Solar PV potential at one of the world’s northernmost settlements

Researchers from Norway’s SINTEF have assessed the potential contribution of solar PV to the transition away from fossil fuel-based energy in Longyearbyen, the administrative center of Norway’s Svalbard archipelago and one of the world’s northernmost permanently inhabited settlements. The study examines how Arctic environmental conditions influence PV performance and deployment, with a particular focus on low temperatures, extreme seasonal variations in solar irradiance, snow accumulation and icing, snow drifting, and permafrost-related ground conditions.

“There is a limited literature on how PV performs and should be designed in extreme Arctic environments,” said corresponding author Berhane Darsene Dimd to pv magazine. “Our work combines solar resource and PV performance analysis with Arctic-specific environmental constraints, real case study evidence, and system-level considerations such as the complementarity between PV, wind power, and storage.”

The research comprised four main elements: a literature-based assessment of Arctic environmental conditions and their impact on PV performance; a comparative analysis of solar resource availability and PV performance indicators in Longyearbyen, Trondheim (mainland Norway), and Munich, Germany, using PV simulation tools and open-access climate datasets; a review of published case studies and energy transition scenarios relevant to Longyearbyen; and an evaluation of the design adaptations required to integrate PV into the settlement’s future energy mix.

The comparative analysis showed that Longyearbyen can achieve a peak solar irradiance of 6.25 kWh/m²/day and a peak PV capacity factor of 19.28%. This capacity factor is comparable to Trondheim’s summer peak of 19.32% and only slightly lower than Munich’s 21.13% during the same period. Published energy transition scenarios suggest that a fully renewable energy system for Longyearbyen would require between 3 MW and 7.5 MW of PV capacity when integrated with other renewable technologies, while an isolated renewable system could require as much as 119 MW of installed PV capacity.

“Longyearbyen, despite its extreme Arctic conditions and complete absence of PV generation during the polar night in the winter, still shows strong PV performance during late spring and summer,” said Dimd. “In these months, the capacity factor is comparable to locations in mid-latitude regions, because the albedo effect and the long daylight duration compensate for the low solar elevation.”

The analysis showed that Longyearbyen has approximately 188,000 m² of suitable rooftop area for PV deployment, with the potential to generate around 24 GWh of electricity annually. Local case studies further demonstrated the viability of solar generation in Arctic conditions. The 13.77–14.04 kW Elvesletta Syd building-integrated PV (BIPV) systems achieved a specific yield of 621 kWh/kW, while the 137 kW PV installation at Svalbard Airport recorded a specific yield of 500 kWh/kW.

“We also found that PV system design choices are very important in Arctic environments. Tilt angle, azimuth, tracking strategy, snow management, and bifacial modules all significantly affect performance,” said the researcher. “For example, the analysis showed that south-facing fixed systems with a 45° tilt performed best among the fixed mono-facial configurations considered, while single-axis tracking could improve the capacity factor substantially. However, because Arctic systems also face higher costs, mechanical stress, snow accumulation, and maintenance challenges, the best technical option is not always automatically the best economic option. A tradeoff is always important.”

Dimd also highlighted the strong seasonal complementarity between solar and wind resources in Longyearbyen. While PV generation is concentrated during the brighter spring and summer months, wind resources are generally more abundant during the dark winter period.

“This indicates that PV should not be evaluated as a stand-alone solution in Longyearbyen, but rather as part of an integrated renewable energy system combining wind power with both short-term and seasonal energy storage,” he said.

In conclusion, Dimd said that the next logical step for his team would be to move from system-level and simulation-based assessment to more detailed techno-economic and operational studies. “This would include accurate modeling of PV, wind, storage, heating demand, and grid constraints in Longyearbyen, together with real-world validation of PV performance under Arctic snow, icing, wind, and low-temperature conditions. In particular, we see a need to quantify better snow-related losses, bifacial gains, and the cost-reliability tradeoffs of different PV configurations in remote Arctic communities,” he stated.

The research work was presented in “The role of photovoltaic energy in Arctic energy system transition: Technical potential and challenges in Longyearbyen, Svalbard,” published in Renewable Energy.