Compared with standard monofacial photovoltaic (PV) systems, the simulation of the energy yield of bifacial PV systems is more challenging since the impact of factors such as the installation height, the ground albedo, shadowing of neighbored rows, the diffuse irradiance fraction, and the PV module design is more pronounced. Therefore, many academic institutions as well as companies are currently working on the development of suitable modeling tools that allow an accurate energy yield prediction of bifacial systems. In this article, we present the results of energy-yield simulations of bifacial PV systems with fixed tilt and horizontal single-axis tracking (HSAT) in comparison to their monofacial counterparts using a tool that has been developed at ISC Konstanz. In addition, the simulated data are compared with measured results. The energy yield of fixed tilt bifacial systems is simulated as a function of the number of rows and number of modules in a row as well as a function of the installation height. The simulated data have been compared with measured data obtained using a PV system with continuously changing tilt angels. The accuracy of the simulated data is shown to be from $+/-0.1$ % to $+/-4$ % depending on the tilt angle of the bifacial modules. In addition, the energy yield of bifacial HSAT PV systems have been simulated and compared with measured data for a bifacial HSAT system in Chile. In this comparison, the use of ray tracing instead of the view factor (VF) concept for modeling of the rear irradiance reduced the deviation between simulated and measured gain significantly. Therefore, the approach of using VF-based calculations for the front irradiance and ray tracing for the rear irradiance was then used to evaluate different bifacial system configurations in comparison to monofacial ones. Especially, the influence of a variation of the ground coverage ratio on the energy yield for various monofacial, bifacial fixed tilt, and HSAT systems was studied.

The size and number of utility-scale bifacial photovoltaic (PV) installations has proliferated in recent years but concerns over modeling accuracy remain. The aim of this work is to provide the PV community with a validation study of eight tools used to simulate bifacial PV performance. We simulate real 26 kilowatt-peak (kW_p) bifacial arrays within a 420-kW_p site located in northern Europe (55.6° N, 12.1° E). The substructures investigated include horizontal single-axis trackers (HSATs) and fixed tilt racks that have dimensions analogous to those found in utility-scale PV installations. Each bifacial system has a monofacial reference system with similar front side power. We use on-site solar radiation (global, diffuse, and beam) and albedo measurements from spectrally flat class A sensors as inputs to the simulation tools, and compare the modeled values to field measurements of string level power, rear and front plane of array irradiance, and module temperature. Our results show that state-of-the-art bifacial performance models add ~0.5% uncertainty to the PV modeling chain. For the site investigated, 2-D view factor fixed tilt simulations are within ±1% of the measured monthly bifacial gain. However, simulations of single-axis tracker systems are less accurate, wherein 2-D view factor and 3-D ray tracing are within approximately 2% and 1% of the measured bifacial gain, respectively.

One of the prerequisites for a reliable energy yield prediction of bifacial photovoltaic (PV) systems is the capability of modeling the backside irradiance of those systems with high accuracy. Currently, the most important optical models used to quantify the reflected irradiance on the backside of a bifacial solar panel are view factor and ray tracing. The MoBiDiG simulation tool has been developed at ISC Konstanz uses the view factor (VF) concept to model the rear irradiance. In addition to the VF concept, ray tracing (RT) has been adopted to determine the backside irradiance of bifacial modules by using the open‐source tool bifacial_radiance that has been developed by the National Renewable Energy Laboratory (NREL). A customized monocrystalline silicon solar panel has been built in order to evaluate the accuracy of the existing optical models by locally resolved rear irradiance measurement. The performance of rear irradiance has been investigated along the rows of the customized PV module during sunny and cloudy days with typical back irradiance values of 50 and . The comparison of measured and modeled data has been carried out on hourly, daily, and monthly basis, and the results show lower deviations for solar cells located in the center of the PV module than on the edge. Moreover, the concept of decisive solar cells has been introduced and applied to both measured and modeled data, solar cells located in the center rows were found to act as the most decisive solar cells. Finally, considering the installation configuration studied here, ie, bifacial mounting with low clearance height (below 0.2 m), both hourly RT and VF approaches are able to model long‐term cumulative irradiance received by decisive solar cells with a very high accuracy ranging from 0.5% to 2%.

In recent years, global PV capacity – particularly in the EU – has reached record levels, supporting decarbonization goals but also intensifying market effects such as increasingly frequent negative electricity prices driven by oversupply and limited system flexibility. These conditions pose growing economic challenges for utility-scale PV assets. This study examines the impact of negative price hours on PV performance and assesses the role of battery energy storage systems (BESS) in mitigating these effects, using Germany as a case study. A temporal analysis identifies pronounced seasonal and diurnal patterns, with negative prices peaking in spring and around midday. Under high negative electricity price scenarios, PV systems experience curtailment-related energy losses of up to 10%, while BESS output increases through active participation in day-ahead and intraday markets. Contrary to common assumptions, increasing BESS capacity does not significantly reduce PV curtailment or enhance PV-specific value. Instead, while total system revenues (PV – BESS) rise monotonically with storage size, the gains are driven entirely by BESS revenues. Economically, standalone PV systems exhibit substantial value erosion, whereas hybrid PV-BESS configurations demonstrate greater resilience and higher net present value (NPV) across all scenarios. These findings underscore that the primary value of storage lies in market-based revenue generation rather than curtailment mitigation, highlighting the strategic importance of storage-ready PV designs, either integrated at deployment or retrofitted to preserve asset value in increasingly volatile electricity markets.