Bengt Jaeckel

Global PV deployment is surging, with Germany adding ~18 GWp in 2024 and 2025 and total capacity reaching ~118 GWp by end-2025. Worldwide, DC nameplate capacity rose from ~1,620 to ~2,760 GWp between 2023 and 2025 amid a rapid shift from PERC to TOPCon and intense cost pressure. While degradation is acknowledged, we focus on discrepancies between module nameplate ratings and delivered power, and on a pragmatic, cost-effective measurement approach to reduce uncertainty, minimizing financial risks, and therefore improving bankability. Manufacturers typically declare positive binning (+5/−0 W) and ±3% tolerances; laboratories report ~±2% measurement uncertainty (MU). Measuring sets of modules and cross-validating a subset in a second, independently calibrated laboratory can reduce effective MU by ~40% (±2% to ~±1.2%). Despite literature indicating average overrating of ~1.3%, our multi-laboratory tests on Tier‑1 batches show underperformance of ~3% or more relative to nameplate - beyond MU and financially acceptable return expectations of 5 to 7%. We tested 10-30 modules per batch using LED AAA (Lab 1) and Xenon A+A+A+ (Lab 2) flashers. TOPCon hysteresis or dark storage effects were mitigated, if necessary, via multi-flash and brief light exposure, however, dark-storage effects were negligible (<0.1%). EL imaging revealed no severe defects (per VDE‑SPEC 90031). Manufacturer flasher lists matched binning, yet both labs measured ~3% lower power; inter-lab agreement was within 1%, reinforcing the validity of the offset. Aggregated 2024 to 2026 results show small within-batch dispersion but batch-to-batch shifts, including bimodal distributions; some outliers exhibited up to 10% overrating and then also often EL anomalies. Because DC underperformance is a persistent offset, a 3% shortfall raises LCOE by ~3%. Financially such increases, or the other way around, lower incomes will make such PV investments risky to not bankable. Systematic two-laboratory quality control reduces uncertainty, improves energy yield forecasts, and strengthens contractual claims for missing “Watt-peak”.

This paper presents a testing and approval concept for the mechanical safety of photovoltaic (PV) mounting systems on buildings within the European regulatory framework. While IEC module standards ensure electrical and environmental performance, structural safety is governed by Eurocodes and national building regulations, which treat PV substructures as load‑bearing roof or façade components. Documented failures under wind and snow loading underscore the need for building authority approval to demonstrate load‑bearing capacity, standardise documentation, and provide legal certainty for stakeholders. The proposed methodology combines non‑standardised small‑body tests on modular components (module clamps, cross connectors, roof hooks) with complete system tests, particularly for flat‑roof and façade systems. Tailored tensile, shear and compression setups reproduce realistic load paths and installation conditions, including misinstallation scenarios. Characteristic load‑bearing capacities are derived statistically, accounting for scatter due to friction, assembly variability and material overstrength, and are evaluated with respect to serviceability limits as well as ultimate capacity. System-scale suction and pressure tests validate the interaction of components and ballast under realistic loading directions. The study highlights the central role of experimental design and assessor involvement under the stringent requirements of the German institute for building technology (DIBt) and shows how the resulting characteristic capacities and dimensioning tables support reliable, economical design and execution of PV substructures.

New material combinations for photovoltaic (PV) modules are required for building‐integrated photovoltaics (BIPV). In previous studies, it has been shown that PV modules with aluminum rear cover degrade heavily during thermal cycling due to interconnector fatigue. The mismatch in thermal expansion coefficients of the aluminum rear cover and the silicon solar cells was expected to induce a larger cell gap change in the solar cell strings under temperature change when compared to typical PV modules with glass covers. In this work, we confirm this effect by measuring and simulating the temperature‐induced cell gap change in test modules with aluminum rear cover as well as with glass rear cover. For a module with glass rear cover, we measure and simulate only about 0.3 times the cell gap change as for a module with aluminum rear cover. Both measurement and simulation show increased cell gap changes for wider solar cells. Furthermore, we measure 20% less cell gap change for a 60% reduction in string length. All in all, we conclude that the (relative) cell gap change is the decisive parameter for controlling degradation due to thermal stress in future PV module designs with alternative material compositions.

Cracks in photovoltaic modules can affect power output, but their relevance depends on module architecture and operating conditions. This study examines how crack length and crack number relate to power loss in 230 mono-Si mini-modules spanning full-cell PERC and half-cut TOPCon technologies with busbar counts from 2 to 12, focusing exclusively on cell line cracks that do not lead to electrically isolated cell parts. Electroluminescence images were used to quantify crack characteristics and busbars, while current–voltage measurements at 200 W/m ² and 1000 W/m ² were used to extract series resistance, shunt resistance, and maximum power point. Correlation analysis was then used to assess how crack characteristics relate to electrical performance. The results show that crack length and crack number are not universal predictors of power loss in modern modules. PERC modules exhibit moderate crack–power correlations at low irradiance, but these correlations weaken at 1000 W/m ² . TOPCon modules show no meaningful correlation at either irradiance level. The results indicate that crack sensitivity is governed primarily by irradiance, busbar count, and cell architecture, rather than by crack length alone.

This study presents a novel, nondestructive in situ method to quantify water ingress into solar modules and polymeric samples using near‐infrared absorption (NIRA) spectroscopy, calibrated with absolute water content via Karl–Fischer titration (KFT). Calibration was performed on various polymer materials—encapsulants, backsheets, and their combinations—using three commercial NIRA spectrometers to assess reproducibility and suitability. The influence of glass type, cell type, sample thickness, and lamination on NIRA signals was also evaluated. The method was validated through two lab and two real‐world case studies. The first lab study quantified moisture ingress in minimodules with PET‐ and PP‐based backsheets, yielding diffusion coefficients consistent with literature. The second involved polymer coupons under accelerated weathering; cracks in the backsheet increased water uptake, while encapsulants reduced it. In the first case study, moisture distribution was mapped in rooftop modules with and without visible defects in the backsheet and cells. Modules with backsheet and cell cracking showed 50% higher water content, especially near cell cracks. The second case study compared field‐retrieved modules with cracked and intact AAA backsheets immersed in water. The cracked module absorbed water more rapidly, with water content an order of magnitude higher than the intact one. The presented approach offers a powerful quality assurance and inspection tool for module manufacturers and solar developers, supporting improved moisture‐resistant module designs, timely mitigation measures, and more precise durability forecasts.

In 2016 Passivated Emitter and Rear Cell (PERC) solar cells started to dominated the PV industry as cell technology. Since 2023, the prices of Tunnel Oxide Passivated Contact (TOPCon) and Heterojunction (HJT) solar cells have become lower, leading to a strong decline in PERC technology till today. TOPCon is now (2025) the mainstream cell technology, while HJT and BC (Back Contact) cells are gaining market share. All technologies feature different cell sizes and quantities, resulting in higher voltages, currents and different reverse characteristics compared to PERC. One major challenge in integrating these new technologies into existing module designs is understanding the reverse bias behavior of solar cells to avoid excessive overheating of partially shaded cells. Evaluating this behavior is crucial for the durability and reliability of PV modules when fully / partially shaded. In such scenarios, shaded cells operate as a load, altering current flow. If the voltage of the series-connected cells exceeds the reverse breakdown voltage of a single cell, that cell can undergo electrical breakdown in reverse bias, consuming energy produced by the other cells. Excessive heat generation due to defects can lead to hot-spots, melting of encapsulants or solder, glass breakage, and even fires. Given the trend toward larger cells (G12, M10) and higher cell quantities (more than 20) for increased module power, a reevaluation of the breakdown behavior of solar cells is urgently needed. To properly understand the behavior of new solar cell technologies in the market, all major architectures were evaluated. Mini-modules were manufactured with the different cell architectures and characterized in forward and reverse bias. The cells/mini-strings were measured at irradiance levels from 100 to 1300 W/m ² in the 1st quadrant all the way to reverse breakdown in the 2nd quadrant. This was especially challenging for HJT and TOPCon cells as they have a pronounced hysteresis effect in the 1st quadrant. However, neither TOPCon nor HJT shows an accountable hysteresis in the reverse breakdown region. As both technologies are bifacial, the behavior is not significantly different between front and rear side. Besides the higher breakdown voltages, −44 to −49V and around −30V for TOPCon and HJT, respectively, their irradiance dependent reverse current increase is compared to PERC low to very low. The results of TOPCon and HJT solar cells show a promising reverse breakdown behavior even with strings with higher number of solar cells under full and potentially also under partial shading conditions.

With the introduction of new cell formats M10, M10R, and especially M12, PV modules have significantly increased in size. The availability of thin tempered glass (<2 mm) has led to a rise in glass-glass modules, which offer a high moisture barrier and minimize cell breakage by placing cells in the neutral axis. However, this increase in size also results in higher weight. To mitigate this, both glass thickness and frame height are being reduced, which brings the mechanical load-bearing capacity of glass and frames into focus. The mechanical stiffness of current frames (28 to 35mm height) is considerably lower than older frames (40mm and above), leading to greater flexibility and deformation under mechanical loads. As material thickness remains typically constant, the strength requirements for components increase. Increased deflection can cause contact between the PV module and substructure at loads significantly below 2,400 Pa (IEC 61215-2 minimum load). While this was not a major concern in the past, module manufacturers now actively exploit it for load approvals. Installers of small PV systems must carefully read installation manuals to understand permissible loads. The situation is even more critical for large systems that utilize bifaciality, as the entire load is transferred through the frame and clamps/screws. Finite element simulations and mechanical load tests demonstrate the importance of using the correct substructure for testing the mechanical load capacity of PV modules and highlight potential interactions. Various module sizes and substructure variants are simulated to compare deformation and stress results.

The development of photovoltaic (PV) modules made of bio-degradable materials from renewable resources offers numerous advantages. It reduces the ecological footprint of the photovoltaic industry and promotes its sustainability. The use of these materials reduces the use of non-renewable resources and minimizes the environmental impact during the full life cycle of the PV module. One limitation of PV modules made from renewable raw materials is their typical limited durability compared to conventional PV modules. Due to their natural properties, biodegradable materials may not offer the same longevity and resistance to environmental influences as conventional materials. This can lead to a shortened lifespan of the modules and affect their long-term performance. The aim of this work is to present a screening of possible material candidates that may be suitable for achieving at least partially substitution of components of standard crystalline PV module with recycled, bio-based or bio-degradable materials. The focus lies on encapsulation, backsheet and module frame as replacement for aluminum. It is shown how these materials behave under the standard requirements of the PV industry, which materials are generally suitable and which mechanisms could prove to be showstoppers. The selected wood-based material as substitute for aluminum showed resistance in aging tests, but the dependence of the properties on the moisture content must be considered. In the design process differences to aluminum regarding fracture behavior must be considered with appropriate design safety factors. From 6 initial variants for mini-module manufacturing only two were identified for further investigation. Material weaknesses were identified in long-term IEC 61215-2 Damp Heat (DH) tests and the sequential test Sequence B of IEC 61730-2. The variant of EVA with bio-degradable additive and bio-based backsheet and polyamid based backsheet were identified as suitable for further testing. The tested bio-degradable materials were identified as not suitable because the temperature and humidity involved in the standard tests lead, even after short testing intervales, to severe material degradation. As result, the materials could no longer fulfill its protective function for the cells.

Sustainability and resource‐efficiency are the major topics for the 21st century. Most of the PV modules are manufactured of glass, polymers, metals, and silicon‐based solar cells. All these materials have the potential to be substituted by sustainable products. The substitution of materials for PV modules is challenging because of issues in significant unknown risks for short‐ and long‐term reliability of the PV module. Investigations for material and process routes of a 100% renewable solar module are necessary. This study investigates the suitability and reliability of different materials. For example, the reliability of an electrically conductive adhesive (ECA) to a leaded‐solder reference is under investigation as well as various polymers (recycled, bio‐based, or biodegradable). In the first step, the interconnections are tested with a standard module encapsulation bill of materials (known good reference). In the second step, the module encapsulation and backsheet materials are substituted by their sustainable counterparts. The goal is to identify the most promising material combinations for further integration of lead‐free interconnected solar cells. Reliability is assessed using accelerated ageing tests in accordance with IEC 61215/IEC 61730 with standard test duration and extended test duration for each material and interconnection batches. The condition of the samples is assessed by regular visual inspection, power measurements, and electroluminescence images. The study aims to demonstrate and assess the suitability and reliability of the selected material combinations to enable the steps toward a renewable material solar module.

Crystalline silicon solar cells were, are and will continue to dominate the Photovoltaic PV module market. In the past decade, significant efforts have been made to better understand and characterize observations using Electro-Luminescence (EL) to investigate the appearance of c-Si solar cells. While standards have been developed, a clear definition of the nomenclature for observations in EL images is still missing. Within the project PV-Riss, a group comprising manufacturers, advisory experts and research facilities worked on an overview of various observations found in the literature (typically of Al-BSF and PERC cells). The individual observations were categorized into four main categories, namely: 1) single cracks, 2) multi-cracks, 3) anomalies in the electrical circuit and all others into 4) miscellaneous. Each category includes several subcategories to include most relevant observations within EL images. These categories can be applied to all existing and new cell types and are independent on the size (ranging from “old” 4” to new M/G12), shape (full, half, third, x-cut), material (mono, multi), or cell technology (AlBSF, PERC, TOPCON, HJT, IBC, Perovskite on Si), as well as of the PV module design (size, glass/backsheet, glass/glass, internal wiring of the electric circuit). Along with a detailed description of observations in EL images, several important definitions are provided that are essential for general understanding, nomenclature, and the mapping of observations to ensure clear and comprehensive communication and reporting. Following the definition of most relevant observations, key observations will be discussed within a classification proposal. This classification proposal aims to facilitate future discussions and to assess EL observations, combining the risk of power loss that exceeds warranty with the probability of potential electrical safety risk.