Depending on the PV system, other factors may affect PV system output. Here are some common ones used in NREL’s PVWatts calculator:
PV module nameplate DC rating: Testing has shown that module nameplate power ratings tend to be a bit optimistic, but by how much? A good place to start is the manufacturer’s power tolerance specification. For example, you might see “Pmax = 250 W, -5%/+10%” on the module data sheet, which means this module is warranted to produce between 237.5 and 275 W at STC. It’s generally best to use the lowest rating. In this example, we will use the -5% tolerance, for a nameplate rating factor of 0.95.
Inverter: We also need to account for the power it takes to convert the DC electricity from the PV array to AC, and we can do so by factoring in the inverter efficiency. While inverter specification sheets will list “maximum efficiency,” a more useful value is the “weighted efficiency,” which accounts for the percentage of time the inverter commonly spends at various power levels. This gives a better indication of the inverter’s real-world efficiency. Most grid-direct inverters have weighted efficiencies greater than 90%. You can find inverter weighted efficiency ratings on the Go Solar California website: (bit.ly/CAeligInv). In this example, we use 0.96 for our inverter efficiency factor.
Module mismatch: Include this factor unless the PV system has maximum power point tracking (MPPT) capability at the module level, using microinverters or DC optimizers. Due to slight differences in modules’ IV curves, or power output profiles, the one MPP used for an entire array or series string will not be a perfect fit for each individual module. A small power loss will result. If there are different makes and models of modules in the array, the power loss will be even greater. If individual series strings of modules have their own MPPT, the loss will be less. Most PV arrays with one kind of module and a single MPPT for the entire array will experience a 2% loss due to module mismatch, so we will use a 0.98 mismatch factor.
Wiring losses: Wire connections and the DC wire runs introduce losses due to resistance. Since we are measuring inverter output at the inverter, we should not include AC wire losses. Most well-designed systems will have about a 0.5% loss due to connections, and about a 2% loss in the DC wiring. If system designers did not account for voltage drop on a long wire run, or there are poor wire connections, these losses might be greater. We’ll assume our system fits the numbers stated above, for a total DC wiring loss of 2.5%, for a 0.975 wiring loss factor.
Soiling: Modules get dirty. In places with lots of dust, few significant rain storms, and buildup of other small debris, this factor can be significant. Modules set at a lower tilt tend to have more soiling. Let’s assume we’re in an area with “normal” dust, and our array is tilted to about 40° (steep enough to shed most gunk). The modules don’t look dirty from the ground, but it hasn’t rained in a while. We will use 0.97 for our soiling factor.
Age: On average, crystalline silicon modules lose about 0.5% of their output power capacity per year. A new installation would have no age-related losses. The array in our example was installed six years ago, so we’ll assume a 0.97 age factor. (Note that degradation rates may vary due to climate effects and may not be linear over time.)
Shading: Quantifying the effects of shading on annual production is fairly easy with site analysis tools. But accurately determining the effects of partial shade on an array at any one time is very difficult. Therefore, you need to choose a time when the array is not shaded to make your measurements.
Now that we have determined all of the other losses, we find the total by multiplying them together. This number will be our final factor:
Other losses factor = 0.95 × 0.96 × 0.98 × 0.975 × 0.97 × 0.97 = 0.82