This paper presents the first systematic comparison between south-facing monofacial and bifacial photovoltaic (PV) modules, as well as between south-facing bifacial and vertical east-west facing bifacial PV modules in Alaska. The state’s solar industry, driven by the high price of energy and dropping equipment costs, is quickly growing. The challenges posed by extreme sun angles in Alaska’s northern regions also present opportunities for unique system designs. Annual bifacial gains of 21% were observed between side by side south-facing monofacial and bifacial modules. Vertical east-west bifacial modules had virtually the same annual production as south-facing latitude tilt bifacial modules, but with different energy production profiles.

Accurate modeling of photovoltaic (PV) systems is critical for the design, financial analysis, and monitoring of solar PV plants. For bifacial PV applications, models must additionally offer robust rear-side irradiance algorithms. However, bifacial PV irradiance models have yet to be sufficiently validated for east–west vertically oriented systems, where direct beam solar irradiation swaps at solar noon. Here, we validate five bifacial irradiance models with field data collected in Golden, CO, USA (40°N) and Fairbanks, AK, USA (65°N) for east–west vertical, north–south vertical, and south-tilted arrays. There is no clear best performer among subhourly models; Bifacial_radiance, bifacialVF, the System Advisor Model, and dual-sided energy tracer (DUET) comparably predict seasonal and daily changes in PV production, with root-mean-squared error (RMSE) falling in the range of 11–28% depending on the location and system orientation. PVSyst (v7.4.8), limited by hourly resolution, demonstrates RMSE in the range of 33–45%. The primary causes of high RMSE are similar for all models; using an irradiance cutoff of >100 W/m², using clear-sky filtering, and removing time stamps with snow, lowers model RMSE to 4–13% for subhourly models and 12–25% for PVSyst. Regular meteorological station servicing is found to further decrease model RMSE by up to 3% abs. in Alaska. Finally, we model bifacial PV systems in over 250 locations between 15 and 85°N, finding that deviations between model-predicted annual insolation tend to be 2–3× higher for vertical PV systems than south-facing fixed-tilt systems. We discuss potential methods for improving vertical PV modeling and provide recommendations for high-quality field data collection in northern environments.

Heat pumps are a proven technology around the world and are being increasingly used in Alaska. Technological advances have improved their performance at low temperatures, making them more suitable for arctic environments. This analysis identified data related to 17 heat pumps installed in Alaska, which included air source, ground source, and sea water source systems. The data show that the average installed cost/kW of the heat pumps studied was $5,579. The minimum cost was just over $700/kW for a small air source minisplit system and over $12 000 for a complex vertical loop ground source heat pump. Air source heat pumps in Alaska have operated successfully down to −15 °C. Technological advances are ongoing that should enable further heat pump operation in colder climates.

Solar photovoltaic (PV) technology is a nascent but promising energy option in remote Alaskan microgrids and serves as an example for isolated electrical grids worldwide. This study examines community scale solar PV installations in Alaska, ranging in size from 2.2 kW in Ambler to 50 kW in Galena. Total installed costs arguably show a trend toward lower values with larger installation sizes although prices in Alaska are still significantly higher than in the rest of the United States. Capacity factors range from 6% to 15%. However, it should be noted that some installation configurations, particularly in the northwestern part of the state, were installed with the goal of a broad production curve rather than maximum power production.

As photovoltaic (PV) deployment increases worldwide, PV systems are being installed more frequently in locations that experience snow cover. The higher albedo of snow, relative to the ground, increases the performance of PV systems in northern and high-altitude locations by reflecting more light onto the PV modules. Accurate modeling of the snow’s albedo can improve estimates of PV system production. Typical modeling of snow albedo uses a simple two-value model that sets the albedo high when snow is present, and low when snow is not present. However, snow albedo changes over time as snow settles and melts and a binary model does not account for transitional changes, which can be significant. Here, we present and validate a model for estimating snow albedo as it changes over time. The model is simple enough to only require daily snow depth and hourly average temperature data, but can be improved through the addition of site-specific factors, when available. We validate this model to quantify its ability to more accurately predict snow albedo and compare the model’s performance against satellite imagery-based methods for obtaining historical albedo data. In addition, we perform modeling using the System Advisor Model (SAM) to show the impact of changes in albedo on energy modeling for PV systems. Overall, our albedo model has a significantly improved ability to predict the solar insolation on PV modules in real time, especially on bifacial PV modules where reflected irradiance plays a larger role in energy production.