Hourly DC/AC production · Tilt & irradiance · Daily kWh
This simulator estimates the hourly DC and AC power output of a solar PV array for a representative clear-sky day, computing daily energy yield and specific yield based on array size, tilt angle, location irradiance, and system losses. Engineers use it for preliminary energy yield estimation, inverter sizing checks, and design optimization before running full annual simulations with PVGIS or PVWatts.
The simulator follows the NREL PVWatts methodology. Target daily DC energy = array_kW × peak_sun_hours × tilt_factor × (1 − losses/100). Peak sun hours represent the location's daily plane-of-array irradiance in kWh/m²/day, equivalent to hours of 1000 W/m² irradiance. Tilt factor adjusts for the array angle relative to optimal — arrays tilted near 30° south (in the northern hemisphere) capture maximum annual irradiance.
The hourly profile distributes DC energy across daylight hours using a sinusoidal bell curve between sunrise and sunset, scaled so the sum equals the target daily DC energy. This is a clear-sky approximation; actual production varies with cloud cover, soiling, and shading. AC energy equals DC energy multiplied by inverter efficiency.
Specific yield (kWh/kW) is the daily AC energy divided by array size in kW-DC, providing a location- and orientation-specific metric independent of array size. Typical specific yields range from 3.5–4.5 kWh/kW/day in high-irradiance locations (SW US, Spain, MENA) and 2.5–3.5 kWh/kW/day in moderate-irradiance locations (Central Europe, Pacific Northwest, UK).
NREL PVWatts (version 8) is the US standard methodology for PV energy yield estimation, used by the IRS, utilities, and financing institutions. It uses the NSRDB (National Solar Radiation Database) for hourly irradiance data and applies a standard system losses factor of 14% covering wiring, soiling, shading, age, and mismatch.
IEC 61724-1 (Photovoltaic System Performance — Monitoring) defines the performance ratio (PR = AC_energy / (GHI × array_kW / 1000)) and specific yield metrics used for system benchmarking. PR of 0.75–0.85 is typical for modern systems. This simulator's tilt factor and losses combine to produce an effective PR.
IEEE 1547-2018 governs interconnection requirements for the PV system with the grid. The inverter must have an IEEE 1547 certification for the voltage/frequency operating ranges at the point of interconnection, and the inverter output current calculated from AC production must not exceed the inverter nameplate current at the service voltage.
Tilt angle optimization depends on latitude and objective. For maximum annual energy, fixed-tilt systems perform best near the site latitude angle (e.g., 35° at latitude 35°N). For maximum winter production (important for net metering in locations with seasonal load variation), steeper tilts of latitude +10° to +15° are preferred. Commercial rooftop systems often use 10–15° to minimize wind loading, accepting a 3–8% annual yield penalty.
The system losses factor (default 14% per PVWatts) includes DC wiring losses (2%), soiling (2%), shading (3%), age/LID (1.5%), mismatch (2%), and other losses (3.5%). Shade-optimized systems using module-level power electronics (MLPEs — microinverters or DC optimizers) can reduce shading losses to near zero, improving yield in partially shaded installations by 5–15%.
Inverter sizing ratio (DC:AC ratio, or inverter loading ratio ILR) is typically 1.1–1.25 for fixed-tilt systems: a 10 kW-DC array paired with an 8 kW-AC inverter has an ILR of 1.25. Inverter clipping (when DC power exceeds AC rating) causes less than 1–3% of annual production to be lost in well-designed systems, while the lower-cost AC inverter provides economic benefit.
Enter the array DC nameplate size in kW. Adjust the tilt angle to match your installation — 20° is common for commercial low-slope roof ballasted systems, 30–35° for residential pitched roof systems or ground-mounted. Set peak sun hours for your location: use NREL PVWatts or PVGIS to look up the annual average plane-of-array irradiance for your specific tilt and azimuth.
Set the day length to match the season you want to model (8 hours in winter solstice at mid-latitudes, 14–16 hours in summer solstice). Adjust inverter efficiency (97% for premium string inverters, 96% for central inverters) and system losses (default 14% per PVWatts, or lower for premium systems with MLPE and minimal shading).
The chart shows hourly DC (yellow) and AC (orange) power output. The summary banner reports daily AC energy and specific yield. Multiply daily AC energy by 365 × average capacity factor adjustment for annual yield estimates, or use the specific yield figure with your array size for quick comparison across designs.
Specific yield (kWh/kW) normalizes energy production by array size, allowing comparison between systems of different capacities at different locations. A 10 kW system in Arizona producing 55 kWh/day has a specific yield of 5.5 kWh/kW, while a 100 kW system in Oregon producing 350 kWh/day has a specific yield of 3.5 kWh/kW — the Arizona system significantly outperforms on a unit basis despite the Oregon system producing more total energy.
Use NREL PVWatts (pvwatts.nrel.gov) or PVGIS (ec.europa.eu/jrc/en/pvgis) to look up the plane-of-array daily average irradiance for your specific location, tilt, and azimuth. Typical values: Phoenix, AZ = 6.0–6.5 kWh/m²/day (south, 25° tilt), Los Angeles, CA = 5.5–6.0, Denver, CO = 5.5–6.0, Chicago, IL = 4.5–5.0, Seattle, WA = 3.5–4.0, Boston, MA = 4.5–5.0. Global horizontal irradiance (GHI) is approximately 5–15% lower than tilted POA.
Tilt angle determines how much direct sunlight the array intercepts across the seasons. The annual-optimal tilt for a south-facing fixed array is approximately equal to the site latitude (±5°). Near the equator (latitude < 15°), a 5–10° tilt is optimal. In northern latitudes (> 45°), tilts of 35–45° maximize annual yield. For seasonal storage applications prioritizing winter production, steeper tilts (latitude + 10°) are preferred.
The PVWatts default 14% system loss factor includes: soiling (2%), shading (3%), snow (0%), mismatch (2%), wiring (2%), connections (0.5%), light-induced degradation (1.5%), nameplate rating error (1%), and age (0%). These losses compound multiplicatively: a system with 14% total losses delivers 86% of the theoretical DC output at the AC output terminals. High-performance systems with MLPE and clean environments can achieve 8–10% total losses.
The inverter loading ratio (ILR = DC kW / AC kW) typically ranges from 1.10–1.30 for fixed-tilt systems, chosen to clip the small percentage of hours when DC power peaks above the inverter AC rating. Higher ILR reduces inverter cost and improves low-irradiance efficiency. Use PVWatts to check clipping losses: a well-designed system clips less than 1–3% annually. The inverter maximum DC input voltage must also exceed the string voltage from the NEC 690.7 calculation at the lowest expected temperature.
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