Created by G.F., SUPSI, on 27.11.2025
Photovoltaic systems deployed in cold climates, as present at high-altitudes and high- latitudes, exhibit compared to other climatic zones some of the lowest degradation rates. This is primarily due to the low operating temperatures which slow down thermally driven degradation mechanisms as chemical (polymer) degradation, while mechanical, thermo-mechanical and UV stressors become dominant. Global climate-specific modelling studies indicate that cold climates can potentially reach below -0.25%/year on average [1] if modules and systems are designed to withstand the present mechanical stressors due to snow, ice or high wind speeds.
However, if this is not the case the risk of catastrophic failures is increasing significantly with respect to moderate climate zones. Alpine systems face stresses from snow loads, freeze–thaw cycles, low-temperature embrittlement, and moisture ingress, which define the particular reliability challenges of PV operation in these regions. Therefore, for sure less robust modules and UV or humidity-susceptible materials increase the risk of module damage and higher degradation rates. The optimization of PV modules for alpine environments is reducing these risks of underperforming or catastrophic failure of PV systems.
Figure 1: Distribution of modeled degradation rates in different Köppen-Geiger PV (KGPV) climate zones. The width of each shape represents the density of degradation rates within each zone. KGPV climate legend: A(tropical), B(desert), C(steppe), E(temperate), D(cold), F(polar), K(very high irradiance), H(high irradiance), M(medium irradiance), L(low irradiance) [1].
Experience from PV systems installed at high latitudes, presented in the report of the IEA PVPS Task 13 [2], confirm these data. For example, long-term field data across continental and polar climates (44–65°N) from a study of Tonita at el., showed a median degradation rate of −0.33%/year [3], which is significantly lower than the −0.75%/year observed across ~1700 systems in the continental United States [4].
Figure 2: (a) The location of reported degradation rates for 27 mc-Si and c-Si PV systems with ≥ 3 years of field exposure in Dfb, Dfc, or ET climates. (b) The distribution of reported degradation rates in cold climates covering Dfb, Dfc, and ET Köppen–Geiger climates [3].
Compared to arctic climates, high altitude or alpine climates are characterized by higher cumulative irradiance, elevated UV doses and stronger diurnal and seasonal temperature fluctuations. Despite of this similarly lower degradation rates for cold climates have been observed in Switzerland [5, 6].
Figure 3: (a) Temperature-corrected performance ratio (PR′) trends of 6 different systems in Switzerland installed at different altitudes. (b) Peformance loss rates with 95% confidence interval. [6].
A recent meta-analysis from the University of Augsburg [7] based on 80 studies, reporting 610 degradation rate observations, identified cold and dry environments to be optimal locations to maximize the photovoltaic lifespan, with a predicted average degradation rate of 0.43%/year corresponding to 47 years of lifespan.
Most of the existing studies concern older module technologies based on thicker BSF cells and more robust design respect to today’s commercialized PV modules. There are few studies on long-term reliability under repeated winter stress (cold, snow, wind, UV) of emerging modules, characterized by increasing size, thinner glass, new generation TOPCon, Hetero-junction or back-contact cells and bifacial module design.
One recent study of 189 bifacial PERC modules installed in northern Europe over 4.5 years, conducted by Bartholomäus et al. [8], reported encouraging low to moderate degradation rates (0.36–0.75 % per year) for most module types, and severe losses for one type, primarily attributed to potential-induced degradation (PID) and UV-induced faults. Overall, in this study bifacial modules exhibited slightly higher early-life degradation compared to mono-facial modules, with failures mainly linked to contact issues and rear-side degradation mechanisms, rather than to typical encapsulant defects.
References
[1] J. Ascencio-Vásquez, I. Kaaya, K. Brecl, K. A. Weiss, and M. Topič, “Global climate data processing and mapping of degradation mechanisms and degradation rates of PV modules,” Energies, vol. 12, no. 24, pp. 1–16, 2019, https://doi.org/10.3390/en12244749
[2] “Photovoltaics and Energy Security in the Greater Arctic Region,” Report IEA-PVPS T13-40:2025, to be published soon on IEA PVPS webpage.
[3] Tonita, E. M., Jordan, D. C., Ovaitt, S., Toal, H., Hinzer, K., Pike, C., and Deline, C.,
“Long-Term Photovoltaic System Performance in Cold, Snowy Climates,” Prog. Photovolt.
Res. Appl. https://doi.org/10.1002/pip.70014
[4] Jordan, D. C., Anderson, K., Perry, K., Muller, M., Deceglie, M., White, R., and Deline,
C., 2022, “Photovoltaic Fleet Degradation Insights,” Prog. Photovolt. Res. Appl., 30(10),
pp. 1166–1175. https://doi.org/10.1002/pip.3566
[5] U. Muntwyler and T. Schott, “Degradation of photovoltaic systems based on long-term measurements and laboratory tests,” in Proceedings of EuroSun 2018, Freiburg, Germany: International Solar Energy Society, 2018, pp. 1–7. https://doi.org/10.18086/eurosun2018.02.07
[6] E. Özkalay, H. Quest, and A. Gassner, “Three Decades, Three Climates: Assessing Environmental and Material Effects on PV Module Reliability,”. https://doi.org/10.1039/D4EL00040D
[7] Michael Straub-Mück, Jerome Geyer-Klingeberg, Andreas W. Rathgeber, “Determinants of the long-term degradation rate of photovoltaic modules: A meta-analysis,” in Renewable and Sustainable Energy Reviews, Volume 216,2025. https://doi.org/10.1016/j.rser.2025.115697
[8] Martin Bartholomäus, Nicholas Riedel-Lyngskær, Luca Morino, Mahmoud Dhimish, Petros Stefanidis, Iltrice Razanakoto, Maxime Deru, Peter B. Poulsen, Sergiu V. Spataru, “Field degradation of bifacial photovoltaic modules in northern Europe,” Solar Energy, Volume 300, 2025. https://doi.org/10.1016/j.solener.2025.113786
