## 5 Power Generation Performance Loss Factor of the BIPV System
### Module Surface Temperature  
Figure 5 shows the monthly module surface temperature of each PV array in the form of a box-and-whisker plot. The marker in the middle represents the mean; the box represents the mean \(\pm\) deviation; the whiskers represent the maximum and minimum values. Figure 4: Performance ratio and loss of each array. The PV module surface temperature of SI 30\({}^{\circ}\) continued to show the distribution of the highest temperatures throughout the year. The temperature distribution of SV 90\({}^{\circ}\) was similar to that SI 30\({}^{\circ}\) in the winter. WV 90\({}^{\circ}\) showed a distribution of the lowest temperatures during winter, but it exhibited a distribution of high temperatures approximating to that of SI 30\({}^{\circ}\) during summer. The PV module surface of HR 0\({}^{\circ}\) showed a distribution of low temperatures throughout the year, regardless of the season. This is in contrast to the general temperature behavior of the horizontal plane receiving the highest accumulated irradiation during summer. Although the other three PV arrays were integrated into the building replacing a window, the PV array of the horizontal plane was installed in the form of a rooftop pergola that is exposed to ambient air. As a result, rear ventilation was possible, which explains why it showed a lower temperature distribution than the other three PV arrays. Table 4 lists the analysis results of the monthly averaged PV module surface temperatures under each installation condition. Figure 6 shows the DC power according to the changes in irradiation and temperature-corrected DC power. The temperature-corrected DC power was calculated using Equation (7). The temperature-corrected DC power is the value that includes the amount of DC power that is lost due to the temperature increase. The difference between the DC power and temperature-corrected DC power makes it possible to analyze the losses caused by an increase in the module temperature in each array. Based on the analysis results shown in Figure 6, the annual DC power losses due to an increase in temperature were calculated, as shown in Figure 7. \begin{table}
\begin{tabular}{c c c c c c c c c c c c} \hline \({}^{\circ}\)**C** & **Jan.** & **Feb.** & **Mar.** & **Apr.** & **May** & **Jun.** & **Jul.** & **Aug.** & **Sep.** & **Oct.** & **Nov.** & **Dec.** \\ \hline HR 0\({}^{\circ}\) & 12.4 & 11.6 & 22.5 & 31.5 & 40.0 & 43.3 & 40.3 & 41.1 & 37.8 & 32.6 & 20.0 & 10.3 \\ SI 30\({}^{\circ}\) & 21.1 & 22.8 & 30.5 & 38.3 & 46.3 & 48.9 & 51.3 & 44.7 & 44.5 & 42.0 & 29.0 & 23.1 \\ SV 90\({}^{\circ}\) & 20.9 & 20.1 & 25.1 & 31.1 & 36.9 & 39.3 & 42.1 & 44.4 & 39.9 & 38.9 & 29.5 & 23.6 \\ WV 90\({}^{\circ}\) & 14.0 & 14.7 & 20.4 & 33.7 & 40.0 & 43.1 & 48.2 & 45.6 & 37.6 & 34.2 & 22.3 & 13.1 \\ \hline \end{tabular}
\end{table} 
Table 4: Monthly averaged photovoltaic (PV) module surface temperature of each array. Figure 5: Monthly module surface temperature of each array. As a result of analyzing the ratio of the annual energy production lost due to an increase in temperature with respect to the measured DC power, the ratio was 4.6% for HR 0\({}^{\circ}\), 6.0% for SI 30\({}^{\circ}\), 3.9% for SV 90\({}^{\circ}\), and 2.2% for WV 90\({}^{\circ}\). In other words, the annual DC power loss was estimated to be 2.2-6.0%. The largest DC power loss was found to occur in SI 30\({}^{\circ}\), which showed the highest PV module surface temperature, and the lowest power generation loss occurred in WV 30\({}^{\circ}\). This result of the analysis occurred, despite the fact that the monthly averaged PV module surface temperature of the horizontal plane was low because the rate of the distribution of temperatures over 50 \({}^{\circ}\)C was higher in the horizontal plane than in the south vertical plane. Figure 6: Direct current (DC) power and temperature corrected DC power trend to each array in relation to the irradiation.