic mechanical load test

Top performers: Aptos Solar, Astronergy, ES Foundry, Gstar, JA Solar, Longi Solar, Runergy, Silfab Solar, SolarSpace, Trina Solar, and Yingli Solar

This test exposes modules to 1,000 cycles of +1,000 pascal and –1,000 pascal loads at a frequency of three to seven cycles per minute. Measurements were taken after this stress test rate electrical performance.

This year, RETC required that PV module models withstand SDML exposure with less than 2.5% degradation in maximum power. It considered maximum power degradation greater than or equal to 5% to be a red-flag result. In this testing category, it notes that 68% of samples qualified as high achievers whereas 7% returned red-flag results.

Thermal cycling

Top performers: Aptos Solar, Astronergy, ES Foundry, Gstar, JA Solar, Longi Solar, Qcells, Runergy, SolarSpace, Trina Solar, and Yingli Solar

The thermal cycle test calls for cycling modules in an environmental chamber between two temperature extremes—85 C (185 F) on the high end and –40 C (–40F)  on the low end. The RETC test runs 600 cycles, three times as much as the 200 required for certification.

About 67% of modules in this test achieved high performer status of less than 2% power loss, while 9% of tested brands had power losses of 5% or more.

Ultraviolet induced degradation (UVID)

Top performers: Trina Solar and VSUN Solar

UVID tests characterize a PV module’s ability to withstand ultraviolet induced degradation. This optional testing sequence exposes test samples to 220 kWh/m2 of UV exposure (UV220), nearly 15 times the UV exposure required for product certification.

Top performers withstand UV220 exposure with less than 2% degradation in maximum power. Red flag modules that degraded more than 5% represented 40% of brands tested.

“Alarmingly, we observed double-digit power loss in some mass-produced, commercially available PV modules, indicating that these products could degrade 10%–16% in the first three years of in-field operation,” said RETC.

Performance

Module efficiency

Top performers: Astronergy, Mission Solar, Qcells, REC Solar, and Silfab Solar

Module conversion efficiency is determined by dividing a product’s nameplate maximum power rating under standard test conditions by its total aperture area.

RETC has recognized manufacturers of PV module models with conversion efficiencies greater than 21% as test category high achievers. About 56% of tested modules were listed as high performers.

Incidence angle modifier

Top performers: Dehui Solar, ES Foundry, JA Solar, JinkoSolar, Longi Solar, Meyer Burger, Qcells, Runergy, Silfab Solar, and SolarSpace

Incidence angle modifier (IAM) is a performance characteristic that accounts for changes in PV module output based on changing sun angles relative to the plane of the array. To characterize IAM, RETC conducts electrical characterization tests at different incidence angles, ranging from 0° to 90°.

Manufacturers of PV module models with an IAM greater than 88% at a 70° angle of incidence were listed as test category high achievers.

LeTID resistance

Top performers: Astronergy, Gstar, JinkoSolar, Longi Solar, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, Waaree, Yingli Solar

Relatively new cell technologies may experience long-term degradation associated with light exposure and elevated temperatures. This phenomenon, called light- and elevated temperature-induced degradation (LeTID), is tested with a protocol of light soaking, followed by 75 C (167 F) temperature exposure for two 162-hour cycles to identify significant degradation (>5%). Subsequently, test samples are subject to 500 hours of 75 C temperature exposure followed by two additional 162-hour cycles.

Highlighted top performers demonstrated products that had less than 0.5% power loss after 486 hours of exposure.

LID resistance

Top performers: Astronergy, GEP VN, Gstar, JA Solar, JinkoSolar, Longi Solar, Meyer Burger, Qcells, Runergy, SEG Solar, Silfab Solar, SolarSpace, Talesun, Trina Solar, VSUN Solar, Waaree, and Yingli Solar

Light-induced degradation (LID), or power losses from sunlight exposure, affects some PV cell types but not others. PV modules exposed to LID losses rapidly lose performance over the first few hours or days of operation before stabilizing. RETC notes LID resistance is highly correlated with cell type.

RETC required that PV module models withstand the LID sequence with less than or equal to 0.5% degradation in maximum power.

Module efficiency

Top performers: Auxin Solar, JA Solar, Longi Solar, Meyer Burger, Mission Solar, Qcells, REC Solar, Silfab Solar, Trina Solar, Yingli Solar

Module efficiency, or the percentage of incident solar energy converted to electrical energy, is a well-known and key metric for solar performance. It is highly correlated with cell technology and module design.

The top 14 highest scoring modules scored efficiencies of 20% or more. An n-type TOPCon cell scored the highest at 25.8% efficiency, followed by a monocrystalline silicon module with heterojunction technology, recording a 22.4% efficiency.

PAN file

Glass is a unique material used for its chemical stability and visual transparency. It is commonly used in solar panels as a protective outer layer.

In its annual PV Module Index, the Renewable Energy Test Center (RETC) examined emerging issues in solar glass manufacturing and field performance. It found reports of a concerning rise in solar panel glass spontaneously breaking in the field, sometimes even before commissioning.

Teresa Barnes, Ph.D., manages the Photovoltaic Reliability and System Performance Group at the National Renewable Energy Laboratory (NREL). Barnes and her colleagues at NREL reported the issue.

“Spontaneous glass breakage is an example of a failure mode that we didn’t used to see. When I first started working on solar module reliability seven or eight years ago, we mostly heard about glass breakage when there were sloppy operations and maintenance practices,” said Barnes.

Now, this is no longer the case, and the NREL reliability team is regularly receiving reports of glass breakage in silicon modules unrelated to direct damage from maintenance or storm impacts. The team found that over time, the average quality of solar glass appears to be decreasing.

“It used to be the case that modules would pass the IEC 61215 static load test with a big safety factor,” said Barnes. “Today, modules are either barely passing the base static load test or they are not passing with higher safety factors. Some new module designs are simply not passing the minimum static load test.”

The NREL team has begun to hypothesize that glass damage in solar panels is undergoing a similar process to a car windshield in need of replacement. When a windshield takes impact damage, often it only shows up as a small star-shaped mark that seems insignificant. But when extreme weather conditions with very high or low temperatures cycle through, the severity of the damage is fully realized, and suddenly a large crack is visible across the whole surface.

“We think a similar dynamic could be a root cause of spontaneous solar glass breakage,” said Barnes.

This rise in breakage is likely due to the trend solar glass getting thinner over time, said NREL. Mike Pilliod from Central Tension, who spoke at NREL’s 2024 PV Module Reliability Workshop said any manufacturer can temper glass that is 3 mm. But under 3 mm, glass tempering is a difficult process. He said that as glass gets thinner, it takes fewer defects to create strength-limiting flaws in the glass. These flaws are actively being studied by NREL to understand some of the potential pitfalls of using thin glass in solar manufacturing.

Barnes warned that it may be a combination of effects that are making glass breakage a larger threat that before. Modules are getting larger, frames are getting thinner, and mounting rails are getting closer together. All these factors lead to “large, floppy modules” that are putting more pressure on the glass surface, which is also getting thinner in many modules.

The NREL team said at this year’s PV Module Reliability Workshop, manufacturers began speaking about introducing thicker frames and wider mounting positions.

“As people better understand how the module system interacts, they can work to optimize how loads are balanced out,” said Barnes. “The pendulum in that balancing act may already be swinging back toward the integrity of the frame and the mounting rail.”

While some module providers are focused on frames and mounting, others have introduced tempered glass modules that are marketed as hail-hardened and resilient to extreme weather.

RETC asked Barnes about the recent catastrophic losses in Texas, where hailstorms caused hundreds of millions of dollars in damage to operational solar assets.

GCube Insurance, an underwriter for renewable energy, said despite being only 1.4% of total number of insurance claims filed, about 54% of incurred costs of total solar losses can be attributed to hail. This is based on data collected by Gcube over the past five years. Average costs totaled $58 million per claim.

“Ten years ago, people would run you out of the meeting on a rail if you mentioned climate-specific module designs. The consensus was that this would simply be too expensive,” said Barnes. “Now climate specific modules and climate-specific testing are starting to look viable because we are seeing more of an emphasis on total system costs. It is entirely possible that we could see hail-hardened modules, especially in a market like the United States, where it could be worth paying more up front for hail resilience.”

A report from kWh Analytics, a climate insurance provider, released its 6th annual Solar Risk Assessment report, providing a data-driven overview of risks to solar assets. The report included contributions from solar industry leaders in technology, financing, and insurance.

“To meet renewable energy deployment goals, the focus needs to be on smart growth – relying on data to inform decisions and utilizing resilience measures to protect assets,” said kWh Analytics chief executive officer Jason Kaminsky.

The report identified 14 risks to be aware of in the solar industry, including risks related to extreme weather and operational risks. For the first time this year, battery energy storage related risks were included. This news covers the extreme weather risks, with subsequent articles reviewing operational and storage related risks.

Modeling assumptions underestimate losses from weather damage by 300% or more

Data from kWh Analytics found that risk modeling for damage from weather events has been heavily overlooked. Particularly in large solar markets like California, Texas and Arizona, actual ground-up losses from weather events have been as much as 300% or more than what has been modeled by asset owners.

kWh Analytics said that as PV is a relatively new asset class, natural catastrophe models typically used to size insurance premiums often rely on proxy structures to estimate losses. The company said more accurate PV-specific modeling is needed, and differences in technology used (like trackers with hail-stow protection) should be considered in risk modeling.

The insurance provider has developed new models leveraging locational-specific risks, backed by data from the National Renewable Energy Laboratory (NREL), significant loss data and satellite imagery to provide a more accurate risk assessment.

Modules perform well after significant cell damage

Reliability testing from Kiwa PVEL found that broken cells from impacts like hail are less catastrophic to solar module performance than one may expect. No module tested by PVEL lost more than 3% production after undergoing a hail stress sequence.

The testing lab said that rather than relying on expensive electroluminescent (EL) testing, it would recommend that asset owners perform annual aerial thermal scans to identify cracked modules that have developed hotspots and are at risk for fires and in need of replacement. Fire risks are most severe in a rare case that a module with a failed bypass diode has cracked cells.

Modules protected by hail stow post only 0.8% power loss

Waaree found that lab-tested solar modules that tilt to a stowed position to protect from direct hail impacts only lose 0.8% of their production from being in a sub-optimal angle during hail events. In turn, the modules were able to avoid damage altogether by stowing. The losses perform far better than the IEC standard of 5% losses from stowing.

Solar project insurance costs can be reduced by up to 50% by investing in resilient design and maintenance

Data from Alliant Power found that assets in high-risks areas can reduce insurance costs by up to 50% by investing in resilience measures like selecting heat-tempered panels and trackers that enable hail stowing.

“It pays to take time to differentiate your project and select highly qualified partners when it comes to risk and insurance,” said Alliant Insurance Services.

Natural catastrophe events are on the rise, with billion-dollar weather events increasing from an average of 13 per year in the 2010s to an average of 22 per year in the 2020s, with 28 billion-dollar damage weather events occurring in 2023 alone, said Alliant.

Asset damage probability is 87% lower with a 75 degree hail stow tilt

Solar developer Longroad Energy shared a case study under which different tilt angles and their impact on module protection from hail impacts were assessed. The report was based on data from RETC and tracker provider Nextracker.

It found that a 50 degree stow led to a 33% estimated module breakage probability, while 60 degree stow had an 8% probability, and 75 degree stow led to only a 1% risk of breakage from hail.

The next report in this series will review the kWh Analytics assessment of solar asset operational risks.

For more on quality issues in utility-scale solar, sign up for a free webinar on Racking and trackers: quality issues in the factory and design considerations for utility-scale solar installations, June 11 at 11 a.m. ET. Register here.

Recently a hailstorm in Texas caused widespread damage to the Fighting Jays solar facility, a 350 MW site that ranks among the largest in the nation. News reports quickly circulated after the event, warning of the risk of cadmium telluride leaking from the cracked panels and toxifying the nearby water table. 

“My concern is the hail damage that came through and busted these panels – we now have some highly toxic chemicals that could be potentially leaking into our water tables,” Needville, Texas resident Nick Kaminski told Fox News affiliate KRIV-TV. “I have a family — two children and a wife. My neighbors have kids and a lot of other residents in the area who are on well water are concerned that the chemicals are now leaking into our water tables.” 

The Solar Energy Industries Association (SEIA) released a report dispelling these reports, which initially reported false information. 

“There are rumors swirling that the broken solar panels contain cadmium telluride. This is categorically false. The Fighting Jays solar farm was built using crystalline silicon photovoltaic cells, which do not contain that material,” said SEIA. 

Most solar panels installed nationwide are of silicon material, a substance found everywhere in sand and quartz, and built into glassware, countertops, toys and computer equipment. 

“Additionally, even if the panels did contain harmful levels of toxic substances, ‘leakage’ is not possible,” said SEIA. 

SEIA explained that the panels at Flying Jay are laminated between two sheets of sealed transparent plastic, covered in tempered glass, fitted with another layer of plastic or glass on the back, and sealed in an aluminum frame. 

“Even if the glass breaks and is left untouched or unrecycled, it would take decades to extract any type of substance from the broken panels,” said SEIA. 

SEIA has vetted a network of solar panel recyclers that can process 10 million panels per year. Repair and repowering is an option for some facilities, as well. 

However, there is no denying that hail risk is a legitimate issue for the solar industry, particularly for hail-prone regions of Texas. Over the past five years, hail damage has caused more than 50% of total insured project losses, said hail risk expert VDE. Though infrequent, these events can produce record losses. In 2022, hail losses exceeded $300 million in Texas alone.

SEIA pointed out that while solar panels are not immune from natural disasters, neither are their fossil fuel counterparts. Natural gas pump stations and coal piles can freeze, power plants can flood, and storms can force nuclear power plants to shut down for weeks at a time. 

While talking heads have spotlighted the Flying Jays damage as an example of solar unreliability, the storm is still producing power at partial capacity, despite the widespread damage from the peak hail event. Conversely, freezing natural gas facilities were found to be the cause of widespread outages following Winter Storm Uri in 2021, which left thousands without power and caused roughly $130 billion in near-term economic consequences.

The damage at Fighting Jays was widespread, and as hail risk for solar assets intensifies, the industry is moving to tackle this issue. Watch a pv magazine webinar with VDE on the various strategies to reduce hail risk, including choosing the right solar panel for your project, using software controlled stowing mechanisms that tilt the panels away from direct hail impacts, and other strategies. The webinar also concluded with a discussion on the Fighting Jays project and associated toxicity risks with solar panels, including those containing cadmium telluride.

The pv magazine Awards celebrate outstanding achievement across the solar and energy storage supply chain, rewarding excellence and innovation within our industry. Our first entry window is open until April 26, 2024, providing the perfect opportunity to shine a spotlight on the achievements of your business.

Submit your business for consideration in the pv magazine Awards here.

Don’t miss out on your chance to walk away with a coveted prize.

Further details on category criteria and how to enter are available at pv-magazine.com.

We are accepting applications across the following categories:

Modules

Projects

Inverters

Manufacturing

Sustainability

Battery energy storage systems (BESS’)

Balance-of-system (BOS) components

Modules: Risen Energy, Hyper-ion

700 W-plus power output is a notable achievement in any solar module, but the 2023 Modules winner packs a heap of innovation inside to set it apart. Alongside its heterojunction (HJT) cell, Hyper-ion deploys Risen’s own patented version of busbarless (0BB) cell interconnection – branded Hyper-link, cell thickness at an industry-leading 90 to 100 micrometers, and the option of a steel frame to make a module that truly stands out.

The efficiency and power results are also notable. The module datasheet confirms the Hyper-ion comes with a power range of 680-705 W, in dimensions of 2,384 mm x 1,303 mm, at a weight of 41 kg. Inside are 210 mm half-cut HJT cells.

Beyond performance, Risen has beefed up its warranty, putting it ahead of TOPCon rivals. It offers a 15-year product warranty and 30-year power warranty, guaranteeing 90.3% of nominal power output.

Projects: Solar Cooling Engineering, PV Cool Kenya

German company Solar Cooling Engineering (SCE) has taken an innovative approach to refrigeration with its PV Cool Kenya project. SCE has developed solar-powered cooling technology that is based on a sustainable refrigerant (R600a) and insulation materials.

Unlike cold rooms that rely on traditional grid-tied cooling methods, the SelfChill system uses modular thermal storage to balance cooling peaks. Water is chilled and frozen, and stored in a water chiller that provides cold water to a fan coil inside the cold room. In this way, energy fluctuations can be balanced by energy stored in the form of ice.

Battery storage can be added if required, but it is not a necessary component of the system. The cooling unit itself was designed in-house, with SCE opting to create a DC unit that is powered by PV modules.

Inverters: Deye Technologies SUN-29.9-50K-SG01HP3

This year’s winner is Deye Technologies SUN-29.9-50K-SG01HP3 – a hybrid inverter for the C&I market. It is available in power classes from 29 kW to 50 kW and is well-suited to retrofitting. The inverter’s 400 AC output fits with older installations, making it a good candidate for revamping PV plants.

Category juror Cormac Gilligan, director clean energy technology at S&P Global, said there is a growing market for revamping and retrofitting solar systems in Europe with the addition of battery systems to increase self-consumption. He saw the flexibility of the Deye inverter as a noteworthy feature. For example, it can be cascaded into a 500 kW application and work entirely off-grid. The option to connect a diesel genset and charge the batteries that way means this inverter could meet demand in regions where weak grids are prevalent.

Manufacturing: Origami Solar, Roll-formed recycled steel frame

Origami Solar is rolling out production of its patent-pending steel frame design with contract manufacturers in the United States. Frames are expected to be available from the end of 2023.

Frames are manufactured using recycled steel in a continuous process that Origami Solar says is 10 times faster than aluminum frame making, producing one frame every 15 seconds. It also claims frames have demonstrated increased stiffness in testing, making modules better equipped for heavy loading from snow or wind. Further testing is underway with partners including the US National Renewable Energy Laboratory.

On price, the company expects to be able to sell frames at least 5% lower than aluminum competitors. There is a sustainability case to be made, too. Origami Solar has worked with consultants Boundless Impact to demonstrate a significantly lower carbon footprint per module.

Sustainability: ArcelorMittal, XCarb and Magnelis

Multinational steel producer ArcelorMittal claims its XCarb steel is both long lasting and sustainable. XCarb is a certified low-carbon material and the company reports that it is made from predominantly scrap steel, with production carried out via an electrical arc furnace that uses 100% renewable energy.

The steel producer’s Magnelis steel also boasts sustainability credentials. It is long-lived, making it suitable for solar installations in challenging environments. Magnelis steel is a double-sided hot-dip galvanized carbon steel, coated on both sides with a zinc-aluminium magnesium alloy.  “Anything you can do to make a solar asset last longer is a positive climate impact,” said juror Jenny Chase, solar analyst at BloombergNEF.

ArcelorMittal has a target of achieving a 25% reduction in CO2 emissions intensity per ton of crude steel by 2030.

BESS: Fluence, UltrastackTM

The US storage specialist Fluence has developed a storage-as-transmission asset (SATA) that can help network owners and operators to manage renewables curtailment, increase the use of power lines, and limit congestion. UltrastackTM, provides network owners and operators with fast-acting response of less than 150 milliseconds and with higher than 99% system uptime to meet the availability requirements of critical infrastructure. Its advanced control applications, some with pending patents, include synthetic inertia, power oscillation damping control, grid-forming inertia, dynamic voltage control, emergency power contribution, and black start.

Unlike “regular” big batteries, SATA projects are operated to mimic transmission line flows by injecting and absorbing power. In such applications, they can be used to bolster or even replace existing power lines, offering infrastructure planners a new, versatile solution for transmission transition.

BOS: Atonometrics, RDE300i

US-based Atonometrics is targeting utility-scale solar projects with its monitoring innovation, the RDE300i. The system performs in-situ measurement of current/voltage (IV) curves within a string of modules. This allows technicians to get a direct view of the performance of individual modules within an array, and eliminates costs associated with installing and maintaining reference modules at a site.

The manufacturer is keen to point out that in-situ IV curve measurement could be useful on many fronts in plant monitoring, and that it is working with laboratories and industrial partners to develop new applications for the technology.

For now, the use case for RDE300i is focused on monitoring soiling. Here the system promises more accurate results than the common approaches of reference modules or optical sensors – and it can also integrate with these systems so monitoring teams have all bases covered.

Publisher’s Pick: JinkoSolar

It’s high time that we recognize leading module manufacturers in this category and this is no easy task. There is a wealth of module makers with strong track records and impressive product portfolios.

In 2023, the nod goes to JinkoSolar, which has shipped more PV modules than any other manufacturer. In November 2023 JinkoSolar hit the historic mark of 200 GW modules shipped since it delivered its first panels in 2010. The manufacturer has quickly transitioned to n-type TOPCon and the higher efficiencies it offers. In October 2023 the company announced a new n-type TOPCon cell efficiency record of 26.89% for a 182 mm cell.

But JinkoSolar is much more than just a module producer. It has expanded its product portfolio to include battery energy storage systems (BESS) to offer its customers around the world a complete solution involving both state-of-the-art modules and the latest BESS technology.

Enter here for consideration in the 2024 pv magazine Awards.

The global solar market continues to grow, as an estimated 413 GW was installed in 2023, rising 58% year-over-year, according to Bloomberg NEF. Along with this growth comes a rising trend in system underperformance, said a report from Raptor Maps.

Raptor Maps analyzed data collected from drones, robotics, application program interfaces (API) and internet of things (IoT) sensors. The company operates an AI-driven “drone in a box” that it deploys at solar facilities. Its dataset comprises 125 GW of PV assets, spanning 41 countries.

Among the analyzed assets, the company found $177.7 million in preventable annualized revenue losses. Extrapolated to solar assets worldwide, this would equate to $4.6 billion in potential annual revenue losses.

The report found average losses of $4,696 per MW, though losses varied regionally. Since 2019, the average losses from underperformance have increased from a 1.61% average power loss, to 4.47% in 2023. Raptor Maps said this equates to an internal rate of return at loss of at least 190 basis points in a 100 MW solar asset.

One factor in increased average power losses is the increase in average system size. Raptor Maps said larger projects tend to have a higher loss percentage. The Solar Energy Industries Association (SEIA) reports that average solar project sizes have grown from 13.9 MW in 2019 to 59.6 MW in 2023, contributing to increased average losses.

Furthermore, inefficiencies in operations and maintenance are causing potential revenue losses, said the report. In a 2023 survey, the company found “many operators identified preventative maintenance visual inspections as a significant source of time wastage, and a large number of respondents also identified validating nuisance alarms as another way time is wasted.”

Regionally, preventable losses vary widely. In the Midwest, average annual losses were modeled at $4,052 per MW, while in the Northeast, losses exceeded $6,108 per MW. The report noted that asset underperformance losses are lower in the U.S. than the global average.

What causes underperformance?

Raptor Maps identified several sources of power losses. The largest fault, following an historical trend, was at the system level. Inverter faults, string outages, and combiner faults contributed power losses of 1.91%, 0.90%, and 0.81% respectively. Instances of tracker issues have also risen from 0.26% in 2022 to 0.46% in 2023.

Raptor Maps noted that module performance has improved slightly, with losses decreasing by about 12% year-over-year. However, with extreme weather events on the rise, median annual power losses attributed to weather events is about 1%. In certain extreme events, weather related losses can lead to losses of up to 60%, said Raptor Maps. Hail events, particularly in booming solar markets like Texas, are a significant risk for solar asset operations.

Risk profiles vary by module type, said Raptor Maps. Thin-film modules averaged lower power losses from defects and manufacturing anomalies than polycrystalline and monocrystalline. However, thin-film modules were twice as likely to have physical damage as polycrystalline modules, and three-and-a-half times more likely to sustain physical damage than monocrystalline modules.

Find the Raptor Maps 2023 report here.

From pv magazine print edition 3/24

Lithium ion battery energy storage systems (BESS’) have emerged as a dominant energy technology, with gigawatts of capacity installed annually. Analyst Wood Mackenzie has estimated the United States battery market alone could reach 75 GW by 2027. Utility scale grid connections and major technology companies including Google, Amazon, and Microsoft are driving demand as they seek reliable backup power. On site battery storage is becoming a priority for renewables developers keen to better match demand and to hedge against volatile energy prices.

The boom in demand has highlighted concern about potential fires and explosions at battery sites and has sparked debate about mitigation measures.

One approach is to leave BESS’ to freely consume, or “burn” through the stranded energy supply without active protection or suppression systems. This unused system capacity is susceptible to fire risk and with no suppression measures, could extend the duration and severity of a burn event.

Approaches to explosions and fire mitigation focus on spatial separation, robust battery management systems (BMS’), granular thermal runaway sensors, and explosion relief systems.

Mitigating fire risk became a major focus in 2017, following destructive fires in first-generation BESS’ that lacked fire protection or suppression. That prompted new asset-protection systems, with gaseous fire systems proving popular.

Gaseous suppression involves oxygen being removed from battery chambers to stop feeding fires. The other common approach involves spraying assets with water. Each has problems. Gaseous suppression risks reigniting fires with the introduction of oxygen, heightening explosion risk. Water-based systems are limited by the volume of water required to extinguish lengthy blazes.

The United States National Fire Protection Association (NFPA) released industry standards in 2017 recommending sprinkler systems for BESS fire protection. The argument for sprinklers was bolstered by a cascading thermal runaway event in Arizona in 2019 which saw a gaseous-based fire suppression system fail to stop thermal runaway gas generation, leading to explosive conditions in closed containers. The resulting updated standards required the use of sprinklers, with alternatives permitted only subject to approval by insurance companies and building-code officials.

Insurance considerations

The rapid evolution of the BESS industry makes life difficult for insurers, with property insurers considering the battery chemistry and the environment around a BESS. Single-layer BESS’ – versus stacked containers – and spatial separation of units can reduce premiums and client-related terms and conditions. Other factors include a robust BMS, predictive thermal runaway sensors, explosion relief systems, and the efficacy of fire department training programs. Such systems can influence how much project cost is covered by insurance policies.

Insurers and building code officials are divided on whether water-based fire protection systems or the free-burn approach is best. BESS technology is evolving rapidly, as are fire protection systems. To mitigate risk, developers should consider three main factors.

Monitoring matters

BMS’ monitor many variables, including the state of health – remaining useful life – and the state of charge of BESS components, down to module and even cell level. The granular use of BMS’ is critical for staying within safe operating parameters. Subsystems such as thermal management processes monitor and optimize performance, heating or cooling cells when necessary. Software tools such as LionTamer, which detects failing battery cells before thermal runaway occurs, help to mitigate explosion and fire risk.

Spatial separation

Effective explosion relief systems require design conformance to NFPA standards in addition to enough spatial separation between containers or other structures to avoid collateral damage. Adherence to, and the enforcement of, fire and building codes will provide a basis for resilience.

Suppression and protection

It is important to consider the outlook of code officials and of insurance partners. Gaseous suppression and water-based protection systems are still available as a last line of defense. Coolant-based protection systems are currently under consideration as well. Research continues to optimize these approaches. The goal is to buy time to isolate and exhaust combustible and flammable gases while limiting fire spread and collateral damage.

Together, these measures are critical. Asset developers, operators, and owners who incorporate the latest predictive software and engineered safety systems will gain a total-cost-of-risk advantage as the BESS industry matures.

Asset owners who actively manage project risks can, over time, reduce insurance cost increases and avert massive premium spikes following losses. They should work with their brokers to identify insurance providers willing to incorporate resiliency measures into premium pricing assessments. With smart strategies, the BESS boom can charge safely ahead.

About the authors: Bobby McFadden is an underwriter at kWh Analytics. He previously spent eight years in the commercial marine division of Chubb. He has also worked in auditing at PwC and has a certified public accountant license.

Mark Mirek has served on the technical committee of Brown & Brown Risk Solutions since 2016, developing NFPA No. 855, a global energy-storage-system asset protection standard. Mirek has more than 25 years’ experience in insurance and engineering design services.

From pv magazine 2/24

The idea that solar panels would one day be available for €0.10 ($0.11)/Wp of generation capacity would have seemed ludicrous a few years ago. But that was the European Union spot price published by retailer pvXchange for low-cost panels in December 2023.

No matter which price graph you consider, there is a clear, slippery-slope trend. Solar manufacturing has been through a boom, with module demand way beyond supply in what was very much a seller’s market but it’s no secret that the road ahead for solar manufacturing is likely to be rocky. Analysts are predicting a downturn, with crystalline silicon-based manufacturers set to struggle to break even. The consequent casualties may affect solar project warranties.

For manufacturers to maintain margins, or even just to survive, something has to give. Typically, that raises questions about materials supply and manufacturing quality. Similarities to the wind industry spring to mind.

Numerous factors can affect manufacturing processes but the strong association between quality and profitability cannot be ignored.

This might raise an important question for PV project owners. What measures will future-proof projects against issues of module quality?

Quality testing is important to protect revenue, extend product lifetimes, and eliminate warranty-claim inefficiency. Two levers are available to project owners.

Third parties

Certified third parties can be contracted to test PV modules at manufacturer factories or ISO 17025-accredited laboratories.

Sample testing is typically based on ISO 2859-1 standards that use the acceptable quality limit (AQL) methodology. AQL determines whether an order has met client specifications. It defines defects that mean test failure so project owners can reject any given sample.

Additional tests or inspections during construction might also be utilized, including electroluminescence (EL) testing after delivery or installation, via an independent third party.

If a project owner opts against quality control, they face the danger of receiving a batch that another owner has rejected.

Engineer Skyray and consultant Everoze have devised a set of employer’s requirements for engineering, procurement, and construction (EPC) contracts. These include the technical requirements for EPC work, commissioning, and quality testing.

For PV module quality control, a five-step process is required.

Factory inspections

A certified inspector should examine manufacturer facilities, reviewing manufacturing-process quality systems, as well as the procedures for raw material procurement, storage, and component traceability. The production process should also be reviewed. Product quality control should include EL and wet leakage current testing, as well as a pre-shipping visual inspection.

The inspection should include at least a visual inspection and measurement of power output. The following details should be checked or tested on a defined sample of panels: serial number, module type, package number, open circuit voltage, short-circuit current, power at the maximum power point, maximum power point voltage, current at maximum power point, fill factor, test date, record date, and EL testing carried out according to International Electrotechnical Commission (IEC) criteria.

A mechanical data inspection should be carried out to an inspection level based on AQL methodology and should include module and component dimensions, as well as label marking and weight conformity.

Lab results

Manufacturer testing results can be verified by sending random batch samples to a lab for visual inspection, electrical insulation, and EL testing. The latter should detect hot burns, inactive parts, cracks, and micro-cracks, according to criteria agreed with the manufacturer, and maximum power measurement.

A small selection of modules should be subject to potential-induced degradation testing, according to the IEC 62804 standard.

For positively-doped, “p-type” cell technology, such as passivated emitter rear cell (PERC) solar, additional testing may be required to determine susceptibility to light-induced degradation or light-elevated temperature induced degradation.

After shipping

Post-shipping tests determine whether transport conditions are aligned with manufacturer guidelines and can reveal module defects.

Samples should be randomly selected, in accordance with AQL, and IEC 61215-aligned visual inspections performed as well as in situ EL testing to detect defects such as unproductive areas or cell micro-cracks.

Post installation

This stage primarily confirms that construction conditions are aligned with the manufacturer’s guidelines and that modules are free from defects. Similar testing (visual inspection and EL tests) can be carried out on a sample. This is important when determining where defects may have arisen, such as during transportation or installation, and where contractual responsibility lies.

Commissioning issues

Finally, a thermographic survey by drone is recommended to evaluate defects such as bypass diode issues, disconnected strings, or breakages during construction. Solutions are now available for post-treatment data, artificial intelligence-based detection, geolocation of anomalies, and automatic reporting.

The cost of these services has dramatically reduced due to a highly competitive market and rapid technological improvement. Such inspections enable project owners to have a global view of their plant after commissioning and offer many positive benefits.

Although solar development is a technical industry, commercial feasibility underpins its success. Clients not only want to develop technically sound projects but also financially sustainable ones that provide value to shareholders.

With a potentially rocky road ahead, project owners must consider the avenues available to help future-proof their projects. Everoze highlights the fact that thorough module testing can help illuminate the road ahead.

About the authors: Martin Laing has worked with Everoze’s United Kingdom and Ireland solar advisory team since 2019. He has managed technical due diligence transactions involving lenders, investors and developers. Laing has also managed multiple long-term operational monitoring projects.

Gauthier Dambrine is a project manager at Skyray. He has more than 10 years’ experience in solar and wind. Dambrine has held technical positions in the design, development, certification, and installation of solar fixed-tilt and tracking systems in Europe, the Middle East, Africa, and Asia.

Despite the infrequent failures and ‘thermal events’ that are verifiably caused by solar, the hundreds of thousands of solar ecosystem members globally suffer when an issue with a solar site gains media attention. In most cases, a sober root-cause analysis will uncover a relatively minor issue that started a cascade of other, more serious problems. However, most resulting mainstream media coverage and industry scuttlebutt oversimplifies or ignores the root cause entirely; that’s easier to write about, makes for better headlines, gets more clicks, and helps disperse blame.

A similar thing happens with self-driving cars. Of the 6.7 million reported car accidents on U.S. roadways in 2019, only 327 accidents involved self-driving vehicles. Even in the face of this miniscule percentage, the latter received outsized attention in the media and rarely is the coverage truly nuanced.

For the reported thermal events in the United States, fire departments around the nation responded to an average of 346,800 home structure fires from 2015 to 2019. According to the National Fire Protection Association, the top five leading causes of home fires, in order, are cooking, heating, electrical distribution and lighting equipment, intentional fire setting, and smoking materials. Note that electrical distribution includes electrical outlets, outdated/worn electrical wiring, cords and electrical circuits, old appliances, light fixtures, and portable heaters and does not account for rooftop solar systems.

Fires caused by rooftop PV systems are historically underreported, but the Solar Energy Industries Association maintains that spontaneous combustion from a PV system is extremely rare. The quantitative analysis determined an annual fire incident rate of 0.0289 per MW. A 2022 fault tree analysis published in the Journal of Building Engineering revealed that modules, isolators, inverters, and connectors play a significant role in igniting PV fires, with connectors contributing to 17% of incidents.

The reality is that fires found to have been caused by solar equipment are vanishingly rare. Just like how a self-driving car that crashes on the highway makes the evening news, there is no shortage of media attention when there is a presumption that a structure fire was caused by solar. In the face of the challenge of misconceptions about solar equipment, the industry must come to terms with the reality of collective responsibility and modify its behaviors and practices accordingly. The outcome will be fewer bad headlines for solar and a more unified solar sector overall.

Embracing responsibility, together

One of the challenges with attributing responsibility for a problem on a solar installation is the number of companies involved in the value chain. A fertile ecosystem of blamestorming develops when equipment from half a dozen vendors is deployed at an installation, a seventh designs the system, an eighth installs it, a ninth maintains it, and a tenth owns it. In some cases, this number is even larger. For any individual entity, the path of least resistance is to point to one of the others for culpability. In reality, the companies technically all share responsibility. Reputationally, however, the entire solar industry suffers; all are punished.

To protect the next round of growth, the industry must come to terms with the fact that solar is a team sport. Reliable and efficient solar energy systems depend on the expertise of installers and engineering, procurement, and construction (EPC) companies. These installers, in turn, lean on quality system design and skilled labor for their success. Hardware and software providers occupy a pivotal role in delivering solutions that are not only reliable but also user-friendly and feature rich. The points at which the work of these entities intersect, however, have been too transactional for too long.

‘Crosstalk’ and the solar value chain

Since stating a problem without suggesting a (possible) solution is not productive, here is a recommendation for every company involved in the solar industry: According to the Department of Energy (DOE), solar system quality issues fall into three categories: design flaws, faulty installation, and equipment defects. Any possible solution, therefore, should address one, several, or a combination of these three possible causes. A worthy and real example through which to investigate the blame-reputation dialectic is ‘crosstalk.’

Any large electrical system with long wire runs and multiple transmitters is susceptible to crosstalk. The term is solar industry shorthand for electromagnetic interference (EMI), created by the interaction of two or more electromagnetic fields of adjacent energized cables. The phenomenon is present in wired communications in home automation, automobiles, or entertainment systems in commercial buildings and residences.

Crosstalk can be minimized, even eliminated, when several preconditions are met, starting with well-trained engineers who design systems such that crosstalk does not occur. In large-scale C&I solar installations, the most efficient wire layouts often require that home runs to inverters share cable races. When array voltage increases towards the inverter-side of the cable run, as multiple strings come together, the close proximity of these cables can result in mutual EMI radiation. That is not a big issue for shielded cables that only carry current, but this type of interference can cause problems for data communications signals.

The installation process is another node in crosstalk mitigation. Installation teams must be well-trained, follow equipment vendor installation guidelines, use high-quality components, and install those components correctly. For systems that were designed according to crosstalk avoidance strategies but were not installed properly, diagnosis and rework are usually costly, margin-eroding exercises that can foul reputations and sour customer relationships.

The final piece of the quality puzzle is the quality of the products being deployed. Suppliers should have a continuous improvement approach to quality with a systematic root cause corrective action analysis, thorough documentation, and a great support team.

Hanging together

Although a single self-driving car accident damages the reputation of all purveyors of self-driving cars, we do not impugn the automobile industry at large. In reality, self-driving car accidents are rare, just like fires caused by solar equipment. Perception, however, often becomes reality. Every company in the value chain has a role in upholding the reputation of solar energy. And that goes for every step in the solar value chain, too; from engineering, procurement and construction to installation teams and distributors.

By prioritizing quality in design, installation, equipment, and service, we collectively propel the growth and success of solar energy solutions. This shared commitment contributes significantly to paving the way for a more sustainable future powered by the brilliance of solar innovation.

Beyond our close-knit solar community, any hiccups in commercial installations tend to cast a spotlight on ‘solar’ as the culprit. This holds true for the customers we collectively serve. Whether for better or worse, we find ourselves sharing the same ‘solar’ identity, which implies that our fortunes and misfortunes are connected. The solar industry is maturing rapidly, and the quality across every aspect of the value chain is good, but focusing on continuous improvement is critical.

JD Dillon is chief marketing officer at Tigo Energy. His experience spans the U.S. Armed Forces, semiconductors, solid-state drive, and the solar industry. His functional leadership has had an impact on pricing, new product introduction, customer experience, and communications at all levels.

Sinovoltaics, a specialist in quality assurance for the solar and battery energy storage system (BESS) industries, is entering the U.S. market.

The company has developed SELMA (Sinovoltaics EL mass analysiswhich, the company says, inspects 100% of purchased modules for microcracks and other cell-inherent defects. The company offers a quality guarantee underwritten by Munich Re, a global insurance leader.

Called “Zero Risk Solar”, the quality inspection service that uses the company’s AI-driven electroluminescence (EL) analysis to review modules and guarantee that orders are 100% free of microcracks and other defects before shipping. Sinovoltaics reports that If any warranty claim is filed within three years, Sinovoltaics will pay liquidated damages to cover costs, such as de-assembly, manpower, and logistics.

The company has been offering inspection by SELMA since 2020 and it has been implemented at all the major Tier 1 solar manufacturers outside the U.S., the company reports. In 2023 alone, more than 4 million PV modules were inspected. Using SELMA, the company reports that replacement rates of 1% to 3% were common at Tier 1 factories, preventing hundreds of thousands of defective PV modules from being shipped.

“100 percent module inspections is the only way to ensure high performance solar projects,” said Dricus de Rooij, co-founder and CEO of Sinovoltaics. “Our goal is to help solar manufacturers to deliver—and for solar developers to receive—the highest quality solar modules. That’s why Sinovoltaics inspects 100 percent of PV modules and does not rely on sampling methods. Every module is inspected by SELMA and replaced, if necessary, before their clients’ orders leave the factory.

“Our objective is that our clients operate high performing projects for more than 40 years. In the event that a warranty claim occurs on-site, we have skin in the game to compensate our clients through our insurance partner, Munich Re,” de Rooij added.

Sinovoltaics reports that its success is based on its experience auditing more than 200 solar PV module factories, more than 35 energy storage and inverter manufacturing facilities, and inspecting more than 18 GW of solar and storage products at factories across 15+ countries for clients from over 45 countries across 6 continents.

The company’s credentials include certification to ISO 17020, ISO 9001, as well as a CQI/IRCA-accredited and SA8000-certified team of auditors, showcasing its commitment to excellence and rigorous quality standards.

PV Evolution Labs (PVEL), a leading independent test lab for the downstream solar industry, announced it has made several upgrades and expansions to its extended reliability and performance tests for solar modules. 

The test lab expanded its Product Qualification Program (PQP), which has been offering accelerated testing services since 2012. The PQP provides empirical data for PV module benchmarking and project-level energy yield and financial modules to identify top performing PV modules. 

The PQP testing helps inform the company’s annual PV Module Reliability Scorecard, which provides actionable insights for solar module procurement. Find a report on the most recent module reliability scorecard report here. 

“The improvements we’ve made in this PQP update incorporate critical feedback from our downstream partners, research institutes, module and component manufacturers, and our own test results, keeping the PVEL PQP at the forefront of the growing demand for PV module procurement due diligence,” said Tristan Erion-Lorico, vice president of sales and marketing at PVEL. 

Highlights of changes made to the PQP include: 

• A new test to address concerns around ultraviolet induced degradation (UVID) 
• Refocusing the hail stress sequence (HSS) on identifying the threshold of glass breakage 
• Modifying the mechanical stress sequence (MSS) to target module mechanical durability concerns 
• Streamlining processes for light induced degradation (LID), damp heat (DH), light and elevated temperature induced degradation (LETID), and backsheet durability sequence (BDS) testing 

Participation in PVEL’s PQP is voluntary for manufacturers and only top-performing module model types are named in the annual PVEL Scorecard. To date, PVEL has tested over 600 balance-of-materials from more than 70 manufacturers for the PV Module PQP.

“The module buying landscape has changed dramatically in recent years with advancements in module technology and new players entering the market, and in response, PVEL has focused our globally-acclaimed test program on addressing these changes,” said Erion-Lorico.

Erion-Lorico was a recent panelist on the pv magazine Roundtables US 2023 event. The session, which focused on emergent trends in solar cells and module production and adoption, can be viewed in full below.

The quiet shift from central to string inverters in utility-scale solar  Central inverters still dominate the U.S. utility solar market but string inverters are beginning to get more traction in 10+ MW projects.  

U.S., China dominate solar investment China and the United States consistently attract the most annual solar investments. Together, they have received about 50% of all solar investments since 2015, according to a new report by the International Solar Alliance.

Following the passage of the Inflation Reduction Act fifteen months ago, the U.S. is expecting solar module manufacturing to ramp up rapidly. At the pv magazine Roundtables US 2023, experts discussed what to expect in terms of manufacturing capacity, what technologies will be manufactured, and how manufacturers will maintain quality, reliability and durability while growing the domestic industry.

In this session, moderated by pv magazine editor-in-chief Jonathan Gifford, panelists include Theresa Barnes, manager of PV reliability and system performance group at the National Renewable Energy Laboratory (NREL); Mark Culpepper, general manager of solar at Zeitview; Terry Jester, managing director of PI Berlin in North America; and Nicole Thompson, head of data science property insurance with kWh Analytics.

Big floppy modules

One of the notable developments in the PV industry over the last few years has been the adoption of larger modules, which Theresa Barnes said are popular due to high energy yield. These modules offer lower overall cost and higher energy yield. However, she said they tend to be “big floppy modules,” because to make a module that large, some of the components have to be very thin in order to keep the weight down.

As a result, Barnes said that they can be less mechanically durable than smaller modules. “In some cases, that’s okay. But we have to understand that these modules have less room for error, they don’t have this big design safety factor for mechanical loads, that some of the smaller, more stouter, thicker modules used to have” Barnes said.

Unfortunately, NREL is seeing early failures in the field at fairly high rates, which Barnes said is attributed to the glass because with a thinner frame, the glass becomes part of the load structure. Now there’s 2-millimeter glass on the front, compared to 3.2 millimeters in smaller designs. And that glass is heat strengthened, but not fully tempered, because glass can’t be tempered below a certain thickness, Barnes said.

Hail testing and more

In terms of testing of these large-format modules, Terry Jester said PI Berlin’s sister company PVEL is seeing quite a bit of deflection with the center glass modules and that perhaps hailstone testing needs to be stepped up hail-prone regions. Jester said this would move us to a regional series of tests, and that it behooves module manufacturers to look at statistics on hailstones in particular regions and possibly step up internal testing as a result. Once in the field, damage is not always obvious as it does not always end up in the glass, but EL inspection may spot damaged cells.

In addition, large-scale solar plants are being built not just in the sunny south, but also in the central U.S., which experiences more hailstorms than other regions. Nicole Thompson of kWh Analytics pointed to the need for testing and the need to further standards to test for more than 1.8 joules, which she said is equivalent to less than one inch of hail. In addition it’s important for labs to test these modules and quantify the differences between 3.2 millimeter tempered glass and the two millimeter non-tempered glass, Thompson said.

Zeitview conducts aerial inspection of solar installations, completing assessments of about 6,200 assets this year in the U.S. Mark Culpepper said glass crack analysis has become one of Zeitview’s fastest growing services. Cracks can cause both performance and safety issues, and the safety issue could be ground faults. This can occur if a module has a deep crack and then gets rained on. Ground faults can be serious safety issues for crews on site, he said.

While the industry has trained itself to try to cut costs, Culpepper said “I do think there is a point of diminishing returns there,” noting that he thinks the industry is discovering that 3.2-millimeter glass is probably more appropriate than the thinner glass in hail-prone regions.

Gathering data

One of the challenges in figuring out failure rates is lack of data. Thompson said that companies are addressing standardization of data, which will make distinctions between costs of projects, maintenance, resilience and more. She said insurance premiums should reflect that reduction of risks that you have by having a more resilient site.

The data being gathered in the field and in internal testing is extremely important to manufacturers who are putting 25- or 30-year warranties on modules. Jester said that at PI Berlin they spend a lot of time ensuring for clients that modules are built to the standard that’s promised, and gathering data from what’s happening in the field is an essential piece of information.

“Obviously anything you can get from the data that can help feed your decision making both on design and factory operations, I think will only help us as an industry,” she said.

Most of the module manufacturers coming to the U.S. are planning highly automated factories, but as Jester pointed out, automation doesn’t substitute for good practice and good data analysis within four walls of a factory. In addition to automating, they should look at lab reports, field reports, as well as at what the insurance companies are finding, and then then refine the design as appropriate.

“If that design loop can continually feed itself, I think, well, we’ll get stronger as an industry,” she said.

With a huge volume of tax credits available to clean technology manufacturers under the Inflation Reduction Act, the U.S. is beginning to see an influx of solar module makers setting up shop. While the clock is ticking on the opportunity to take advantage of the tax credits, establishing a vertically integrated facility quickly is no small task. At the recent RoundtablesUS 23, Jonathan Gifford, editor-in-chief of pv magazine moderated a panel session that discussed what technologies are best suited to both the rapid rollout and also long-term competitiveness.

Panelists include Alex Barrows, head of PV at Exawatt, Tristan Erion-Lorico, VP of sales and marketing at PVEL, MinWah Leung, senior engineer, solar technology at DNV, and Kim Primerano, vice president, energy and infrastructure development, Estuary Power.

In the panel on how the IRA is changing the landscape of solar manufacturing in the U.S., four experts discussed how realistic it is to reduce our dependence on Chinese imports, what the challenges are for manufacturers in setting up shop in the U.S., how we fill in anticipated gaps in the U.S. supply chain, and more. Alex Barrows kicked off the next panel session by noting that while a lot of module manufacturing announcements have come out, not all will get built. But he estimates that if every company does what they say they intend to do, we could have 90 GW of module capacity by 2026, 20 GW of cells and potentially 20 GW of wafer.

Clearly the mismatch in capacity leaves U.S. manufacturers beholden to importing cells and wafers, which presents a myriad of challenges, not the least of which is for developers to claim the domestic content adder. Erion-Lorico pointed out that there’s a lot to be done, but that there are challenges remain, ranging from the current transformer shortage to the challenge of hiring skilled workers. Erion-Lorico sees the workforce issue as a huge challenge. He estimates that we’ll need 4,000 to 5,000 people to run 100 GW of plants.

The TOPCon choice

With the majority of announced manufacturing facilities intending to produce solar modules, the question is, which module technology will be manufactured. MinWah Leung of DNV said that they see TOPCon as the big player. She thinks that heterojunction (HJT) will play a role in the future, but that TOPCon will be “the main technology, at least in the next few years.”

Leung said there are two pieces that DNV looks for in assessing module quality and risk: One is the design of the module—and what the technology risk is in terms of the design of the module. The second piece is the risk in terms of production quality on the manufacturing side. As DNV specializes in assessing risk, she said that it comes down to extended duration testing, which speaks to the design of the module. To assess manufacturing quality DNV also looks at factory audits, production quality, reports, monitoring, and pre inspection reports.

From the developer’s standpoint, Kim Primerano of Estuary Power said that she is risk averse and she doesn’t “usually like to be the first one off the production line”. While Estuary is closely monitoring the buildout of U.S. solar manufacturing, the company is not currently modeling domestic content. She noted that if the numbers that Barrows was projecting come true, it’ll result in the prices coming down while driving capacity up. At that point, she said, Estuary would start to look at domestically manufactured modules.

In terms of technology choice, however, Primerano said Estuary is definitely looking at TOPCon and planning to use it in an upcoming project. Erion-Lorico spoke of what PVEL is finding in its testing. He said both HJT and TOPCon introduce new risks and there’s a range of results, but over time the modules have industry leading low degradation rates. Developing TOPCon is a sensitive process, and the production window is tighter, he said. But they are seeing great results from factories overseas in PID for TOPCon and they’re seeing great results in thermal cycling in HJT. However, he noted that it’s “a wider range that’s going to take time to tighten”.

Another thing we’re starting to see is U.S.-made encapsulants and backsheets, according to Erion-Lorico, which is a result of the push to onshore the whole solar supply chain. He pointed out that this brings risk as well because manufacturers like Trina have long relationships with materials suppliers, they know how the materials will perform. And yet, to get to that 40% domestic content, some manufacturers will be looking to source materials from new U.S. manufacturing lines.

Automation in manufacturing, installation

With these risks come opportunity. Leung pointed out that we’re seeing a lot more automation not just of factories but of solar construction. She that we are starting to see robot and smart technologies being used for manufacturing, delivery, pile driving, mounting modules, and more. “It’s going to require a lot of coordination in the industry between not just module manufacturers, but also mounting system and inverter manufacturers, to EPCs and developers to see how everything can be automated on a larger scale”.

From a quality standpoint, Erion-Lorico said that PVEL has seen good results in automation of manufacturing, especially with glass glass modules. He added that even with multi-busbar modules, such as TOPCon, cell cracks matter less, so that may help to accelerate these less standard transportation methods. Leung added that a benefit that could result from automation is the standardization of mounting and module equipment so it can be installed more quickly.

“With the amount of solar that all of these renewable energy goals are looking towards, and the acceleration of installation, I think it will necessitate some form of automation in the future, Leung said. “It’s an emerging technology and it’s not perhaps quite there yet.”

Perovskites

Looking at emerging module technologies, Barrows noted that there are a number of companies looking at perovskites, but he doesn’t think they can move fast enough toward commercialization to make use of the IRA incentives. He said we’re likely looking at HJT by in the early 2030s, but there’s definitely still a bit of work to be done.

At the same time, there’s a lot of talk about tandem and about that being a path to domestic content advantage, Erion-Lorico said. “Instead of competing with modules from Southeast Asia or elsewhere, the U.S. is actually bringing back innovation and setting ourselves apart on an efficiency and technology level.” He said he’s bullish on tandems and perovskites—“people are working on it and they want to do it in the U.S., so that’s exciting.”

The drawback with perovskites right now, however, is durability. Erion-Lorico expressed optimism, however, because—just as in developing the rest of the solar supply chain, there are a lot of brilliant minds focused on overcoming the challenges.

In the first part of this series, pv magazine reviewed the productive lifespan of solar panels, which are quite resilient. In this part, we examine residential solar inverters in their various forms, how long they last, and how resilient they are.

The inverter, a device that converts the DC power produced by solar panels into usable AC power, can come in a few different configurations. 

The two main types of inverters in residential applications are string inverters and microinverters. In some applications, string inverters are equipped with module-level power electronics (MLPE) called DC optimizers. Microinverters and DC optimizers are generally used for roofs with shading conditions or sub-optimal orientation (not south-facing).

In applications where the roof has a preferable azimuth (orientation to the sun) and little no shading issues, a string inverter can be a good solution.

String inverters generally come with simplified wiring and a centralized location for easier repairs by solar technicians. Typically they are less expensive, said Solar Reviews. Inverters can typically cost 10-20% of the total solar panel installation, so choosing the right one is important.

How long do they last? 

While solar panels can last 25 to 30 years or more, inverters generally have a shorter life, due to more rapidly aging components. A common source of failure in inverters is the electro-mechanical wear on the capacitor in the inverter. The electrolyte capacitors have a shorter lifetime and age faster than dry components, said Solar Harmonics.

EnergySage said that a typical centralized residential string inverter will last about 10-15 years, and thus will need to be replaced at some point during the panels’ life.

String inverters generally have standard warranties ranging from 5-10 years, many with the option to extend to 20 years. Some solar contracts include free maintenance and monitoring through the term of the contract, so it is wise to evaluate this when selecting inverters.

Microinverters have a longer life, EnergySage said they can often last 25 years, nearly as long as their panel counterparts. Roth Capital Partners said its industry contacts generally report microinverter failures at a substantially lower rate than string inverters, though the upfront cost is generally a bit higher in microinverters.

Microinverters typically have a 20 to 25-year standard warranty included. It should be noted that while microinverters have a long warranty, they are still a relatively new technology from the past ten years or so, and it remains to be seen if the equipment will fulfill its 20+ year promise.

The same goes for DC optimizers, which are typically paired with a centralized string inverter. These components are designed to last for 20-25 years and have a warranty to match that time period.

As for inverter providers, a few brands hold dominant market share. In the United States, Enphase the market leader for microinverters, while SolarEdge leads in string inverters. Tesla has been making waves in the residential string inverter space, taking up market share, though it remains to be seen how much of an impact Tesla’s market entry will make, said an industry note from Roth Capital Partners.

(Read: “U.S. solar installers list Qcells, Enphase as top brands“)

Failures 

A study by kWh Analytics found that 80% of solar array failures occur at the inverter level. There are numerous causes of this.

According to Fallon Solutions, one cause is grid faults. High or low voltage due to grid fault can cause the inverter to stop working, and circuit breakers or fuses can be activated to protect the inverter from high-voltage failure.

Sometimes failure can occur at the MLPE level, where the components of power optimizers are exposed to higher temperatures on the roof. If reduced production is being experienced, it could be a fault in the MLPE.

Installation must be done properly as well. As a rule of thumb, Fallon recommended that the solar panel capacity should be up to 133% of the inverter capacity. If the panels are not properly matched to a right-size inverter, they will not perform efficiently.

Maintenance

To keep an inverter running more efficiently for a longer period, it is recommended to install the device in a cool, dry place with lots of circulating fresh air. Installers should avoid areas with direct sunlight, though specific brands of outdoor inverters are designed to withstand more sunlight than others. And, in multi-inverter installations, it is important to be sure there is proper clearance between each inverter, so that there isn’t heat transfer between inverters.

It is a best practice to inspect the outside of the inverter (if it is accessible) quarterly, making sure there are no physical signs of damage, and all vents and cooling fins are free from dirt and dust.

It is also recommended to schedule an inspection through a licensed solar installer every five years. Inspections typically cost $200-$300, though some solar contracts have free maintenance and monitoring for 20-25 years. During the checkup, the inspector should check inside the inverter for signs of corrosion, damage, or pests.

In the next installment of the series, pv magazine will examine the life of residential battery energy storage applications.

Residential solar panels are often sold with long-term loans or leases, with homeowners entering contracts of 20 years or more. But how long do panels last, and how resilient are they?

Panel life depends on several factors, including climate, module type, and the racking system used, among others. While there isn’t a specific “end date” for a panel per se, loss of production over time often forces equipment retirements.

When deciding whether to keep your panel running 20-30 years in the future, or to look for an upgrade at that time, monitoring output levels is the best way to make an informed decision.

Degradation

The loss of output over time, called degradation, typically lands at about 0.5% each year, according to the National Renewable Energy Laboratory (NREL).

Manufacturers typically consider 25 to 30 years a point at which enough degradation has occurred where it may be time to consider replacing a panel. The industry standard for manufacturing warranties is 25 years on a solar module, said NREL.

Given the 0.5% benchmark annual degradation rate, a 20-year-old panel is capable of producing about 90% of its original capability.

Panel quality can make some impact on degradation rates. NREL reports premium manufacturers like Panasonic and LG have rates of about 0.3% per year, while some brands degrade at rates as high as 0.80%. After 25 years, these premium panels could still produce 93% of their original output, and the higher-degradation example could produce 82.5%.

(Read: “Researchers assess degradation in PV systems older than 15 years“)

A sizeable portion of degradation is attributed to a phenomenon called potential induced degradation (PID), an issue experienced by some, but not all, panels. PID occurs when the panel’s voltage potential and leakage current drive ion mobility within the module between the semiconductor material and other elements of the module, like the glass, mount, or frame. This causes the module’s power output capacity to decline, in some cases significantly.

Some manufacturers build their panels with PID-resistant materials in their glass, encapsulation, and diffusion barriers.

All panels also suffer something called light induced degradation (LID), in which panels lose efficiency within the first hours of being exposed to the sun. LID varies from panel to panel based on the quality of the crystalline silicon wafers, but usually results in a one-time, 1-3% loss in efficiency, said testing laboratory PVEL, PV Evolution Labs.

Weathering 

The exposure to weather conditions is the main driver in panel degradation. Heat is a key factor in both real-time panel performance and degradation over time. Ambient heat negatively affects the performance and efficiency of electrical components, according to NREL.

By checking the manufacturer’s data sheet, a panel’s temperature coefficient can be found, which will demonstrate the panel’s ability to perform in higher temperatures.

The coefficient explains how much real-time efficiency is lost by each degree of Celsius increased above the standard temperature of 25 degrees Celsius. For example, a temperature coefficient of -0.353% means that for every degree Celsius above 25, 0.353% of total production capability is lost.

Heat exchange drives panel degradation through a process called thermal cycling. When it is warm, materials expand, and when the temperature lowers, they contract. This movement slowly causes microcracks to form in the panel over time, lowering output.

In its annual Module Score Card study, PVEL analyzed 36 operational solar projects in India, and found significant impacts from heat degradation. The average annual degradation of the projects landed at 1.47%, but arrays located in colder, mountainous regions degraded at nearly half that rate, at 0.7%.

Proper installation can help deal with heat related issues. Panels should be installed a few inches above the roof, so that convective air can flow beneath and cool the equipment. Light-colored materials can be used in panel construction to limit heat absorption. And components like inverters and combiners, whose performance is particularly sensitive to heat, should be located in shaded areas, suggested CED Greentech. 

Wind is another weather condition that can cause some harm to solar panels. Strong wind can cause flexing of the panels, called dynamic mechanical load. This also causes microcracks in the panels, lowering output. Some racking solutions are optimized for high-wind areas, protecting the panels from strong uplift forces and limiting microcracking. Typically, the manufacturer’s datasheet will provide information on the max winds the panel is able to withstand.

The same goes for snow, which can cover panels during heavier storms, limiting output. Snow can also cause a dynamic mechanical load, degrading the panels. Typically, snow will slide off of panels, as they are slick and run warm, but in some cases a homeowner may decide to clear the snow off the panels. This must be done carefully, as scratching the glass surface of the panel would make a negative impact on output.

(Read: “Tips for keeping your rooftop solar system humming over the long term“)

Degradation is a normal, unavoidable part of a panel’s life. Proper installation, careful snow clearing, and careful panel cleaning can help with output, but ultimately, a solar panel is a technology with no moving parts, requiring very little maintenance.

Standards

To ensure a given panel is likely to live a long life and operate as planned, it must undergo standards testing for certification. Panels are subject to the International Electrotechnical Commission (IEC) testing, which apply to both mono- and polycrystalline panels.

EnergySage said panels that achieve IEC 61215 standard are tested for electrical characteristics like wet leakage currents, and insulation resistance. They under go a mechanical load test for both wind and snow, and climate tests that check for weaknesses to hot spots, UV exposure, humidity-freeze, damp heat, hail impact, and other outdoor exposure.

IEC 61215 also determines a panel’s performance metrics at standard test conditions, including temperature coefficient, open-circuit voltage, and maximum power output.

Also commonly seen on a panel spec sheet is the seal of Underwriters Laboratories (UL), which also provides standards and testing. UL runs climactic and aging tests, as well as the full gamut of safety tests.

Failures 

Solar panel failure happens at a low rate. NREL conducted a study of over 50,000 systems installed in the United States and 4,500 globally between the years of 2000 and 2015. The study found a median failure rate of 5 panels out of 10,000 annually.

Panel failure has improved markedly over time, as it was found that system installed between 1980 and 2000 demonstrated a failure rate double the post-2000 group.

(Read: “Top solar panel brands in performance, reliability and quality“)

System downtime is rarely attributed to panel failure. In fact, a study by kWh Analytics found that 80% of all solar plant downtime is a result of failing inverters, the device that converts the panel’s DC current to usable AC. pv magazine will analyze inverter performance in the next installment of this series.

GAF Energy LLC, headquartered in in San Jose, California has recalled two products following a report of fire and five reports of thermal incidents leading to property damage. The recall was reported by the U.S. Consumer Product Safety Division.

TLS-1 energy shingles and TLS-1 jumper modules have been recalled as electrical components within the shingle are prone to malfunction. Damage to customer roof decks were reported, but no injuries have been sustained from the thermal incidents.

GAF will inspect the electrical components of the shingles for repairs and replace all jumper modules free of charge as result of the recall. About 2,100 units are affected by the recall, and GAF is directly contacting affected customers. The products under recall were solar between November 2021 and April 2023.

GAF’s solar shingle product is a building integrated photovoltaic (BIPV) design that mimics roof shingles. Much like a shingle, it can be nailed to the roof, positioning itself as a solution that can be readily installed by existing roofing companies. The lightweight solar shingles measure 64 inches by 17 inches by 1 inch thick and weigh about 10 lbs.

The Timberline solar shingles are water-shedding and warranted to withstand winds up to 130 mph. The Timberline Solar design achieved UL’s 7103 certification, which authorizes GAF Energy to install the system on residential roofs as a roofing product and a solar energy product, the first of its kind to be recognized as both. In addition, GAF Energy worked with Sandia National Laboratories, a U.S. Department of Energy research and development lab, to verify the product’s strength, durability, and overall market-readiness.

In Summer 2022 the company announced it will open a 450,000 square foot manufacturing facility in Georgetown, Texas, one of the many U.S. solar manufacturing investment announcements over the last year. The facility is expected to create 260 jobs.

From pv magazine Italy

The recent hail storms that occurred in northern Italy have drawn attention to the damage that these sudden and violent atmospheric events can cause to photovoltaic systems. Several system owners have posted photos of damaged plants on social networks, clearly demonstrating the violence of the hailstorms and, above all, the size of the hailstones, which in some cases even reached 20 cm in diameter.

But how big do these grains have to be to damage a photovoltaic system? What can be considered a critical threshold beyond which the damage becomes significant?

pv magazine Italy tried to answer these questions by dusting off a 2019 report by the Vrije Universiteit Amsterdam (VUA) which had investigated the insurance damage data of a historic hailstorm that occurred in June 2016 in the Netherlands.

According to the conclusions of the Dutch researchers, damage to solar panels occurs primarily with hailstones with a maximum size of at least 3 cm. “Larger hailstones (more than 4 cm) cause more damage on average than smaller hailstones, but they also show greater variety in the amount of damage to solar panels,” they explained in the paper “The vulnerability of solar panels to hail.”

Starting at 3 cm, both invisible and visible damage can occur, but starting at 4 cm, the percentage of visible damage increases significantly.

The smallest cracks (microcracks) do not form in the front glass layer but in the silicon, resulting in no reduction of the initial yield. After a few months, however, the damaged areas may begin to show a rapid drop in power, and after about a year the micro-cracks also become visible on the outside of the panel. All damage then reduces the lifespan of a solar panel.

The orientation of the roof relative to the direction of the hail can greatly affect the damage caused by hail to solar panels, the researchers explained, noting that this factor could be even more decisive than the size of the hailstones.

Then there is some empirical evidence – on the other hand, not too significant – that even the angle at which the solar panels are installed can influence the damage to the solar panels. A greater inclination, according to the conclusions of the scientists, would help to moderate the damage.

The study also shows that the frequency of hailstorms is increasing in Europe and the Netherlands, as is the damage caused by hailstorms. This indicates that exposed items, such as solar panels, could become more vulnerable in the future.

“Hail risk and the vulnerability of solar panels to hail should be included in risk models and climate adaptation strategies,” the Dutch researchers concluded.

The Renewable Energy Test Center (RETC) released its 2023 PV Module Index report, evaluating the reliability, quality, and performance of solar panels.

Solar modules are put through a variety of accelerated stress tests to evaluate these parameters. Through comparative test results, project stakeholders can select products best suited for a particular environment, location, or portfolio.

Quality

Hail durability

Top performers: JA Solar, JinkoSolar, Trina Solar

RETC’s hail durability test takes UL and IEC standards testing a step further, exposing solar modules to higher kinetic impact to reflect the risk posed by hail over a 25 or 30 year operating life. In addition to ballistic impact testing, RETC runs thermal cycle and hot-spot tests to reveal potential long-term module degradation.

The top eight performers in this category withstood an effective kinetic energy of 20 Joules or more. These modules effectively demonstrated resistance to a 45 mm (1.8 in.) iceball traveling at a terminal velocity of 30.7 m/s (68.7 mph).

Thresher Test

Top performers: Astronergy, JA Solar Longi Solar, Runergy

The thresher test is a summation of a series of tests that places modules under a variety of vigorous environmental stresses to provide quantitative data behind degradation modes. Power drop, leakage current and visual observations are also made in the test.

The RETC test places backsheets, modules, and connectors through accelerated stresses. Thresher tests include humidity-freeze cycling, thermal cycling, damp heat exposure, static and dynamic load testing, and UV soaking. High performers in this category consistently achieved less than 2% of power degradation.

Performance

LeTID resistance

Top performers: Aptos Solar, Astronergy, JA Solar, Runergy, SEG Solar, Silfab Solar, Solar Space, Trina Solar, Yingli Solar

Relatively new cell technologies may experience long-term degradation associated with light exposure and elevated temperatures. This phenomenon, called light- and elevated temperature-induced degradation (LeTID), is tested with a protocol of light soaking, followed by 75 C (167 F) temperature exposure for two 162-hour cycles to identify significant degradation (>5%). Subsequently, test samples are subject to 500 hours of 75 C temperature exposure followed by two additional 162-hour cycles.

Highlighted top performers demonstrated products that less than 0.75% power loss after 486 hours of exposure.

LID resistance

Top performers: Dehui Solar, Longi Solar, Merlin Solar

Light-induced degradation (LID), or power losses from sunlight exposure, affects some PV cell types but not others. PV modules exposed to LID losses rapidly lose performance over the first few hours or days of operation before stabilizing.

RETC notes LID resistance is highly correlated with cell type. Top performers were all monocrystalline silicon panels and experienced an increase in performance or a modest decrease amounting to less than one tenth of one percent.

Module efficiency

Top performers: Auxin Solar, JA Solar, Longi Solar, Meyer Burger, Mission Solar, Qcells, REC Solar, Silfab Solar, Trina Solar, Yingli Solar

Module efficiency, or the percentage of incident solar energy converted to electrical energy, is a well-known and key metric for solar performance. It is highly correlated with cell technology and module design.

The top 14 highest scoring modules scored efficiencies of 20% or more. An N type TOPCon cell scored the highest at 25.8% efficiency, followed by a monocrystalline silicon module with heterojunction technology, recording a 22.4% efficiency.

PAN file

Top performers: Dehui Solar, JA Solar, Longi Solar, Qcells, Runergy, Yingli Solar

The PAN file test is a module characterization test with 22 parameters set by the PVsyst modeling software. Project developers use PVsyst to evaluate potential sites based on energy production and financial performance.

The assuming filed test conditions of a 10 MW utility-scale solar plant in Midland, Texas with fixed tilt ground mounts and 500 kVA central inverters. Top performers in the PAN test achieved a performance ratio in PVsyst of 85% or greater.

Reliability

Damp heat test

Top performers: Astronergy, JA Solar, Longi Solar, Qcells, Runergy, Trina Solar, Yingli Solar

The RETC thresher test includes a damp heat test that exposes modules for 2,000 hours, double the amount required for product certification. The test evaluates a module’s ability to withstand prolonged exposure to humid, high-temperature environments. Taking place inside an environmental chamber, the test exposes modules to a controlled temperature of 85 C (185 F) and a relative humidity of 85% for a set amount of time.

RETC highlighted performers that experienced less than 2% degradation after this exposure.

PID resistance

Top performers: Astronergy, JA Solar, JinkoSolar, Qcells, Runergy

Potential induced degradation (PID) resistance tests rack-mounted modules in an environmental chamber, which controls temperature and humidity, and exposes them to a voltage bias of several hundred volts with respect to the mounting structure. Typically, exposure times range from 96 hours to as much as 500 hours. PID testing characterizes a module’s ability to withstand degradation due to voltage and current leakage resulting from ion mobility between the semiconductor and other elements in module packaging.

Nearly 28% of the test samples experienced less than 1% degradation over the test period. By comparison, less than 9% of modules achieved greater than 5% power loss.

Static and dynamic mechanical load test

Top performers: Astronergy, JA solar, JinkoSolar, Longi Solar, Runergy, Trina Solar, Yingli Solar

This test exposes modules to 1,000 cycles of +1,000 pascal and –1,000 pascal loads at a frequency of three to seven cycles per minute. Measurements taken after this stress test rate electrical performance.

This year, nearly 47% of the modules that RETC subjected to simulated wind and environmental stresses achieved less than 2% degradation in power. Roughly 17% of the total test samples experienced less than 1% degradation in power after the SDML sequence. RETC notes that the results in this category represent a modest improvement on a year-over-year basis.

Thermal cycling

Top performers: Astronergy, JA Solar, JinkoSolar, Longi Solar, Qcells, Runergy, Saint Gobain, Trina Solar, Yingli Solar

Thermal cycle test calls for cycling modules in an environmental chamber between two temperature extremes—85 C (185 F) on the high end and –40 C (–40F)  on the low end. The RETC test runs 600 cycles, three times as much as the 200 required for certification.

Roughly 80% of modules in this test achieved less than 2% power loss, while only 2.4% had power losses of 4% or more.

Overall top performers

“To identify the best of the best, we reviewed and ranked the overall data distributions across all three disciplines: quality, performance, and reliability. The Overall Results Matrix on the right summarizes the results of this analysis, which highlights eight high achievers based on overall highest achievement in manufacturing,” said RETC.

Top performers (alphabetical order): Astronergy, JA Solar, JinkoSolar, Longi Solar, Qcells, Runergy, Trina Solar, Yingli Solar

Clean Energy Associaties, a clean energy advisory company, performed over 600 safety audits at sites all over the world and found that 97% had safety concerns.

The vast majority of these hazards are caused by poor installation practices, according to CEA. This means most of them can be identified and resolved relatively easily before they lead to fires, safety risks and potentially costly liabilities.

The top ten safety concerns include:

1. Grounding issues
2. Damaged modules
3. Cross-mated connectors
4. Poor terminations
5. Improperly assembled connectors
6. Module hotspots
7. Cables on sharp edges
8. Broken/damaged connectors
9. Water ingress
10. Enclosure hotspots

Nearly half of the sites surveyed had damaged modules caused by incorrect installation or cleaning methods, extreme weather, electrical short circuits in the module or heavy soiling on the modules. And while damaged modules can cause underperformance, they can also cause electrical faults, shock hazards and fire safety risk.

Cross-mated connectors were found in 41% of the sites. This typically occurs due to installer error or a lack of understanding UL-listed connector pairings, or the use of incorrect installation techniques. It can also happen when field-made connectors don’t match the module connector. The effect can be water intrusion or corrosion. Or it can potentially lead to fire from arcing in the connector housing.

Poor terminations were seen at 40% of the sites. The issue can be caused by untrained technicians using the wrong crimp, wrong die, poor wire stripping and/or trimming methods. Poor terminations can arc to one another or to wire clippings within the inverter housing. This can also increase heat at the terminal, causing safety and longevity concerns.

Improperly assembled connectors were found at 40% of the inspected sites, another risk possibly caused by untrained workers or lack of standards. The problem cannot be identified during a visual inspection and requires thermal imaging (shown below) or destructive testing. Left unchecked, poorly assembled connectors can cause extreme thermal signatures that result in safety and reliability issues.

Module hotspots were found in 31% of sites. Hotspots can be caused by manufacturing defects, module shading or soiling or damage during shipment. This issue can lead to voltage mismatch between modules, causing string underperformance. If the modules get too hot they can melt the backsheet, potentially causing arcing or fire.

Cables rubbing against sharp edges were found at 27% of sites surveyed. This can be caused by untrained workers or by weather variations. The expansion and contraction that takes place through seasonal heat changes can cause enough movement to allow sharp edges to eventually cut through the cable installation. Once the conducts is exposed, a short circuit can develop and may lead to fire.

Broken and damaged connectors were found in just over one-quarter of sites. While this can be cause by untrained workers or lack of standards, it can also be caused by prolonged exposure to sunlight, rain, etc.

All installations are expected to resist a certain level of water from rain and snow, however, water ingress was found to be an issue at 26% of sites. This can be caused by improperly installed equipment covers, missing or damaged conduit seals or missing weep holes, leaving no way for water to exit enclosures. Electrical failure and potential thermal events can result, caused by compromised component protection or the creation of unintended electrical paths.

Enclosure hotspots were identified at 19% of sites. These hotspots can be caused by installation problems or from faulty fuses or unsafe system operation. The issue can affect production output, or can risk component breakdown and electrical failure.

Co-authors Chris Chappell, CEA’s senior director of engineering services, and Ankil Sanghvi, engineering manager, will discuss these findings and their experiences inspecting solar rooftops for some of the largest retailers in the U.S. at 1 p.m. EDT June 29, on a free webcast, “From Sunlight to Spotlight: Avoiding Fire Hazards in Your Rooftop Solar Installations.”

The solar industry is forecast to build as much capacity in the next five years as it has over the previous two decades. As the industry matures, risk assessments support the build out of bankable projects that perform at a high level.

This is the motivation behind the annual kWh Analytics Solar Risk Assessment report, now in its fifth year. In the 2023 report, the firm highlights key risks in extreme weather, finance, and asset operations.

“Mitigation of these risks will be critical to our industry’s shared goal: investment of capital into solar to attain sustainable growth,” said Jason Kaminsky, chief executive officer, kWh Analytics. “Doing so will require industry leaders to continue working together as new environmental, technological, legislative, and economic challenges arise.” 

1) Proactive hail stow program can reduce property insurance premiums

Hail is an increasingly prominent issue for PV assets. As more sites are built in the central U.S. “hailstorm alley” and modules trend towards larger formats with thinner glass, the risk for significant damage increases.

Tilting modules to a stowed position to avoid direct hail impact can protect them. However, the stow process is often delayed until hail starts falling, diminishing the effectiveness of the protective measure.

Due to this, a predictive, proactive approach to hail stowing is recommended by many asset operators. Other industry members push against this idea, arguing that hail stowing ahead of time diminishes the total output of the solar array, missing out on productive hours with the optimal angle.

kWh Analytics modeled this scenario, comparing proactive stowing with a no-stow method. Assuming a $22/MWh PPA, moving into hail stow during predicted hail events throughout the year led to a total production loss of $12,000, or 0.1% of the $9.75 million of estimated annual revenue. Meanwhile, this stow program would result in a property insurance premium reduction.

“The choice is clear: stow early and stow often when there is a chance of severe weather near your PV project,” said Nicole Thompson, data scientist, kWh Analytics.

2) Tempered-glass modules are twice as resilient to hail as heat-strengthened glass modules

Renewable Energy Test Center (RETC) runs hail durability tests on various module formats. After a three-year test, the firm found that PV modules with a 3.2 mm tempered front glass over a polymer backsheet are approximately twice as resilient to impact as dual-glass modules with 2.0 mm heat-strengthened glass.

“Using RETC’s HDT (Hail Durability Test) data to identify and select hail-resilient modules, stakeholders can significantly reduce financial risk exposure in hail-prone regions,” said Cherif Kedir, president and chief executive officer, RETC.

“Moreover, hail risk mitigation specialists like VDE Americas can use these impact resiliency data to inform probabilistic financial loss estimates that also consider site-specific hailstorm severity and frequency, tracker-specific defensive stow capabilities, and operator-specific weather-alert response protocols,” said Kedir.

Watch our pv magazine webinar on hail risk mitigation with RETC’s Cherif Kedir and VDE America’s John Sedgwick.

3) Glass/glass modules break twice as much as glass/backsheet

Glass/glass (G//G) modules are gaining popularity due to an industry preference for bifacial modules and are being adopted due to concerns with glass/backsheet (G//BS) reliability. However, G//G modules have been showing risks in breakage from impacts.

“While we have observed that G//G modules have lower mean and median power degradation than G//BS modules in thermal cycling, damp heat, and potential-induced degradation testing, the results for two other critical durability tests present breakage concerns for G//G modules,” said Tristain Erion-Lorico, vice president of sales and marketing, PVEL.

Results from PVEL’s hail stress sequence testing, which launches ice balls at module surfaces, show that 89% of G//G modules experienced broken glass during testing, compared to only 39% for G//BS modules. PVEL’s mechanical stress tests also found a higher rate of breakage for G//G modules.

“Current G//G module designs may not be suited for extreme hail or heavy wind/snow locations. As discussed further in PVEL’s 2023 PV Module Reliability Scorecard, extended testing helps determine which modules to procure for long-term project success,” said Erion-Lorico.

This article, the first of a three-part series, will focus on the extreme weather risks, and next up, pv magazine USA will highlight kWh Analytics’ risk warnings for financial modeling and asset operations.

Each year solar technical advisory and inspection servicer Heliovolta releases a report on solar performance and safety called the SolarGrade PV Health Report.

The report assesses PV health using over 60,000 data points, ranging from projects from 100 kW to 350 MW in size. About 73% of the assessed projects in this year’s report are located on commercial rooftops, 25% are ground-mounted, and 2% are solar carports. All projects are located in the United States.

Heliovolta found some important problem areas for the performance and safety of these solar assets. A staggering 62% of inspected projects were identified to have critical or major issues. Of this share of projects with critical risks, 91% of the major issues were found to be in DC distribution components.

“Issues can be fixed before they become hazardous. Periodic inspections and proactive O&M — especially in the DC distribution section of PV systems — are critical to safe and reliable operations,” said the report.

Heliovolta noted that inverters often appear to be the cause of PV system problems due to the fact they are typically the primary device of energy yield data and error messages. However, on-the-ground data reveals that inverters are rarely the root cause of downtime. In most cases, inverters trip because they detect underlying issues located within the DC Distribution section, said the report.

The report shared that 74% of issues were in the DC distribution section, 9% in racking, 7% in modules, and 7% in inverters.

Within this critical DC distribution system failure are a few specific components driving most of the problems. Over 33% of failures in this system were due to field-made PV connectors. Wire management issues were the second cause of failures and safety issues, about 26% of reported problems. Other problems with conduits, raceways, improper installation, combiner boxes, grounding, and wire terminations were listed as significant risks.

(Read: “Solar assets are underperforming expectations by 8%, what is the root cause?”)

“The most frequently observed issues are related to field-made connectors and wire management. Installer error is typically the root cause for these categories of issue — not defective equipment,” said Heliovolta.

The company said that 79% of all field-made connector issues are caused by improper installation or cross-mating of incompatible parts. Identifying and remediating compromised field-made connectors is critical to safety as they can trigger PV system fires by overheating and by creating arc and ground fault conditions. Heliovolta offers a safety guide to solar connectors.

Interestingly, the report found that 37% of all inverter issues were sourced from one inverter provider. This brand was kept anonymous by Heliovolta in the report.

As for solar module performance, about 30% of problems were related to microcracking. These small cracks restrict the flow of current, reducing energy yield and potentially creating hotspots over time. The report recommends using electroluminescent (EL) imagining tests to detect microcracking.

Heliovolta operates a cloud-based software platform called SolarGrade to help manage the performance and safety inspection process. The company’s report recommended five best practices to ensure a more reliable, productive, and safe solar facility:

1) Require robust installer training

DC distribution issues related to connectors and wire management are the most common problems at project sites. With better training protocols, the vast majority of these issues could be avoided.

2) Conduct QA/WC inspections at commissioning

Assessing EPC workmanship through QA/QC inspections early in a project’s lifecycle helps ensure that latent issues are corrected before catastrophic failures occur.

3) Require inspections during operations and maintenance visits twice a year

Periodically walking project sites to assess PV system health ensures that signs of latent component failure and accelerated degradation are identified early.

4) Standardize inspection processes

Make sure inspectors know what to look for in PV system health assessments by providing standardized, accessible, and easy-to-use guidelines. The SolarGrade platform comes with pre-written templates and issue descriptions.

5) Track issue resolution

Do not allow issues to get lost in the shuffle of PDF reports, spreadsheets, and clunky manual checklists. The SolarGrade platform allows field technicians to quickly find problems on the ground, and asset managers can dynamically track issue resolution in the cloud.

Industry trade association Solar Energy Industries Association (SEIA) announced it has been approved by the American National Standards Institute (ANSI) as an accredited standards development organization.

The accreditation empowers SEIA to convene industry stakeholders to develop national standards for materials, products, processes and services in the U.S. solar and energy storage industry.

Through the development of national standards, SEIA will promote open and efficient markets, working to reduce costs and minimize risks for the industry. Standards encourage the use of best practices across the supply chain, supporting a safe and rapid deployment of projects. Standards also foster shared expectations and trust among customers, businesses, regulators, investors, and other stakeholders.

The organization said it will pursue standards that improve supply chain traceability, consumer protection, and end-of-life or performance period management.

Abigail Ross Hopper, president and chief executive officer, SEIA said:

Strong national standards are the bedrock of any successful industry. Through strong leadership and SEIA’s new ANSI accreditation, we will help the industry proactively and responsibly manage its growth, building confidence among solar customers, businesses and key stakeholders alike. We look forward to creating new industry standards that will propel the industry forward and create a culture of compliance, helping to address PV recycling and provide assurances of ethical practices throughout the solar supply chain.

SEIA is welcoming industry collaboration for the development of standards. It also offers voting memberships in a Standards Technical Committee, enabling participation in the development, review, approval, and publication of SEIA standards. Industry members are also able to publicly review and comment on standards that SEIA publishes. More information on these activities can be found on the SEIA website.

Standards will be developed under a multi-phase consensus process through a diverse coalition of SEIA members and non-members representing producers, users, and general interest categories. The organization’s first Standards Technical Committee will focus on supply chain traceability and said it is planning to release its first American National Standard in early 2024.

PV Evolution Labs (PVEL), an independent test lab for the downstream solar industry and member of the Kiwa Group, published its 2023 PV Module Reliability Scorecard. This year’s Scorecard names 250 model types of PV modules from 35 manufacturers as Top Performers in PVEL’s testing, the most in the company’s history.

The Scorecard summarizes results from the PV Module Product Qualification Program (PQP), a testing regime established by PVEL in 2012 to provide empirical data for PV module benchmarking and project-level energy yield and financial models.

Now in its ninth edition, the Scorecard provides more than just module testing, while its current iteration includes additional factors such as frames, glass, cells, backsheets, encapsulants and junction boxes. In the backsheet category, for example, 24 backsheet models were tested, 47% of which used a backsheet and 53% used rear glass to cover and protect the back of modules.

In terms of module technologies, p-type PERC is still the dominant technology across the Top Performers, TOPCon is also rising to the top. This year there are 37 TOPCon model types listed as Top Performers, up from just one in 2022. Heterojunction (HJT) is also on the rise, with nine HJT modules rated as a Top Performer, compared to just two last year.

Manufacturers of the thirteen top rated modules have had Top Performers for three years in a row. JinkoSolar and Trina Solar have been Top Performers since 2014, while Qcells and REC Solar since 2016.

The 2023 PV Module Reliability Scorecard shows Top Performers for six PQP test categories. To earn the rank of Top Performer, the modules must have < 2% power degradation following the particular test, a threshold that PVEL has used since 2018. For that reliability test they must not have experienced a wet leakage failure, a ‘major’ defect during visual inspection, or a diode failure.

“Solar technology and the manufacturer landscape continue to evolve rapidly, and with module supply issues persisting, buyers need guidance on how to procure the best possible modules for their projects,” said Tristan Erion-Lorico, VP of sales and marketing at PVEL. “Our 2023 Scorecard features a truly global list of module manufacturers. For buyers worldwide looking to understand the critical differences across cell technologies and module designs, our Scorecard provides many key insights and an easy way to search through the best commercially available options for developers.”

While it could seem that overall quality has improved because of the increasing number of Top Performer manufacturers and models, the percentage of manufacturers that experienced a failure also increased. Additionally, almost one third of the bills of materials (BOMs) tested suffered at least one failure during testing, and 15% of BOMs had a failure before stress testing.

Modules tested for the 2023 Scorecard were manufactured in 12 different countries, with sales worldwide. Also included in this year’s Scorecard are case studies from the factory and the field, showing how real-world performance is addressed through reliability testing.

Participation in PVEL’s PQP and Scorecard is voluntary for manufacturers and only top-performing module model types are named in the Scorecard. To date, PVEL has tested over 500 BOMs from more than 60 manufacturers for the PV Module PQP.

The Scorecard is publicly accessible in digital format, and includes a searchable and exportable database. Top Performers can be filtered by PQP test, cell technology, factory location, power class and more. Search results can also be downloaded and exported directly from the site. Access the Scorecard here.

Research from climate insurance and renewable energy risk management firm kWh Analytics shows that solar assets are broadly underperforming by an average of 8%.

On average, projects constructed after 2015 have generated 7 to 13% less electricity than P50 production estimates. P50 means there is a 50% chance in any given year that production will be at least a given amount. If an array has a P50 production level of 500 kWh, it means that on any given year there is a 50% chance that production will be at least 500 kWh. Projects built since 2015 are on average performing worse than those constructed in the early 2010s relative to their P50 estimates.

Drone inspection and imaging provider Raptor Maps estimates annual losses of $82 million for the 24.5 GW of assets it inspected in 2022, at an average of an $3,350 annual loss per megawatt.

“Extrapolating across total global PV capacity (as of the end of 2021, excluding residential) translates to a $ 2.5 billion annual revenue loss for the industry,” the company said.

(Read: “Raptor Maps points to growing problem of PV system underperformance“)

“Underperformance affects investors and lenders critical to the success and growth of solar projects,” said Jason Kaminksy, chief executive officer of kWh Analytics. “As an industry, we must collaborate to find ways to course-correct in order to ensure the industry’s long-term financial health.”

Kaminsky suggests that sponsors and lenders should consider accurately priced risk-transfer products, be wary of aggressive production forecasts, and be collaborative with stakeholders to encourage data sharing.

Forensic analysis

The Renewable Energy Test Center (RETC) recommends conducting a thorough forensic analysis on solar assets to determine the root cause of performance issues. RETC notes that in many cases, inverter failure or inaccurate production estimates are the cause of underperformance. 

However, sometimes PV module health issues can be the reason for falling short of estimates. As an expert source for solar module evaluation, RETC conducts forensic analyses to determine if module performance is the issue. 

The process begins with a baseline assessment. By capturing measurements prior to commercial operations, a baseline forensic assessment provides both short- and long-term benefits over the operating life of a PV power system. For the short term, evaluating panel health can help reduce loan default risk. For the long term, it can help with warranty claims. RETC said processing a warranty or insurance claim without baseline measurements taken at the beginning of the project lifecycle can be challenging. 

Electroluminescence (EL) testing is another forensic analysis technique to ensure module performance. Using a specialized camera system, inspectors can view light emissions that occur when an electrical current moves through solar cells. The test allows technicians to identify installation damages, or damages resulting from severe weather events such as hail, wind or snow. 

While EL testing has been used for a long time by manufacturers in indoor, pre-project settings, RETC takes a different approach by testing the asset while operational in the field. It also has specialized EL technology that allows for daytime testing, advancing from past methods that required nighttime imaging. 

RETC conducts daytime EL testing in the field, which comes with a few benefits. First, this method of EL testing allows technicians to test modules installed on-site, expediting the testing process and preventing cell damage from module removal and handling. Second, RETC’s daytime EL testing eliminates the need to test modules in the dark of night, improving safety and throughput. 

System monitoring and predictive maintenance methods are also recommended for ensuring healthy PV performance. This is especially true for identifying problems as PV systems age. For instance, cell microcracking often does not impact module performance when modules are new, but that is not necessarily the case as systems age. After 5 or 10 years in the field, some modules continue to perform as expected, whereas others suffer from accelerated degradation, said RETC. 

“Thermal mismatch resulting from cracked cells or other causes needs to be closely monitored as it can lead to substantial PV system underperformance,” said Dr. Ralph Romero, managing director, digital infrastructure advisory services, Black & Veatch. 

Large projects that appear to have a single module supplier may integrate modules manufactured using cells sourced from a dozen different vendors, said RETC. Given that each bill of materials is unique, each has a different risk profile. 

Romero said that his company is aware of digital monitoring platforms that can provide powerful, granular insights into system underperformance causes, but in some cases, further analysis is needed. 

“If we suspect that PV modules are underperforming and the root causes are not identifiable through performance monitoring, we can ask the forensic analysis team to identify the root causes of underperformance,” he said. “With this information in hand, we can develop an action plan based on a cost-benefit analysis of potential remediation measures. In the process of engineering a cost-effective solution that immediately improves system performance, we can also take steps to prevent the recurrence of underperformance moving forward.” 

In the first part of this series, pv magazine reviewed the productive lifespan of solar panels, which are quite resilient. In this part, we examine residential solar inverters in their various forms, how long they last, and how resilient they are.

The inverter, a device that converts the DC power produced by solar panels into usable AC power, can come in a few different configurations. 

The two main types of inverters in residential applications are string inverters and microinverters. In some applications, string inverters are equipped with module-level power electronics (MLPE) called DC optimizers. Microinverters and DC optimizers are generally used for roofs with shading conditions or sub-optimal orientation (not south-facing).

In applications where the roof has a preferable azimuth (orientation to the sun) and little no shading issues, a string inverter can be a good solution.

In a string inverter, there is generally less complicated wiring and a centralized location for easier repairs by solar technicians. Typically they are less expensive, said Solar Reviews. Inverters can typically cost 10-20% of the total solar panel installation, so choosing the right one is important.

How long do they last? 

While solar panels can last 25 to 30 years or more, inverters generally have a shorter life, due to more rapidly aging components. A common source of failure in inverters is the electro-mechanical wear on the capacitor in the inverter. The electrolyte capacitors have a shorter lifetime and age faster than dry components, said Solar Harmonics.

EnergySage said that a typical centralized residential string inverter will last about 10-15 years, and thus will need to be replaced at some point during the panels’ life.

String inverters generally have standard warranties ranging from 5-10 years, many with the option to extend to 20 years. Some solar contracts include free maintenance and monitoring through the term of the contract, so it is wise to evaluate this when selecting inverters.

Microinverters have a longer life, EnergySage said they can often last 25 years, nearly as long as their panel counterparts. Usually, these inverters have a 20–25-year standard warranty included. It should be noted that while microinverters have a long warranty, they are still a relatively new technology from the past ten years or so, and it remains to be seen if the equipment will fulfill its 20+ year promise.

The same goes for DC optimizers, which are typically paired with a centralized string inverter. These components are designed to last for 20-25 years and have a warranty to match that time period.

Failures 

A study by kWh Analytics found that 80% of solar array failures occur at the inverter level. There are numerous causes of this.

According to Fallon Solutions, one cause is grid faults. High or low voltage due to grid fault can cause the inverter to stop working, and circuit breakers or fuses can be activated to protect the inverter from high-voltage failure.

Sometimes failure can occur at the MLPE level, where the components of power optimizers are exposed to higher temperatures on the roof. If reduced production is being experienced, it could be a fault in the MLPE.

Installation must be done properly as well. As a rule of thumb, Fallon recommended that the solar panel capacity should be up to 133% of the inverter capacity. If the panels are not properly matched to a right-size inverter, they will not perform efficiently.

Maintenance

To keep an inverter running more efficiently for a longer period, residential installer Those Solar Guys recommended choosing a cool, dry place with lots of circulating fresh air. It also suggested avoiding installing in areas with direct sunlight, though specific brands of outdoor inverters are designed to withstand more sunlight than others. And, in multi-inverter installations, it is important to be sure there is proper clearance between each inverter, so that there isn’t heat transfer between inverters.

Those Solar Guys said it is best practice to inspect the outside of the inverter (if it is accessible) quarterly, making sure there are no physical signs of damage, and all vents and cooling fins are free from dirt and dust.

It is also recommended to schedule an inspection through a licensed solar installer every five years. Inspections typically cost $200-$300, though some solar contracts have free maintenance and monitoring for 20-25 years. During the checkup, the inspector should check inside the inverter for signs of corrosion, damage, or pests.

In the next installment of the series, pv magazine will examine the life of residential battery energy storage applications.

Residential solar panels are often sold with long-term loans or leases, with homeowners entering contracts of 20 years or more. But how long do panels last, and how resilient are they?

Panel life depends on several factors, including climate, module type, and the racking system used, among others. While there isn’t a specific “end date” for a panel per se, loss of production over time often forces equipment retirements.

When deciding whether to keep your panel running 20-30 years in the future, or to look for an upgrade at that time, monitoring output levels is the best way to make an informed decision.

Degradation

The loss of output over time, called degradation, typically lands at about 0.5% each year, according to the National Renewable Energy Laboratory (NREL).

Manufacturers typically consider 25 to 30 years a point at which enough degradation has occurred where it may be time to consider replacing a panel. The industry standard for manufacturing warranties is 25 years on a solar module, said NREL.

Given the 0.5% benchmark annual degradation rate, a 20-year-old panel is capable of producing about 90% of its original capability.

Panel quality can make some impact on degradation rates. NREL reports premium manufacturers like Panasonic and LG have rates of about 0.3% per year, while some brands degrade at rates as high as 0.80%. After 25 years, these premium panels could still produce 93% of their original output, and the higher-degradation example could produce 82.5%.

A sizeable portion of degradation is attributed to a phenomenon called potential induced degradation (PID), an issue experienced by some, but not all, panels. PID occurs when the panel’s voltage potential and leakage current drive ion mobility within the module between the semiconductor material and other elements of the module, like the glass, mount, or frame. This causes the module’s power output capacity to decline, in some cases significantly.

Some manufacturers build their panels with PID-resistant materials in their glass, encapsulation, and diffusion barriers.

All panels also suffer something called light induced degradation (LID), in which panels lose efficiency within the first hours of being exposed to the sun. LID varies from panel to panel based on the quality of the crystalline silicon wafers, but usually results in a one-time, 1-3% loss in efficiency, said testing laboratory PVEL, PV Evolution Labs.

Weathering 

The exposure to weather conditions is the main driver in panel degradation. Heat is a key factor in both real-time panel performance and degradation over time. Ambient heat negatively affects the performance and efficiency of electrical components, according to NREL.

By checking the manufacturer’s data sheet, a panel’s temperature coefficient can be found, which will demonstrate the panel’s ability to perform in higher temperatures.

The coefficient explains how much real-time efficiency is lost by each degree of Celsius increased above the standard temperature of 25 degrees Celsius. For example, a temperature coefficient of -0.353% means that for every degree Celsius above 25, 0.353% of total production capability is lost.

Heat exchange drives panel degradation through a process called thermal cycling. When it is warm, materials expand, and when the temperature lowers, they contract. This movement slowly causes microcracks to form in the panel over time, lowering output.

In its annual Module Score Card study, PVEL analyzed 36 operational solar projects in India, and found significant impacts from heat degradation. The average annual degradation of the projects landed at 1.47%, but arrays located in colder, mountainous regions degraded at nearly half that rate, at 0.7%.

Proper installation can help deal with heat related issues. Panels should be installed a few inches above the roof, so that convective air can flow beneath and cool the equipment. Light-colored materials can be used in panel construction to limit heat absorption. And components like inverters and combiners, whose performance is particularly sensitive to heat, should be located in shaded areas, suggested CED Greentech. 

Wind is another weather condition that can cause some harm to solar panels. Strong wind can cause flexing of the panels, called dynamic mechanical load. This also causes microcracks in the panels, lowering output. Some racking solutions are optimized for high-wind areas, protecting the panels from strong uplift forces and limiting microcracking. Typically, the manufacturer’s datasheet will provide information on the max winds the panel is able to withstand.

The same goes for snow, which can cover panels during heavier storms, limiting output. Snow can also cause a dynamic mechanical load, degrading the panels. Typically, snow will slide off of panels, as they are slick and run warm, but in some cases a homeowner may decide to clear the snow off the panels. This must be done carefully, as scratching the glass surface of the panel would make a negative impact on output.

(Read: “Tips for keeping your rooftop solar system humming over the long term“)

Degradation is a normal, unavoidable part of a panel’s life. Proper installation, careful snow clearing, and careful panel cleaning can help with output, but ultimately, a solar panel is a technology with no moving parts, requiring very little maintenance.

Standards

To ensure a given panel is likely to live a long life and operate as planned, it must undergo standards testing for certification. Panels are subject to the International Electrotechnical Commission (IEC) testing, which apply to both mono- and polycrystalline panels.

EnergySage said panels that achieve IEC 61215 standard are tested for electrical characteristics like wet leakage currents, and insulation resistance. They under go a mechanical load test for both wind and snow, and climate tests that check for weaknesses to hot spots, UV exposure, humidity-freeze, damp heat, hail impact, and other outdoor exposure.

IEC 61215 also determines a panel’s performance metrics at standard test conditions, including temperature coefficient, open-circuit voltage, and maximum power output.

Also commonly seen on a panel spec sheet is the seal of Underwriters Laboratories (UL), which also provides standards and testing. UL runs climactic and aging tests, as well as the full gamut of safety tests.

Failures 

Solar panel failure happens at a low rate. NREL conducted a study of over 50,000 systems installed in the United States and 4,500 globally between the years of 2000 and 2015. The study found a median failure rate of 5 panels out of 10,000 annually.

Panel failure has improved markedly over time, as it was found that system installed between 1980 and 2000 demonstrated a failure rate double the post-2000 group.

System downtime is rarely attributed to panel failure. In fact, a study by kWh Analytics found that 80% of all solar plant downtime is a result of failing inverters, the device that converts the panel’s DC current to usable AC. pv magazine will analyze inverter performance in the next installment of this series.

Solar asset managers such as SMA, the German company known for its smart solar technology, are finding that aerial inspections using drones and manned aircraft are the optimal way of managing and maintaining large solar installations.

SMA has O&M contracts for over 1,000 sites, from small commercial of 30 kW and up to large-scale installations of over 600 MW. The company has been managing assets since 2015 and since then much has changed in terms of the technology and techniques used.

Today they are using drones and manned aircraft to conduct thermal and visual inspections of modules, looking for defects or modules or strings or groups that may be offline. In the course of inspection, they may see, for example, strings, modules and sections offline because an inverters not running, but the majority of the time the imaging is finding broken modules or hot spots on modules.

pv magazine spoke with Mark Culpepper, general manager solar solutions with DroneBase, a global company that specializes in data captured through aerial imaging. DroneBase serves a range of industries including wind energy, insurance, construction, real estate, and more—but the solar industry has increasing become a focus as solar assets increase across the globe.

Aerial inspections have great benefits in the solar industry not the least of which is speed. An unmanned drone can inspect about 20 MW per day per drone operator for on-demand thermal inspections or spot checks, while manned aircraft can capture over 500 MW in a 4-hour period. SMA uses both unmanned drones and airplanes to complete its inspections, finding aerial imaging far superior to “the old way” of doing things, which was manual inspection.

What’s the difference between the two? “It comes down to picking the right tool for the job,” says Culpepper. “Drones are the best tool for spot checks of solar energy systems. We use manned aircraft for two reasons: for annual health scans of systems and to capture images of large projects and portfolios.”

DroneBase recently announced its North American Solar Scan program, which flies each spring and fall and cover every major solar market in both Canada, including Ontario, and the United States, including California, Nevada, Colorado, Texas, Florida, North Carolina, South Carolina, Illinois, Massachusetts, and more.

Manual inspection required an inspector to go into the field and, using an I-V curve tracer, the inspector would go inside each combiner box, check every string while it’s operating, check every string after they pull the fuse out and see where it’s sitting, etc. Jamie Mordarski, Director, O&M Americas at SMA America, told pv magazine USA that the problem with manual inspection is time.

“It takes anywhere between 15 to 25 minutes per combiner box and if you have a site that has a combiner box with say 1200 combiners boxes, that’s 400 man hours.” He added that in addition to the time it takes, manual inspection doesn’t tell you what the problem is or what module it is. The inspector would have to isolate the string to figure out which module it is.  With a thermal aerial scan, a 600 MW site can be done in 5 hours.

Mordarski said that seven years ago when SMA started using aerial imaging it was not something that every solar asset owner was doing. When he saw what aerial imaging companies like DroneBase could do and how beneficial it was, he knew it was better than going out into the field with a meter. “As people are starting to see more aerial inspection, they realize it’s better, cheaper, quicker, easier,” said Mordarski. “Doing it the old way just doesn’t make sense.”

To conduct its inspection, SMA uses a combination of drones and manned aircraft. Many of the inspections they can do with their own pilots and drones/airplanes, and for very large or highly concentrated portfolios they hire DroneBase. Even when SMA does its own inspections, it supplies SMA’s raw data to DroneBase to complete the analysis.

Technological advancements

Dramatic changes have occured in the technology in the seven years that SMA has been conducting aerial thermal imaging inspections. Mordarski said that there were not off-the-shelf drones back then, and the inspection companies that SMA was working were getting custom built drones from Europe and adding off-the-shelf thermal images that weren’t really made for drones. Some were even using GoPro cameras that they’d strap to the drone. Now drones are made with high-resolution thermal imagers on them natively so you don’t need two separate cameras. They are also capable of doing automated patterns, where you draw a box on a map, set your parameters and off you go. “It does it by itself,” said Mordarski.

Inspections of solar assets by manned aircraft is also becoming more common. It used to be that the drones got better resolution because they fly closer to the solar installations than planes, which have to fly higher. Mordarski pointed out that today you can get the same resolution from the plane as from the drone as long as you’re flying at the right altitude. “The technology has improved, speed has improved, quality has improved, and the cost per engagement has gone down.”

From niche to mainstream

In just a few years, aerial inspection of solar assets has gone from a niche application to mainstream use. Technology has advanced dramatically in the intervening years, and cameras and imaging continues to advance, along with new ways of analyzing the data. For example, DroneBase recently acquired India-based AirProbe, a specialist in drones using artificial intelligence in its analytics. As a result of these new capabilities, DroneBase is expanding its offering to include construction progress monitoring, serial ID mapping, and advanced shade analysis. Overall, aerial inspection has gotten to the point where “everyone has to do it,” said Mordarski. The bottom line, according to Mordarski is that using aerial thermography and high-resolution visual inspection is somewhere between 10x lower cost and 30x as fast as doing it by manually. For SMA, there’s no going back.

Norwegian classification society DNV is aiming to develop the world’s first recommended practice on the design, development, and operation of floating solar photovoltaic (FPV) systems.

The independent energy expert and assurance provider estimates that the potential global capacity for deploying FPV power is currently around 4 TW and expects installed capacity to reach 10 GW worldwide by 2025.

The group points out, however, that standards applicable to FPV are still largely lacking, which could result in project delays and obstacles in permitting and authorization of utility-scale projects.

“FPV players are at best relying on inconsistent and diverse procedures and adjacent codes adopted from other sectors, which may hinder the industry’s capacity to rapidly scale up,” DNV notes.

In an effort to provide comprehensive guidance to FPV operators, DNV has taken the lead on two new joint industry projects (JIPs) to achieve FPV-specific reference standards. DNV previously spearheaded a JIP involving 24 of the sector’s leaders to develop the world’s first recommended practice (RP) on the design, development, and operation of FPV systems — DNV-RP-0584 — which was introduced in 2021 as the first step towards FPV standards and certification. FPV-specific reference standards will further enable companies to manage risks and facilitate the shift to renewables, according to DNV.

The first new JIP is to share and improve the best practices for the design of FPV-specific anchoring and mooring structures. Based on a selection of floating solar concepts, the project will address a variety of anticipated challenges when deploying installations in larger islands with shallow drafts. The second JIP would draw from DNV’s expertise and network to create “an adequate unified FPV-specific floats design, testing and qualification standard that will introduce clearer, faster and cheaper performance-based procedures that are layout-neutral and failure-mode-specific.”

Many water bodies remain largely available for power generation – making the business case for FPV extremely attractive. After a slow start, the FPV market grew to 2 GW of globally installed capacity in 2020. DNV foresees a total of 7 to 11 GW to be installed by 2025 with a major increase from 2023 onwards.

“The use of industry standards will ultimately lead to higher quality, lower failure rates and more adequate access to data-driven digital solutions and assurance services like verification and certification,” said Juan Carlos Arévalo, executive vice president at GPM&S, a DNV company. “This can only be achieved through joint efforts and continuous knowledge sharing. This will not lead to the convergence of floating solar photovoltaic technology into a dominant concept, but rather establish a common approach to analysis and simulation that allows players to consistently improve on one another’s best practices and lay out industry-wide testing and quality assurance procedures.”

Dana Olson, global segment lead for solar power, Energy Systems at DNV, added, “FPV structures present unique challenges to the solar industry due to specific hydrodynamic loads, risks of corrosion and specific components, such as floats, anchors and mooring lines.

“Several large customers in the solar community have requested that we develop new, tailored standards to guide them in the development of resilient FPV projects,” Olson added. “In particular, our input on the determination of design environmental loading will provide crucial guidance to the whole field, and we’re eager to engage directly with customers across the industry at this crucial step of FPV project development.”

Over time, light-elevated temperature-induced degradation (LETID) can cause significant performance losses in PV modules in the field. The problem was first recognized around 2012; the industry did not know the exact cause behind it, but it has been quick to develop mitigation strategies.

Understanding the effectiveness of these strategies, and ultimately eliminating performance losses associated with LETID, requires comprehensive testing. Such testing is increasingly a requirement for module buyers wary of the financial impacts of unexpected performance losses.

A collaborative effort between scientists and industrial players across Asia, Europe and the United States has tested a range of silicon PV modules for LETID, with the aim of developing a new, applicable protocol. Their findings and the testing procedures they used will likely be adopted into a formal standard published by the International Electrotechnical Commission later this year.

“Global researchers have published many promising strategies for reducing or eliminating LETID, and there is evidence both in this work and elsewhere that manufacturers in recent years have adopted these strategies,” said Joseph Karas, a researcher at the US National Renewable Energy Laboratory. “Some modules in this work showed essentially no LETID sensitivity. Still, LETID risk is not a fully resolved matter as new wafer types and cell architectures are being adopted which might be LETID-sensitive.”

Standardized testing

The group described the testing procedures in “Results from an international interlaboratory study on light- and elevated temperature-induced degradation in solar modules,” which was recently published in Progress in Photovoltaics. The procedures primarily involve subjecting modules to high temperatures, and either directly injecting a current, or placing them under simulated sunlight at different levels, either to cause LETID degradation or initiate a recovery mechanism in already degraded modules.

By fabricating intentionally LETID sensitive modules, they were able to calibrate the procedures to maximize LETID, and could distinguish such losses from other issues. Testing was conducted over a period of four weeks, but the researchers noted that in the soon-to-be-published standard, this will be reduced to two, with a doubling of the injected current to compensate.

“This work, the forthcoming TS, and the advancing scientific understanding of LETID will help mitigate the physical and financial effects of LETID,” the researchers said. “Manufacturers will be able to test for LETID and engineer LETID-free cells and modules, module buyers will be able to evaluate potential purchases with confidence, and financial stakeholders will benefit from the reduced risk that follows from that confidence.”

It might lead to effective mitigation or even the elimination of LETID effects, but the work will nonetheless continue, so the industry can fully understand the mechanisms behind the problem. In this project, the group found differing impacts on fill factor between modules, and significant variations in LETID between individual cells within single modules – neither of which it could immediately explain.

In November 2021, Gibraltar’s RBI Solar, SolarBOS, Sunfig and TerraSmart legacy brands announced that they would be unifying under a single brand and identity, Terrasmart, to deliver seamless solutions across the solar project lifecycle, in order to mitigate risks, streamline development, and create unified solutions for customers, according to the company.

However, laying out goals and actively working and making progress on achieving them are two different things all together, so pv magazine sat down with Terrasmart President, Ed McKiernan to discuss the implications of the integration, ideas behind the new identity, and his company’s vision of their role in the US’ transition to renewable energy.

“Customers need options,” said McKiernan. “They need options to figure out what the right solution set is. And then once they figure that out, they need sort of a box of Lego bricks that’s flexible enough that they can fit it one way or another, because they’re not going to do the same cookie-cutter project every single time. That’s what led us to even start thinking about acquiring other companies to add together.”

This idea of options, and more so one centralized offering that can bring all of the different services that the Terrasmart brand now offers into one experience, has been part of Gibraltar’s long-term vision of their place in the US energy landscape since long before the idea of consolidating and unifying their brands was proposed.

Gibraltar first entered the solar space in 2015 when it acquired RBI Solar, a mounting solutions provider for commercial, utility-scale, and carport solar projects. That acquisition was followed by the 2018 purchase of SolarBOS, an electrical balance-of-systems company. The company kicked off 2021 by acquiring Sunfig, a project software services company, for $3.75 million. A short time later, Gibraltar paid $220 million for TerraSmart, which provides screw-based, ground-mount solar racking technology, and the pieces for what would soon become the new Terrasmart were all put into place.

These acquisitions all provided an opportunity for Gibraltar to expand its footprint in the U.S. market by becoming an end-to-end, turnkey provider of ground-mount infrastructure, tracker tech, and design software, but the solution still needed identity.

Why Terrasmart?

If you’re four brands, then the first message you’ve given your own employees is hold on to that legacy identity,” said McKiernan. “Just changing the logo, just changing the name, that is not sufficient, the rest of it goes to aligning your employees around the strategy, helping them to understand why we’re making that change, and then looking at our daily operating behaviors, and changing so that when customers look for that experience, we can support it.”

Part of the decision came down to the idea that, even if these legacy brands were all inter-operating and working with the same customers, the landscape of different teams and identities, to customers, would feel the same as working with four entirely unrelated companies.

“If we had stayed as we were before, we would just be misaligned with our strategy and not giving our customers what they wanted,” asserted McKiernan. “It’s the power of changing the brand that’s on your email, the halls of the building you walk through, the clothing you wear, the products you sell, changing everything. What we do individually doesn’t matter as much as what we do collectively.”

Terrasmart, the brand’s chosen identity, comes with a dual meaning. The first is a literal translation of the name Terrasmart — earth smart — which is how the company sees solar: a smart solution, not just for customers and energy buyers, but for the planet. A smarter choice in energy for the earth.

The way the company looks to present this value outwardly is through its broad, technology-agnostic portfolio of hardware and services. The company’s paramount goal is to be able to plug and play whatever solution is required for the best solution on every site – no matter the condition.

Since the initial rebranding, McKiernan has identified another meaning behind the name, a natural extension of the first’s philosophy: not just doing smart things for the earth, but with the earth. According to McKiernan, this comes down to getting the most out of every project site and variable condition that they can, in order to deliver an optimized project to the customer.

Their products interact and have a relationship with the earth, and the vision is to utilize the land they have to the fullest, in order to deliver the cleanest solution possible.

Areas of innovation

For Terrasmart to achieve its goal of being a one-stop solution provider of solar projects for its customers, McKiernan shares that Terrasmart has targeted four areas of development and focus: developing and innovating its tracker platform, advancing its balance of systems wiring solutions, developing additional intelligent operation options for trackers, and starting work on some of the company’s futuristic ideas, which include hybrid approaches combining elements of trackers and fixed-tilt racking, as well as reducing the amount of steel the company uses in its solutions.

The aspect of steel usage is an interesting one for Terrasmart, as the company fabricates its own steel structures in house. The reason is that this allows Terrasmart to switch up their operations “on a dime,” as McKiernan puts it, in order to accomodate design and timeline changes for customers.

Sourcing the steel to enable this process, however, has become more challenging.

“In today’s environment, being able to buy steel from the right people is very hard to do,” said McKiernan. “There’s not any excess capacity in the steel industry. If you’re on the outside looking in, you might have to go halfway around the world to get your steel. That would be a big problem between duties and freight to get it. And then of course, your ability to react to changing project schedules, if that’s where you’re pulling your steel from, is very challenged.”

Operating in the US

Despite the size of the company and scope of operations, Terrasmart has and will continue to dedicate its efforts in the US renewable energy space, driven by the company’s “Power of Focus” philosophy and the idea that less is more.

“If you look at RBI Solar, and the legacy TerraSmart businesses that were started in the late 2000s, they are massive in the racking space,” explained McKiernan. “They are truly founders in the space and feel a lot of responsibility that we can’t take our eye off the ball in the US to go figure out how to execute internationally.”

Could the company expand to offer its services across the Atlantic or Pacific, sure, but what’s harder to establish overseas is the start-to-finish solar system experience that the company is developing. Moving internationally, the company would become a step in the development process. When the vision is to become the process, stepping out of that framework because singular opportunities arrive here or there weakens the overall mission.

“The customers that have brought us to this point are here in the US,” said McKiernan. “They demand a lot from us and we take those obligations very seriously. Our strategy is to grow with them, and we think that, you know, we would be penny wise and pound foolish by chasing opportunities on foreign soil.”

The energy storage decade has arrived, BNEF says. Falling battery costs and “surging” renewables penetration make energy storage a “compelling flexible resource in many power systems.”

A guide to addressing fire risks in rooftop solar. More than 90% of inspected rooftops had significant safety and fire risks. Here’s how to protect your solar asset.

Solar anti-dumping group said it is weighing options, may refile petitions seeking tariffs. A-SMACC urged Commerce Department officials to consider launching their own circumvention actions and trade cases on behalf of the U.S. solar industry.

Solar project now powers five New England colleges. The arrangement links colleges in a 20-year power purchase agreement that mirrors corporate-style renewable sourcing strategies.

Costs for all types of PV systems continue to fall, NREL benchmark report says. In a change from previous years’ reports, however, balance of systems costs have increased or remained flat across sectors in 2021.

Investors, developers, and asset owners with commercially procured solar inverters may collaborate with PV Evolution Labs (PVEL) on its Crowd Power Product Qualification Program (PQP).

The program, which does not require manufacturer participation, conducts tests on inverters to develop data that can help mitigate technology risks and quantify product performance.

“Third-party data for inverters is notoriously difficult to obtain from manufacturers,” said C.J. Colavito, VP of engineering at Standard Solar. The Crowd Power PQP is intended to address this data access issue.

The tests largely mirror PVEL’s inverter PQP, which was introduced in 2014. Both programs include safety, reliability, and performance testing under varying environmental and interconnection conditions.

(Read: “How long do residential solar inverters last?”)

As designed, the PQP will generate data sheet validation for what PVEL said would be more accurate performance and revenue models, reliability evaluations for improved operations and maintenance cost and replacement rate forecast accuracy. It will also provide safety assessments for arc and ground fault detection.

The crowdsourced testing is intended to offer inverter buyers an opportunity to leverage empirical data over the claims of product marketing materials, said PVEL. Ginlong Solis and Chint Power Systems recently submitted 250+ kWh inverters for the traditional PQP, but PVEL said most inverter suppliers do not engage in independent testing that exceeds certification standards.

By contrast, solar module manufacturers more readily take part in PVEL’s PQP. Since 2012, some 50 panel makers have tested their panels with PVEL. Around 25 undergo frequent periodic testing. PVEL said module reliability has improved since the PQP launch. It said that its thermal cycling test has shown an average degradation rate reduction of 70% over that time.

In the first part of this series, pv magazine reviewed the productive lifespan of solar panels, which are quite resilient. In this part, we examine residential solar inverters in their various forms, how long they last, and how resilient they are.

The inverter, a device that converts the DC power produced by solar panels into usable AC power, can come in a few different configurations. 

The two main types of inverters in residential applications are string inverters and microinverters. In some applications, string inverters are equipped with module-level power electronics (MLPE) called DC optimizers. Microinverters and DC optimizers are generally used for roofs with shading conditions or sub-optimal orientation (not south-facing).

The technology ensures that each panel produces its max capability real-time and isn’t limited to the weakest link in the chain or “string.” String inverters are subject to the “Christmas light” effect where if one panel is not performing or is shaded, the rest of the panels connected in series will be limited to that panel’s production level.

Some string inverters are equipped with a bypass diode, a technology that prevents the “Christmas light” effect from taking place altogether, shown here by Fronius.

In applications where the roof has a preferable azimuth (orientation to the sun) and little no shading issues, a string inverter can be a good solution.

In a string inverter, there is generally less complicated wiring and a centralized location for easier repairs by solar technicians. Typically they are less expensive, said Solar Reviews. It said that inverters can typically cost 10-20% of the total solar panel installation, so choosing the right one is important.

How long do they last? 

While solar panels can last 25 to 30 years or more, inverters generally have a shorter life, due to more rapidly aging components. A common source of failure in inverters is the electro-mechanical wear on the capacitor in the inverter. The electrolyte capacitors have a shorter lifetime and age faster than dry components, said Solar Harmonics.

EnergySage said that a typical centralized residential string inverter will last about 10-15 years, and thus will need to be replaced at some point during the panels’ life.

String inverters generally have standard warranties ranging from 5-10 years, many with the option to extend to 20 years. Some solar contracts include free maintenance and monitoring through the term of the contract, so it is wise to evaluate this when selecting inverters.

Microinverters have a longer life, EnergySage said they can often last 25 years, nearly as long as their panel counterparts. Usually, these inverters have a 20–25-year standard warranty included. It should be noted that while microinverters have a long warranty, they are still a relatively new technology from the past ten years or so, and it remains to be seen if the equipment will fulfill its 20+ year promise.

The same goes for DC optimizers, which are typically paired with a centralized string inverter. These components last for 20-25 years and have a warranty to match that time period.

Failures 

A study by kWh Analytics found that 80% of solar array failures occur at the inverter level. There are numerous causes of this.

According to Fallon Solutions, one cause is grid faults. High or low voltage due to grid fault can cause the inverter to stop working, and circuit breakers or fuses can be activated to protect the inverter from high-voltage failure.

Sometimes failure can occur at the MLPE level, where the components of power optimizers are exposed to higher temperatures on the roof. If reduced production is being experienced, it could be a fault in the MLPE.

Installation must be done properly as well. As a rule of thumb, Fallon recommended that the solar panel capacity should be up to 133% of the inverter capacity. If the panels are not properly matched to a right-size inverter, they will not perform efficiently.

Maintenance

To keep an inverter running more efficiently for a longer period, Those Solar Guys recommended choosing a cool, dry place with lots of circulating fresh air. It also suggested avoiding installing in areas with direct sunlight, though specific brands of outdoor inverters are designed to withstand more sunlight than others. And, in multi-inverter installations, it is important to be sure there is proper clearance between each inverter, so that there isn’t heat transfer between inverters.

Those Solar Guys said it is best practice to inspect the outside of the inverter (if it is accessible) quarterly, making sure there are no physical signs of damage, and all vents and cooling fins are free from dirt and dust.

It is also recommended to schedule an inspection through a licensed solar installer every five years. These standups typically cost $200-$300, though some solar contracts have free maintenance and monitoring for 20-25 years. During the checkup, the inspector should check inside the inverter for signs of corrosion, damage, or pests.

In the next installment of the series, pv magazine will examine the life of residential battery energy storage applications.

Residential solar panels are often sold with long-term loans or leases, with homeowners entering contracts of 20 years or more. But how long do panels last, and how resilient are they?

Panel life depends on several factors, including climate, module type, and the racking system used, among others. While there isn’t a specific “end date” for a panel per se, loss of production over time often forces equipment retirements.

When deciding whether to keep your panel running 20-30 years in the future, or to look for an upgrade at that time, monitoring output levels is the best way to make an informed decision.

Degradation

The loss of output over time, called degradation, typically lands at about 0.5% each year, according to the National Renewable Energy Laboratory (NREL).

Manufacturers typically consider 25 to 30 years a point at which enough degradation has occurred where it may be time to consider replacing a panel. The industry standard for manufacturing warranties is 25 years on a solar module, said NREL.

Given the 0.5% benchmark annual degradation rate, a 20-year-old panel is capable of producing about 90% of its original capability.

Panel quality can make some impact on degradation rates. NREL reports premium manufacturers like Panasonic and LG have rates of about 0.3% per year, while some brands degrade at rates as high as 0.80%. After 25 years, these premium panels could still produce 93% of their original output, and the higher-degradation example could produce 82.5%.

A sizeable portion of degradation is attributed to a phenomenon called potential induced degradation (PID), an issue experienced by some, but not all, panels. PID occurs when the panel’s voltage potential and leakage current drive ion mobility within the module between the semiconductor material and other elements of the module, like the glass, mount, or frame. This causes the module’s power output capacity to decline, in some cases significantly.

Some manufacturers build their panels with PID-resistant materials in their glass, encapsulation, and diffusion barriers.

All panels also suffer something called light induced degradation (LID), in which panels lose efficiency within the first hours of being exposed to the sun. LID varies from panel to panel based on the quality of the crystalline silicon wafers, but usually results in a one-time, 1-3% loss in efficiency, said testing laboratory PVEL, PV Evolution Labs.

Weathering 

The exposure to weather conditions is the main driver in panel degradation. Heat is a key factor in both real-time panel performance and degradation over time. Ambient heat negatively affects the performance and efficiency of electrical components, according to NREL.

By checking the manufacturer’s data sheet, a panel’s temperature coefficient can be found, which will demonstrate the panel’s ability to perform in higher temperatures, said SolarCalculator.com.

The coefficient explains how much real-time efficiency is lost by each degree of Celsius increased above the standard temperature of 25 degrees Celsius. For example, a temperature coefficient of -0.353% means that for every degree Celsius above 25, 0.353% of total production capability is lost.

Heat exchange drives panel degradation through a process called thermal cycling. When it is warm, materials expand, and when the temperature lowers, they contract. This movement slowly causes microcracks to form in the panel over time, lowering output.

In its annual Module Score Card study, PVEL analyzed 36 operational solar projects in India, and found significant impacts from heat degradation. The average annual degradation of the projects landed at 1.47%, but arrays located in colder, mountainous regions degraded at nearly half that rate, at 0.7%.

Proper installation can help deal with heat related issues. Panels should be installed a few inches above the roof, so that convective air can flow beneath and cool the equipment. Light-colored materials can be used in panel construction to limit heat absorption. And components like inverters and combiners, whose performance is particularly sensitive to heat, should be located in shaded areas, suggested CED Greentech. 

Wind is another weather condition that can cause some harm to solar panels. Strong wind can cause flexing of the panels, called dynamic mechanical load. This also causes microcracks in the panels, lowering output. Some racking solutions are optimized for high-wind areas, protecting the panels from strong uplift forces and limiting microcracking. Typically, the manufacturer’s datasheet will provide information on the max winds the panel is able to withstand.

The same goes for snow, which can cover panels during heavier storms, limiting output. Snow can also cause a dynamic mechanical load, degrading the panels. Typically, snow will slide off of panels, as they are slick and run warm, but in some cases a homeowner may decide to clear the snow off the panels. This must be done carefully, as scratching the glass surface of the panel would make a negative impact on output.

(Read: “Tips for keeping your rooftop solar system humming over the long term“)

Degradation is a normal, unavoidable part of a panel’s life. Proper installation, careful snow clearing, and careful panel cleaning can help with output, but ultimately, a solar panel is a technology with no moving parts, requiring very little maintenance.

Standards

To ensure a given panel is likely to live a long life and operate as planned, it must undergo standards testing for certification. Panels are subject to the International Electrotechnical Commission (IEC) testing, which apply to both mono- and polycrystalline panels.

EnergySage said panels that achieve IEC 61215 standard are tested for electrical characteristics like wet leakage currents, and insulation resistance. They under go a mechanical load test for both wind and snow, and climate tests that check for weaknesses to hot spots, UV exposure, humidity-freeze, damp heat, hail impact, and other outdoor exposure.

IEC 61215 also determines a panel’s performance metrics at standard test conditions, including temperature coefficient, open-circuit voltage, and maximum power output.

Also commonly seen on a panel spec sheet is the seal of Underwriters Laboratories (UL), which also provides standards and testing. UL runs climactic and aging tests, as well as the full gamut of safety tests.

Failures 

Solar panel failure happens at a low rate. NREL conducted a study of over 50,000 systems installed in the United States and 4,500 globally between the years of 2000 and 2015. The study found a median failure rate of 5 panels out of 10,000 annually.

Panel failure has improved markedly over time, as it was found that system installed between 1980 and 2000 demonstrated a failure rate double the post-2000 group.

System downtime is rarely attributed to panel failure. In fact, a study by kWh Analytics found that 80% of all solar plant downtime is a result of failing inverters, the device that converts the panel’s DC current to usable AC. pv magazine will analyze inverter performance in the next installment of this series.

Florida-based Castillo Engineering Services, a solar and energy storage design firm, recently launched Solar Done Right, which it said is intended to advance the quality and safety of solar designs and installations by providing checklists and other educational resources.

The checklists, downloadable for free, provide guides to help ensure that projects comply with the newly updated Florida Building Code, National Electric Code, and National Fire Code.

“Checklists are a key element of high-reliability and high-performance engineering,” said Christopher Castillo, CEO of Castillo Engineering. The Solar Done Right Checklist is intended to help keep local building departments, solar installers, and homeowners current on the latest structural, electrical, and fire safety solar codes; as well as reduce plan examiners’ review times and permit rejections.

Rejected solar plans

The company cited five primary reasons why solar plans are rejected in Florida.

1. Missing PE Stamp: Florida now requires a professional engineer stamp, or an FSEC certification.
2. Plans not site-specific: Florida Building Code (FBC) requires site-specific measurements of wind speed, exposure category, and risk category. Module pressures and attachment spans must be included as well, and none of these measurements may be generically assumed.
3. Incorrect wind zones: FBC 2020 set new wind zones, increasing the number from three to seven distinct zones, and reworked roof zones on flat roof planes. Pressures per roof zone also increased with respect to wind speed.
4. Missing module exposure identification: The recent code change differentiates the pressures experienced by the PV module based on its location in the array. Modules are now separated into edge, exposed, and non-exposed classifications.
5. Incorrect attachment spans and loading: The spans between attachments are determined by the loading on the attachments. That loading should not exceed the maximum allowable strength of the attachments. The effect is to limit the span of the rails between the attachments.

In addition to the checklists, Castillo Engineering will offer a series of Continuing Education Courses hosted by the Building Officials Association of Florida.

The Structural Engineering Institute (SEI) of the American Society of Civil Engineers (ASCE) recently approved the formation of a new committee whose purpose is to provide guidance to the solar industry on the design, development, and construction of solar photovoltaic (PV) structures.

This committee, called the Solar PV Structures Committee, is comprised of engineers, manufacturers, contractors, permitting officials, and owners. The mission of the committee is to focus on the structural and geotechnical design of the unique structures that support PV modules on building rooftops, carports, and ground mount facilities so that these structures can be both reliable and economical in a consistent manner throughout the country.

To the untrained eye, PV structures may be perceived as simple to design and well-understood by the engineers and manufacturers that design and build them. However, the reality is that the racks that support the PV modules are unique structures, and the current structural design standards and building codes, typically written with conventional bridges and buildings in mind, are not sufficient for the solar industry to be both reliable and economical.

The continual push to economize PV facilities is driving the need for detailed design guidance from the PV industry as the benefits of “sharpening the pencil” can be tremendous. On large-scale utility projects, the structural elements are repeated thousands of times and optimization of these elements can yield significant savings.

For instance, on a 200 MW project, there can easily be 100,000 piles. Decreasing the pile length from 15 ft to 13 ft can save millions of dollars. But properly justifying this optimized pile length requires a thorough understanding of the behavior of a PV racking structural system under all load conditions, as well as a concurrence among all stakeholders on the acceptable risk of failure compared to the cost required to reduce the risk to an acceptable level.

Without a reliable and consistent approach to the design of these types of structures the solar industry will continue to struggle with failures, misunderstandings, inconsistent designs, and potential litigation.

The committee strives to be the PV industry’s arena for collaboration and sharing lessons learned so that everyone can benefit. This can be challenging, but to better understand the behavior of PV structural elements, collaboration needs to take place. Buildings and bridges have decades of experience and research that can be used in their design – PV structures do not.

For ground mount PV structures, no formal industry guidance has been provided to engineers on how to reliably and consistently design them. When there is no design guidance, engineers do their best while working within the constraints of the project schedules and budgets. This tends to lead to inconsistent and/or unreliable designs. This new committee wants to fill in this knowledge vacuum and provide the guidance the industry is looking for.

The committee is currently collaborating on important topics such as wind loading, snow loading, corrosion, frost jacking (heaving) of piles, pile testing, PV-specific reliability indices, and more.

An ASCE Manual of Professional Practice is currently being developed that will be followed by a detailed industry design standard. The committee plans to publish updates and best-practice articles so that PV solar structural and geotechnical engineers can begin to perform consistent and reliable designs. Stay tuned for future articles on the advancement of structural and geotechnical design of solar PV structures.

Jon Manning is a structural engineer with Kimley-Horn. Steve Gartner is the chair of the new ASCE committee on solar PV structures and is a senior structural engineer at HDR. Both are based in Minnesota.

It’s 1995 and Bill Clinton is president. The only discussions of global warming are in technical papers and oil company board rooms. Gangsta’s Paradise by Coolio is No.1 and Waterfalls by TLC is No. 2 on the song chart. The U.S leads the world in solar panel production with 35 MW built.

That’s the same year that cadmium telluride solar panels built by First Solar’s earlier incarnation, Solar Cells Inc., were installed at NREL’s outdoor test facility (OTF) in Golden Colorado.

Those panels are still performing, as is First Solar — unlike most of the 1995-vintage vendors that planted their panels at NREL in the previous century — such as Shell, Amoco or Arco.

NREL’s outdoor test facility (the OTF)

First Solar’s thin-film solar modules hit 25 years of continuously monitored performance testing — as part of the longest-running research project at NREL’s OTF.

While the OTF is equipped to perform accelerated testing, nothing is a match for years in the field. NREL uses multi-year outdoor testing to validate its accelerated testing. A solar module with a longer lifetime produces more value and less waste.

The nearly 40 test beds surrounding the OTF building allow researchers to chart the electrical output performance of PV modules under outdoor conditions; test the long-term performance and stability of PV modules and systems under standard and accelerated outdoor conditions; and measure the performance of hybrid systems, according to a release from NREL.

One I-V system used by the researchers to measure the electrical output performance of PV modules under outdoor conditions (and as close as possible to standard test conditions), is the Standard Outdoor Measurement System, a fixed system on which modules are placed for testing and can track the sun. NREL looks to make measurements under a clear sky, with irradiance between 950 and 1050 W/m², and as close to 25°C as possible.

Long-term test results

First Solar’s origin story includes DOE funding for researching cadmium telluride PV technology in the early 1990s. Among the companies involved in the research was Solar Cells Inc., which later became First Solar.

Ben Kroposki, an NREL engineer who installed the initial PV modules for First Solar at the OTF, said “We always intended to keep the modules/arrays installed at the OTF as long as the technologies were relevant to get very long-term reliability data,” in a release.

The initial studies on First Solar’s panels revealed that after five years, the company’s panel degradation amounted to a relative 0.6% a year.

NREL now finds, 25 years later, that the long-term degradation of the studied modules was 0.5% a year, with an efficiency, today, of around 88% of the original panel performance.

Louis Trippel, VP of product management at First Solar, added that the lessons learned from the testing at NREL provided “incremental confidence to help support a recently announced extension” of its module power output warranty from 25 years to 30 years. First Solar’s modules are warranted at 0.5% degradation per year — but the company “guides” to 0.4%.

NREL has also worked with silicon high-efficiency solar panel builder SunPower (now Maxeon) to develop a method to calculate solar panel degradation. After eight years of energy performance data, SunPower panels were shown to degrade at a median rate of 0.2% per year. Trina Solar provides a 30-year linear warranty and a 0.5% annual degradation rate for its silicon solar panels.

But most solar firms haven’t tested their panels for the actual duration of the warranty term.

Different insides

While the solar modules under test are specified at 1995-era performance levels of 45 W output with a 6% efficiency, the dimensions of the module are the standard pre-Series 6 First Solar form-factor.

Trippel noted that the company’s current technology suite is a marked improvement over the panels tested at the OTF. The old panels did not have an edge seal and used only an EVA encapsulant, while today’s modules use a polyolefin encapsulant as well as an edge seal component. Other materials and manufacturing improvements have been made in junction box potting materials, plastics, adhesives and the solar absorber stack itself.

Nick Strevel, the company’s VP of product management, noted, “Our product encapsulation technology and materials today are far superior,” but this testing “helps us understand a legacy performance baseline and provides further confidence in the superior long-term durability and long-term degradation performance of today’s product.”

Strevel said, “Measuring degradation is hard to get to a tenth or hundredth percent — you need some time to get that level of accuracy.” It’s engineers like Dirk Jordan and the OTF staff at NREL focused on PV degradation who develop tools and techniques to make that happen.

On November 17, pv magazine launched its 2020 Roundtable USA event, with leading figures from the U.S. solar PV and energy storage industry coming together in a virtual format to discuss solar PV resiliency in the wake of change.

Watch the pv magazine Quality Roundtable USA

The first part, the Quality Roundtable, looked at how critical it is for companies to focus on quality as an effective tool for not only bringing down the levelized cost of electricity (LCOE) and optimizing PV plant performance, but also for ensuring reliability over the full lifetime of a PV system against the backdrop of a changing climate with increased natural disasters, and for keeping insurance costs down.

Session 1: In the face of extreme weather – Water, wind and fires

Since 1980, damages from weather and climate disasters in the U.S. have exceeded US$1.825 trillion, according to the National Oceanic and Atmospheric Association (NOAA). From 1980 to 2019, the annual average count of extreme climate and weather events, which caused damages of more than $1 billion, was 6.6. When looking at the annual average from 2015-2019, this jumps to an average of 13.8 – twice the number of such events.

This year, extreme weather has hit the U.S. particularly hard. Through October 2020, there have been 16 weather/climate disaster events with losses exceeding $1 billion each, calculated NOAA. These included 11 severe storms, three tropical cyclones, one drought, and one wildfire.

Looking at these numbers, it is important to note what we don’t see: There have been numerous other storms and wildfires in the U.S. this year affecting solar PV assets.

All about PV quality

Building PV for resiliency – before and after an extreme weather event – is all about quality. We can’t control the weather, but we can control quality, sound engineering and deployment of the right O&M strategies. Renewable energy insurance provider GCube said in 2018 that 50% of North American insurance claims in the PV industry come from weather events. Reason enough to give this topic some greater attention.

To discuss these key issues, Kaushik Roy Choudhury, Global Technical Leader, DuPont Photovoltaic Solutions, Jeff Wang, Business Development Alternative Energies – North America, Stäubli Electrical Connectors, independent expert, Daniel Chang, VP of Business Development, from PV testing lab RETC, and Alex Roedel, Senior Director of Design and Engineering, Nextracker took to the virtual stage to host a panel discussion (see video: minute 51).

Watch the pv magazine Quality Roundtable USA

RETC’s Chang stated that the U.S. solar industry is in a “perfect storm” of increased demand for higher efficiency PV panels, lower costs and PV installations built in hail prone regions, like Texas. “Insurance companies want to qualify and quantify the issues that they’re seeing, before they insure,” he said. This means testing is crucial.

Agreeing, DuPont’s Choudhury added that with fast changing technologies, like bigger, lighter modules, and pressures to decrease costs, both testing and the reliability of materials are key for solar installers.

Adding to their sentiments, Nextracker’s Roedel said that while discussions have thus far focused on why extreme weather events are a big issue, it is now time to figure out what the solutions are for lowering both solar risk and insurance rates.

Session 2: Building resiliency through modern O&M

Operations and maintenance (O&M) is now a much more critical piece of the solar landscape – and the key to long-term resilience and a competitive LCOE. As grid-scale solar becomes a more mature, sophisticated business, so is the modernization of the O&M segment, where we are seeing more alliances to support the long-term ownership for PV assets. Increasingly, the O&M role in the U.S. is being contracted out to a third party – a trend typical of a maturing power industry.

To discuss these issues, George Schulz, Vice President of Clean Energy at Ariel Re provided a review of risk management insurance solutions in the second session, to enhance the certainty of long-term project cash flows through Performance Ratio/MWh guarantees available to stakeholders of utility scale projects, C&I and residential portfolios, as well as the O&M services that provide comprehensive performance guarantees to customers (hour 1.39).

Sarah Herman, Director of Engineering and Remote Operations, NovaSource went on to present case studies to shed light on some of the events a solar O&M provider must be well-equipped to handle to minimize project downtime, maximize performance, and stabilize the assets (hour 1.49).

Watch the pv magazine Quality Roundtable USA 

Presentations and case studies

In addition to the two sessions, DuPont’s Kaushik Roy Choudhury held a presentation on Field performance of modules in the wake of changing technologies and weather, where he looked at recent issues from the field; and balancing technology and reliability to reduce premature degradation and field failures (minute 24).

pv magazine’s K Kaufman went on to present a case study, Hail happens, from a 2019 North Carolina extreme hail event and the resulting implications (minute 42).

Finally,  Tara Doyle from PV Evolution Labs held a presentation on Field data from California wildfires, which provided a review of fire the latest fire season’s damage reports and an approach to evaluating sites and most affected areas. Insights into O&M and handling insurance claims (hour 1.31).

Those who registered for the event can download the presentations in the networking area of the event app -> to the event app.

From pv magazine global

In the field, PV modules have been observed to degrade and lose performance in a variety of ways. And the fast-moving nature of the technology often means new problems are being discovered as fast as the old ones are being solved.

Detailed standards exist to set a minimum standard for industry entry, however, it is widely acknowledged fall short in some areas, particularly when it comes to spotting new or little-understood degradation mechanisms. “Standards are not intended to serve as a guarantee of quality or reliability,” state scientists from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) in a newly published paper. “…the industry has been forced to design standards around known failures, as opposed to developing a more comprehensive testing regime that could detect unexpected failure modes more frequently.”

The group led by NREL set out to create such a comprehensive testing regime, focused on mimicking the overall natural environment modules are installed in, rather than pushing the limits of one particular failure mode. “Of great value to the industry would be a test that would provide more comprehensive identification of failure modes in new module designs and materials prior to field deployments,” the group states.

Key to the development of a testing protocol is the ability to simultaneously apply different stress factors to the modules. With this in mind, the group combined a climate chamber with xenon lamp solar simulators, hydraulic actuators for mechanical loading and power sources to apply voltage stress to the modules. The set up is described in the paper Advanced reliability assessments of photovoltaic modules and materials using combined-accelerated stress testing, published in Progress in Photovoltaics.

Backsheet cracking

To demonstrate the effectiveness of its protocol, the group compared it’s combined-accelerated stress testing (C-AST) results with the Module Accelerated Sequential Testing (MAST) protocol developed by DuPont to test the reliability of polymer backsheets, noting that backsheet is a common failure mode not well covered by current testing standards.

C-AST was shown to produce similar results to MAST in terms of backsheet cracking, while also producing reliable results for light induced degradation, cell cracking, soldering failures, corrosion and other issues. And the group is confident that its testing could be adopted as an industry standard in the future. “With the single C-AST protocol, we have the ability to screen for both known and unknown degradation modes, providing the possibility to minimize the many tests in the design qualification standard when used in conjunction with a single test protocol,” they conclude. “Potentially reducing the cost of certification testing and accelerating time to market.”

From pv magazine 09/2020

pv magazine: This has been a tumultuous year for economies right around the world, and the United States has been no exception. How would you describe the year for large-scale solar?

Dean Solon, founder and CEO (DS): The short version is that it’s been a damned good year.

Why do you say that?

DS: Last year was great for solar in the United States and we thought, ‘that’s going to be a hard one to top off.’ And now 2020 is topping 2019, and we know that 2021 is going to go even further.

Jason Whitaker (JW): From our standpoint as an electronic balance of system (eBoS) supplier, through our communications with our clients and customers, we understand that our indirect customers [asset owners] are really putting a lot of pressure on our direct customers [EPCs] to ensure continuity of supply and even accelerated delivery to sites.

And why do you think there is this acceleration?

DS: A lot of people thought that the 100 MW fields were all dead, but those suckers are coming back with a vengeance. We are seeing lots of 220 MW, 250 MW, 500 MW, 750 MW projects – we are even seeing two 1 GW-plus sites taking shape.

What is driving the increase in project size?

DS: I think what is happening is that many states are seeing coal assets reach end-of-life and powering down, and they are just replacing them with solar. The second part is that solar has gotten very cheap to install. The modules have come down, the eBoS, trackers have sunk like a rock, inverters are dead cheap – it just makes sense to install more PV.

JW: It’s not just the size though, the geographic spread [of PV projects] is also growing: These projects aren’t only in California anymore.

Moving onto PV power plant design trends – one notable feature of some projects, as an outside observer of the U.S. marketplace, has been some of the high AC/DC ratios in certain parts of the country. Where do you see that heading?

JW: The AC/DC ratios have been quite high, but that’s only been the case for the last couple of years. It really depends on what that client is trying to optimize. There are a lot of things that come into play, including the financial model. All the things really play into the various “secret sauces” that the developer has in their recipe. I don’t know how far it will go, but it is something that is more driven by other components and standards. It’s been fairly steady over the last 18 to 24 months.

DS: One thing that we’ve seen is that a couple of our clients are incorporating a 42-year cycle into their financial modeling – which is kind of bizarre, but if it works it works.

You mean they are assuming a 42-year lifetime of the plant? As a supplier of electrical components that will be out in sun, rain, snow, hail and wind for 42 years, what do you make of that?

DS: If they choose Shoals’ products they might be OK.

I suppose you would say that. We’ve recently seen the rapid rise of bifacial modules on single-axis tracking systems. This also means that two-in-portrait (2P) configurations have also become more commonplace. Where do you see that discussion regarding these tracker configurations and wind events?

JW: This really applies the same way, regardless of the component you are talking about. I think the key thing is to pick a reputable tier-1 vendor that understands all the different aspects that come into play when you are talking about a bifacial product and 2P configuration – which is a lot more surface area and a lot more weight than what has been in the market previously. It is making sure you partner with a reputable player.

DS: And don’t go cheap.

JW: Exactly. Otherwise you will end up choosing a supplier that has a better price point, but is a newcomer to the tracker market or a newcomer to this type of configuration. Ultimately you will still pay the price – it might not be day one, it could be day 50, or year five.

DS: What happens with trackers is that you have steel. And steel costs six pennies per pound. For some new startup tracker companies, the only way they can compete with the established companies like Array Technologies or Nextracker, is to reduce the cross sectional area or size, and then sell it cheaper. And what we are seeing, especially down in Florida, is a lot of cheaper trackers that are rusting – even within one year. They are also bowing like Christmas lights hanging across your gutters. So now you are asking the module to act as a structural feature to compensate for the beams that are under-designed. You may save half a penny or a penny off the price with the startup [tracker] guy but within five years you are going to pay triple that cost when your modules are lying across the field in a wind event.

Everyone says that they’ve done the modeling and stuck one [tracker] table in a wind test, but put it in Florida, have a hurricane come by and see how it goes. That’s a realworld wind event, not spending $50,000 for 30 minutes in a wind tunnel test. The O&M costs down the road for these trackers are going to be phenomenal.

Well let’s talk O&M. We are seeing quite a few transactions with some exiting the O&M business while others acquire portfolios. How do you see this space evolving?

DS: From a pennies-per-watt standpoint everyone is beating themselves up to do it cheaper and cheaper – that’s why First Solar got out of it. The O&M cost is dropping just like it has done for the module, inverter and eBoS – it’s cost down. O&M kind of got a free ride in not being on the radar for cost down, but in the last three years that process has really tightened up.

For us, with our Big Lead Assembly where we’ve removed combiner boxes, the fuses are external and the wiring, once installed, is never messed with again. That means O&M costs on the BLA are approaching zero. The EPCs that make their money off O&M don’t like us so much – their model was to sell cheap and then make up that margin on the O&M services.

JW: It really has come full circle, a lot of the clients are starting to understand the true cost of eBoS and are starting to head down the straight-and-narrow path – a lot of this is due to lessons learned in the past. Last year, 2019, we repowered about 850 MW of our competitors’ products. Keep in mind that this was multiple sites and multiple different competitors. Although the BLA takes O&M down to near zero, there is still a lot of cleanup with cheap competitors projects that will have to go through a repowering cycle.

DS: That number Jason is talking about, the 850 MW, were fields that never made it to 36 month lifespan before the eBoS failed.

That’s a bit shy of 42 years.

DS: It didn’t even make 42 months!

We are seeing from China the race to make the biggest, most powerful module. What do you make of that trend?

JW: I think it’s a hell of a marketing trend. We’re obviously not panel experts, but the trend did make me wonder whether modules have reached a point of stagnation from a technology perspective, and manufacturers just focused their efforts on multiplying the existing form factor to increase the output. Bifacial, by contrast, is starting to push the envelope and offer more power output for an equivalent cost. Increasing the amount of power without occupying more real estate is a good thing and ultimately from an eBoS and a metal-BoS perspective – more power per steel, more power per copper does work. But I am not sure what the advantages are in saying that you have a 1000 W module that in its simplest form is just two 500 W modules stuck together.

Shoals is an American company playing on the international market. You’ve had part of your supply chain in China in the past – is that still the case? And I’m asking in light of recent trade tensions…

DS: We had operations in China in the early 2000s, when we were in automotive. But when we were starting to pick up a heap of module makers and inverter guys, who were manufacturing in China, we started to supply companies from some of our Chinese operations. In the last eight to 10 years, we have been able to manufacture in the U.S. and ship abroad. We think we have the most efficient labor force here, and at a great cost. Another good thing is that we have a lot of sea containers rolling into the United States, and all of those go home empty. We can take advantage of that and get great freight rates. Half of our customers are outside the U.S. We ship 15 to 20 sea containers a week to customers around the world. We’re not opposed to having local production for local customers though.

JW: If you look at our cost of goods and sold material, about 95% of that comes from North America.

DS: We practice what we preach.

The Yale Program on Climate Communication has released an interactive map that shows variations in the climate and clean energy views of Democrats and Republicans. The map shows the results of 15 survey questions, with map layers representing response data at the levels of the U.S. as a whole, each individual state and each of the country’s 435 congressional districts.

The questions pertain to a number of topics ranging from opinions on the reality of global warming, potential risk of climate change and individual policy questions.

The biggest variance in responses came from questions regarding climate change, especially those concerning the role humans play in it.

There are 19 states where at least 50% of Republicans surveyed stated that they don’t believe that climate change is happening. The most skeptical GOP respondents came from Wyoming and West Virginia, where 55% denied the existence of climate change, man-made or otherwise. For Democrats, every single state had an agreement rate of at least 80%, with Alabama Democrats’ 84% agreement rate being the lowest among the party in the nation. The highest rate of GOP agreement came from New York, at 62%.

The biggest disparity when respondents were asked if they were worried about the threat posed by climate change. Nationally, 85% of Democrats shared that they were worried, compared to just 40% of Republicans. The biggest disparity came in Idaho, where 90% of Democrats shared that they’re worried, compared to just 37% of Republicans. There was not a single state where the majority of Republican respondents shared that they were worried.

Policy (mostly) bridges the divide

While common ground on climate change was seldom achieved among the two parties, renewable energy proved to be a better tool to bring the left and right together.

In every single state, at least 50% of Republican and Democrat respondents support:

• funding research into renewable energy sources
• regulating CO2 as a pollutant
• teaching about the causes, consequences, and potential solutions to global warming in public schools
• the idea that corporations should be doing more to address climate change

Among these, the topic with the most universal support was funding research into renewable energy sources, with North Dakota seeing 95% of Democrats and 84% of Republicans in agreement.

Outside of unanimous support, the two parties also generally agreed that environmental protection is more important than economic growth, with only Texas, Oklahoma, Missouri, Arkansas, Louisiana, Tennessee, North Carolina, Connecticut, Maine, New Hampshire, Michigan and Ohio Republicans offering dissenting opinions. And while the majority of Republican respondents didn’t agree that utilities should be required to procure 20% of their generation from renewable resources, it was still one of the closer points of agreement.

While policy proved to be a generally effective tool to bring the two parties together, there was still some dissent. This disagreement came only on policy questions regarding climate change. While Democratic respondents in every state agreed that citizens should do more to address global warming, the only states to feature a corresponding GOP agreement majority were New York, New Jersey and Maryland. There wasn’t a single state where the majority of Republicans agreed that Congress should do more to address global warming, yet that opinion was consensus among Democrats across the board.

From pv magazine 06/2020

Estimating the impact of product piracy in the solar industry is not easy to do. Since the price of a PV module is typically based on its measured output, it may appear that there is no immediate advantage for a ‘pirate’ producer in fraudulently slapping the logo of a more reputable manufacturer onto its own inferior products.

German company Viamon, which provides security services to the PV industry, says that it sees on average one to two cases per year involving counterfeit modules. China-based Quality Assurance provider Sinovoltaics, meanwhile, states that its experience related to counterfeiting is more along the lines of falsified power ratings or quality certifications, and even electroluminescence images being edited to hide cell cracking and other defects.

Several PV module manufacturers, however, have confirmed to pv magazine that they do see fake versions of their products available for purchase in various locations, and that they see solutions to prevent this as a worthwhile investment – even in times where profit margins in module production are stretched thin. “Unfortunately, it is almost impossible to determine an exact number of copycats, but year by year this problem is increasing, and we think that the dark figure is even higher,” explains Waldemar Hartmann, sales director at German module producer AE Solar. “We see it quite frequently by ourselves, and our partners see it around the world.”

What to do with a fake

When counterfeit modules are detected, AE Solar says it works both with the customer who purchased them and with legal advisers to track down the producer and prevent further counterfeiting. But it notes that with the network of intermediaries between production lines and end customers, it can be difficult to establish who makes such modules.

Norway-headquartered manufacturer REC Group also states that it occasionally sees counterfeits of its modules being sold via online platforms. “Although these are only a few small cases per year, we take these seriously,” says Cemil Seber, vice president of product management at REC Group.

Hartmann goes on to explain that fake branded AE Solar modules are frequently found for sale on online e-commerce platforms such as Alibaba. They also have cases where an end customer has contacted them to complain of a product’s poor performance, only to find that what they purchased was not in fact produced or certified by AE Solar at all. But one case in particular, says Hartmann, led the company to take further action. “A huge manufacturer placed an OEM order with us, saying due to high demand they did not have the capacity to produce their client’s full order,” he explains. “Once we finished the order, and started to unpack the stickers for the panels, we saw that it was AE Solar’s old logo – we already had an upgraded new design. So it appeared that we had made copies of our own brand for another factory.”

Multiple solutions

AE Solar is now introducing an NFC chip for all of its modules, which allows the company to track its panels. The chips also allow customers to reliably authenticate products before buying, simply by scanning them with a smartphone. The chips link with an app that can identify the module with a unique web link, while also allowing customers to directly communicate with the AE Solar team. The chips are laminated under the module glass, so they are difficult to remove without severely damaging the modules themselves. Hartmann notes that while the chips and accompanying mobile app took some years and significant investment to manufacture, AE Solar has not increased its prices as a result of integrating them.

REC Group uses an app-based solution to assist its certified solar installers, which also serves to help prevent counterfeiting, relying on module serial numbers rather than a chip. This is likely less secure, however, REC states that the app allows it to immediately identify any fake serial numbers. Installers are encouraged to use the app to register all installations with REC Group modules, and the company offers extended warranty terms to all registered solar installations.

Another approach to combating counterfeits, taking things down to the cell level, can be seen with Korean manufacturer Hanwha Q Cells. The company deploys its patented Tra.Q process, where individual wafers are marked using a laser, and the marks can be read by a scanner. According to the company, such approaches have value beyond protection against counterfeiting. “Tra.Q gives each cell a unique fingerprint, which enables us to completely trace the entire manufacturing process for each individual solar cell – this includes the serial number, the date and location of production and even which material charge was used to make the cell,” says a Q Cells spokesperson. “We can thus better analyze errors and even make improvements as they arise.”

For Viamon, this fits in with a wider industry move toward quality assurance and establishing accountability across the supply chain, including in transit and installation. “Chip inside the shipment is an interesting new topic. That not only means counterfeiting but also controlling shipping routes, on-time deliveries, and the correct content of containers,” says Viamon general manager Oliver Strecke. “Often, the customer is so cost-sensitive that copy-protected chips are not easy to establish in every module. I believe that using random samples of a whole shipment could be a worthy solution.”

Solar assets are underperforming far more frequently than official energy estimates would suggest, validating an industry-wide bias towards overly optimistic pricing, according to the industry experts who contributed to KwH Analytics’ 2020 solar risk assessment report. “From a business standpoint, this means that smart investors need to take a step back and adjust to reality,” Richard Matsui, CEO and founder of kWh Analytics said.

“P90 downside events occur so often that they have nearly become P50,” kWh Analytics said in this year’s Solar Risk Assessment report. By definition, P90 events should occur once every 10 years, but they are now at least three times more frequent because of the unreliable energy estimates that have been baked into projections.

The situation is fueled, in part, by the fact that it is a seller’s market; buyers need to be competitive to get the best solar assets.

“Many projects perform up to the rosy expectations but, on average, projects are underperforming their financial expectations,” Jackson Moore, head of DNV GL’s solar section said, noting that the data-driven insights in the report make this clear. “We want data to be as accurate as possible, so it can support a sustainable solar industry,” Dana Olson, global solar segment leader at DNV GL added. Accuracy means avoiding a correction, he added, noting that the solar industry’s optimistic projections problem will not be solved without transparent insight into the sources of underperformance being experienced in the field today.

According to Matsui, the structural setup that underpins the aggressive solar production predictions bias exacerbates the situation. Like the big three credit rating agencies pre-financial crisis, the independent engineers that are hired by solar developers to give solar production estimates have an inherent profit motive for giving an aggressive projection, Matsui explained. “It’s a way to gain market share,” he said.

The data is hard to dispute, however. The report noted that for commercial scale solar projects optimistic irradiance assumptions contributed to a 5% underperformance on a weather-adjusted basis and that “weather-adjustment bias” is responsible for up to 8% bias in measured underperformance.

The report goes on to highlight O&M cost variation issues, disappointing inverter performance and the increasing frequency of diode and string anomalies after the first year.

Highly automated factories

The ITEK module factory bought by Silfab last year in Bellingham, Washington has an annual capacity of 200 MW. Silfab makes the same mono-PERC modules there as at its factory in Toronto, Ontario — with an emphasis on 60-cell modules.

The company has a total capacity of 800 MW with three lines in in Toronto and two lines in the U.S. That’s modest compared to JA Solar’s 16 GW capacity in China but substantial for silicon PV module capacity in North America.

Geoff Atkins, business development at Silfab, told pv magazine, “We believe we’re one of the most automated solar manufacturers in North America.”

Silfab’s line of metal wrap-through back-contact modules comes as the result of a strategic alliance with DSM, maker of an “integrated” electroconductive backsheet.

Atkins spoke of an international supply chain and operational discipline that minimizes inventory and makes sure every module has an associated purchase order.

“We rarely get caught up in the solar coaster,” said Atkins.

Notable “high-profile commercial projects”

Silfab’s “main business is U.S. residential installers,” said Atkins, but he noted, “We touch on high-profile commercial projects.”

Here are a few of those high-profile projects.

U.S. state department: Twenty Silfab solar panels on the roof of the State Department’s Harry S. Truman building in Washington, DC. — installed by Inman Solar.

NFL Stadiums: Atkins noted that Silfab’s modules are deployed by Powerhome at “most of the NFL stadiums” including the North Carolina Panthers’ Bank of America Stadium (pictured below) and the Cleveland Browns, Detroit Lions, and Pittsburgh Steelers.

Walmart: After Walmart parted ways with Tesla, the global retailer started to deploy Silfab modules (as well as SolarEdge inverters and DCE racking) through C2 Energy Capital on five projects, totaling over 1.9 megawatts across Walmart rooftops in New Jersey.

Atkins said that these PV modules are “Buy American” approved and “specifically designed for and dedicated to the North American market.”

He notes that many companies have tried their hand at manufacturing in North America but, unlike Silfab, most have experienced what Atkins called, “varying levels of success.”

Even under the worst of worst-case scenarios, throwing damaged, crushed or otherwise decommissioned photovoltaic (PV) solar panels into unsafe, unsanitary landfills will not result in runoff or emissions that could raise cancer or other health risks for nearby communities.

In fact, according to a new report from the International Energy Agency (IEA), health risks from lead in crystalline silicon PV panels are one order of magnitude — or about one-tenth — below the risk levels set by the U.S. Environmental Protection Agency (EPA). For cadmium in thin-film panels, the risk is even lower — “several orders of magnitude.” Both metals are classified as toxic and pose a range of threats to human health.

However, these findings are not intended as a carte blanche for the indiscriminate disposal of end-of-life solar panels, according to the report’s authors. “Recycling is expected to be a dominant strategy for sustainable end-of-life management and is both commercially underway and subject to further research and development activities,” they write in the second sentence of the report’s Executive Summary.

Rather, the report is targeted at answering public health concerns sometimes raised during permitting or regulatory proceedings, said co-author Garvin Heath, a senior scientist at the National Renewable Energy Laboratory.

In a separate research effort, Heath has called for an increased focus on developing high-value recycling methods aimed at recovering more silicon from end-of-life PV panels.

The value of worst-case scenarios

The use of worst-case scenarios in the IEA study is aimed at exploring maximum potential risks to human health. The scenarios used are, in reality, largely illegal or unlikely to occur in most countries; for example, landfills without linings to prevent toxic runoff or located within 100 meters of a river or stream that could be polluted by such runoff.  According to the report, only 3.6% of U.S. landfills are located within 1.6 kilometers — just under a mile — of a river or stream.

Beyond quieting stakeholders’ safety concerns, the value of the study is in providing a model for future research to assess potential impacts to human health of other metals in solar panels — both today and as the technology continues to evolve. The current report is specifically limited to the key metals used in crystalline silicon and thin-film panels — including lead and cadmium.

The authors note that further research may be needed on other panel components such as copper, nickel and tellurium. The study is also limited to impacts on human health, not the environment in general.

The report is third in a series looking at other potential health risks — and worst-case scenarios — related to solar panels. Focusing on panel breakage and emissions caused by fires, the findings of these earlier reports are similar to the landfill report — that is, the risks to human health were all under EPA thresholds.

National Grid’s Renewable Energy Growth program contracted with the Cadmus Group to inspect 100 solar power systems installed in the state. The powerpoint version of the report, Study of Renewable Energy Installation Quality in Rhode Island (the official presentation can be found here – pdf), looked at 100 installations in the state in November of 2018. The group found that 45% of the 86 residential, 8 medium sized and 6 large sized projects – built by 27 companies – inspected exhibited major or critical installation deficiencies.

The program’s scoring metric is as follows:

Looking at the residential projects, the issues by inspection element were:

• AC Combiner – 31
• AC Disconnect – 5
• Array – 190
• Inverter – 81
• Junction Box- 6
• Optimizer – 4
• Overall Observations – 3
• Production Meter – 2
• Supply-Side Connection – 187
• Total – 509

Cadmus noted that more than 70% of installation companies responded to reports of their system installation issues, however, only 33% of those reports resulted in actual corrective actions.

In the small-scale systems, there were 25 examples of racking mechanical connection issues, such as connections incorrectly made or variations from the installation instructions. The below image shows a missing rail support, that could lead to premature system failure as the aluminum could bend over time, shifting the solar modules connection to the racking system.

Improperly secured solar modules were noted in 28 instances in small scale installations, with missing, incompatible, or inappropriately-installed hardware. Missing clamps, bent bolts (see header image) due to incorrect cuts to the length of rails, and incorrect hardware used in tying down modules. While most of these issues weren’t considered critical – over the long time – they can lead to hardware not staying in place.

Conductor – wiring – issues were also observed, and comprised most issues noted with medium and large scale system. For instance, below a rooftop solar installation’s rapid shutdown requirements aren’t properly met as the hardware to manage this shutdown process was located more than ten feet from the solar modules to be shut down in the event of an incident.

Other conductor issues included, unprotected or improperly-supported conductors. These issues lead to wires lain atop metals (below image)that can cut through the outer sheath over time, or unsupported wires that can sit in water if it pools on the roof.

Two instances of DC connectors not properly connected or used outside of the product listing were found (and this is actually one of the main issues that were found in the Tesla-Walmart fires). Cadmus notes that hazards exist when DC connectors are not properly installed, these connections can cause heat, arcing, poor electricity generation efficiency or a thermal event (fire).

Rhode Island also inspected the interconnection techniques – and Cadmus actually found that there were four systems installed (3 residential and one commercial installation) – in which the solar power system wasn’t actually hooked up to an electrical meter that was measuring the production. Obviously an issues.

There were also 23 noted wire splice issues, such as methods not rated for the specific environment or conductor type, which over time would lead to risk of premature failure due to environmental conditions. For example, the below connectors not suitable for exposed outdoor locations.

In general though, most customers – 86% – were still very happy with their installations, with 12% having a negative perception of things. And even though most customers were happy, 26% of respondents said payments generated by their system were lower than expected. Some of them were not properly informed of the tax implications of cash payments generated by the system, that monthly payments are dependent on actual energy produced, and weren’t fully communicated the delays between when the system started producing energy and when credits appeared on the utility bill.

Editor’s note: Are you interested in learning more about solar installation techniques, and how to avoid fires at solar plants? Be sure to attend pv magazine’s Quality Roundtable at the Solar Power International trade show in Salt Lake City on September 25, from 2 PM to 4:30 PM. Space will be limited, so click here to learn more and to register.