How to Change Parameters
The PVWattsTM calculator allows users to substitute its default input parameters with custom values. Learn how to change the PVWatts parameters for:
The size of a photovoltaic (PV) system is its nameplate DC power rating. This is determined by adding the PV module power listed on the nameplates of the PV modules in watts and then dividing the sum by 1,000 to convert it to kilowatts (kW). PV module power ratings are for standard test conditions (STC) of 1,000 W/m2 solar irradiance and 25°C PV module temperature. The default PV system size is 4 kW. This corresponds to a PV array area of approximately 35 m2 (377 ft2).
Caution: For correct results, the DC rating input must be the nameplate DC power rating described above. It cannot be based on other rating conditions, such as PVUSA test conditions (PTC). PTC are defined as 1,000 W/m2 plane-of-array irradiance, 20°C ambient temperature, and 1 m/s wind speed. If a user incorrectly uses a DC rating based on PTC power ratings, the energy production calculated by the PVWatts calculator will be reduced by about 12%.
DC-to-AC Derate Factor
The PVWatts calculator multiplies the nameplate DC power rating by an overall DC-to-AC derate factor to determine the AC power rating at STC. The overall DC-to-AC derate factor accounts for losses from the DC nameplate power rating and is the mathematical product of the derate factors for the components of the PV system. The default component derate factors used by the PVWatts calculator and their ranges are listed in the table below.
Derate Factors for AC Power Rating at STC
|Component Derate Factors||PVWatts Default||Range|
|PV module nameplate DC rating||0.95||0.80–1.05|
|Inverter and transformer||0.92||0.88–0.98|
|Diodes and connections||0.995||0.99–0.997|
|Overall DC-to-AC derate factor||0.77||0.09999–0.96001|
The overall DC-to-AC derate factor is calculated by multiplying the component derate factors.
For the PVWATTS default values:
Overall DC to AC derate factor
= 0.95 x 0.92 x 0.98 x 0.995 x 0.98 x 0.99 x 0.95 x 0.98 x 1.00 x 1.00 x 1.00
The value of 0.77 means that the AC power rating at STC is 77% of the nameplate DC power rating. In most cases, 0.77 will provide a reasonable estimate. However, users can change the DC-to-AC derate factor. The first option is to enter a new overall DC-to-AC derate factor in the provided text box. The second option is to click the Derate Factor Help button. This provides the opportunity to change any of the component derate factors. The derate factor calculator then calculates a new overall DC-to-AC derate factor.
The component derate factors are described below.
PV module nameplate DC rating
This accounts for the accuracy of the manufacturer's nameplate rating. Field measurements of PV modules may show that they are different from their nameplate rating or that they experience light-induced degradation upon exposure. A derate factor of 0.95 indicates that testing yielded power measurements at STC that were 5% less than the manufacturer's nameplate rating.
Inverter and transformer
This reflects the inverter's and transformer's combined efficiency in converting DC power to AC power. A list of inverter efficiencies by manufacturer is available from the Consumer Energy Center. The inverter efficiencies include transformer-related losses when a transformer is used or required by the manufacturer.
The derate factor for PV module mismatch accounts for manufacturing tolerances that yield PV modules with slightly different current-voltage characteristics. Consequently, when connected together electrically, they do not operate at their peak efficiencies. The default value of 0.98 represents a loss of 2% because of mismatch.
Diodes and connections
This derate factor accounts for losses from voltage drops across diodes used to block the reverse flow of current and from resistive losses in electrical connections.
The derate factor for DC wiring accounts for resistive losses in the wiring between modules and the wiring connecting the PV array to the inverter.
The derate factor for AC wiring accounts for resistive losses in the wiring between the inverter and the connection to the local utility service.
The derate factor for soiling accounts for dirt, snow, and other foreign matter on the surface of the PV module that prevent solar radiation from reaching the solar cells. Dirt accumulation is location- and weather-dependent. There are greater soiling losses (up to 25% for some California locations) in high-trafffic, high-pollution areas with infrequent rain. For northern locations, snow reduces the energy produced, and the severity is a function of the amount of snow and how long it remains on the PV modules. Snow remains longest when sub-freezing temperatures prevail, small PV array tilt angles prevent snow from sliding off, the PV array is closely integrated into the roof, and the roof or another structure in the vicinity facilitates snow drift onto the modules. For a roof-mounted PV system in Minnesota with a tilt angle of 23°, snow reduced the energy production during winter by 70%; a nearby roof-mounted PV system with a tilt angle of 40° experienced a 40% reduction.
The derate factor for system availability accounts for times when the system is off because of maintenance or inverter or utility outages. The default value of 0.98 represents the system being off 2% of the year.
The derate factor for shading accounts for situations in which PV modules are shaded by nearby buildings, objects, or other PV modules and arrays. For the default value of 1.00, the PVWatts calculator assumes the PV modules are not shaded. Tools such as Solar Pathfinder can determine a derate factor for shading by buildings and objects. For PV arrays that consist of multiple rows of PV modules and array structures, the shading derate factor should account for losses that occur when one row shades an adjacent row.
The figure below shows the shading derate factor as a function of the type of PV array (fixed or tracking); the ground cover ratio (GCR), defined as the ratio of the PV array area to the total ground area; and the tilt angle for fixed PV arrays. As shown in the figure, spacing the rows further apart (smaller GCR) corresponds to a larger derate factor (smaller shading loss). For fixed PV arrays, if the tilt angle is decreased, the rows may be spaced closer together (larger GCR) to achieve the same shading derate factor. For the same value of shading derate factor, land area requirements are greatest for two-axis tracking, as indicated by its relatively low GCR values compared with those for fixed or one-axis tracking. If you know the GCR value for your PV array, the figure may be used to estimate the appropriate shading derate factor. Industry practice is to optimize the use of space by configuring the PV system for a GCR that corresponds to a shading derate factor of 0.975 (or 2.5% loss).
The derate factor for sun-tracking accounts for losses for one- and two-axis tracking systems when the tracking mechanisms do not keep the PV arrays at the optimum orientation. For the default value of 1.00, the PVWatts calculator assumes that the PV arrays of tracking systems are always positioned at their optimum orientation and performance is not adversely affected.
The derate factor for age accounts for performance losses over time because of weathering of the PV modules. The loss in performance is typically 1% per year. For the default value of 1.00, the PVWatts calculator assumes that the PV system is in its first year of operation. For the eleventh year of operation, a derate factor of 0.90 is appropriate.
Note: Because the PVWatts overall DC-to-AC derate factor is determined for STC, a component derate factor for temperature is not part of its determination. Power corrections for PV module operating temperature are performed for each hour of the year as the PVWatts calculator reads the meteorological data for the location and computes performance. A power correction of -0.5% per degree Celsius for crystalline silicon PV modules is used.
The PV array may be fixed, sun-tracking with one axis of rotation, or sun-tracking with two axes of rotation. The default value is a fixed PV array.
For a fixed PV array, the tilt angle is the angle from horizontal of the inclination of the PV array (0° = horizontal, 90° = vertical). For a sun-tracking PV array with one axis of rotation, the tilt angle is the angle from horizontal of the inclination of the tracker axis. The tilt angle is not applicable for sun-tracking PV arrays with two axes of rotation.
The default value is a tilt angle equal to the station's latitude. This normally maximizes annual energy production. Increasing the tilt angle favors energy production in the winter, and decreasing the tilt angle favors energy production in the summer.
For roof-mounted PV arrays, the table below gives tilt angles for various roof pitches (in ratio of vertical rise to horizontal run).
PV Array Tilt Angle by Roof Pitch
|Roof Pitch||Tilt Angle (°)|
For a fixed PV array, the azimuth angle is the angle clockwise from true north that the PV array faces. For a sun-tracking PV array with one axis of rotation, the azimuth angle is the angle clockwise from true north of the axis of rotation. The azimuth angle is not applicable for sun-tracking PV arrays with two axes of rotation.
The default value is an azimuth angle of 180° (south-facing) for locations in the northern hemisphere and 0° (north-facing) for locations in the southern hemisphere. This normally maximizes energy production. For the northern hemisphere, increasing the azimuth angle favors afternoon energy production, and decreasing the azimuth angle favors morning energy production. The opposite is true for the southern hemisphere.
Azimuth Angles by Heading
|Heading||Azimuth Angle (°)|
|N||0 or 360|
For the United States and its territories, the default value is the average 2010 residential electric rate for the state in which the station is located (source: Ventyx). For locations outside the United States, the default value is the average 2004 or 2005 residential electric rate for the country in which the station is located (sources: International Energy Agency Electricity Information 2005; International Energy Agency Energy Prices and Taxes, 4th Quarter 2005; and Eurostat Gas and Electricity Market Statistics 2005). For some countries, no electric cost information is available, and the default values are set to zero. For these countries, users should enter a value based on their knowledge. Electric costs are presented in the country's currency.
The default value is the average 2010 residential electric rate for the 40-km cell chosen. Note that some areas are not covered by any utility provider. For these areas, the electric rate for the nearest utility service area is used.