Model utility-scale solar farm annual generation, specific yield, and 25-year revenue projections.
Calculate annual generation and 25-year revenue from utility solar
Excludes network upgrade costs, planning risk, and merchant revenue risk. Assumes fixed power price over analysis period.
UK utility-scale solar farms (5–150 MWp) achieve 10–12% capacity factors and £40–65/MWh LCOE (2024). Specific yield (kWh/kWp/yr) averages 920–950 in good locations.
A utility-scale solar farm's annual generation depends on four factors: (1) Installed capacity (MWp) = number of panels × rating per panel. (2) Irradiance = location-specific solar resource (kWh/m²/yr), ranging 900–1,100 in the UK. (3) Performance ratio = fraction of theoretical generation actually captured, typically 80–85% after accounting for temperature, shading, soiling, inverter losses. (4) Specific yield = annual output per MW of capacity, typically 900–950 kWh/kWp/yr in the UK, equivalent to 10–12% capacity factor.
UK Solar Farm Examples: Cleve Hill (49 MW, south Kent, Irradiance ~1,050 kWh/m²/yr, expected 47 GWh/yr = 960 kWh/kWp). Cottam (31 MW, East Midlands, 30 GWh/yr = 970 kWh/kWp). Brize Norton (36 MW, Oxfordshire, 34 GWh/yr = 945 kWh/kWp). These operate without subsidies as merchant projects, selling to wholesale market at £60–80/MWh.
Planning and Permitting: Ground-mounted solar farms above 5 MW require planning application (NSIP for 50+ MW). Typical timeline: 18–30 months from application to grid connection. Land requirement: 3–4 hectares per MW (accounting for spacing between rows, access, substation). Landowner typically receives £1,500–3,000/hectare/year revenue share or lease.
PR Breakdown: Temperature losses (~5–10%, higher in hot climates), soiling (1–3%, rain cleans panels), shading (0–5%), reflection (1–2%), inverter losses (2–4%), cable/connection losses (1–2%), availability (1–2%). Total PR 0.80–0.85 typical. Bifacial modules (+3–8% from ground reflection) push PR to 0.85–0.88. Single-axis trackers add 20–25% generation vs fixed-tilt but increase CapEx by 15–20%. Payback of tracker investment: 3–5 years in UK conditions.
PVGIS Irradiance Data: PVSystemDesigner (NREL PVGIS) and SolarGIS use 30-year historical weather data to estimate irradiance. UK average: 1,000–1,100 kWh/m²/yr on horizontal surface, 1,050–1,150 on 35° south-facing tilt. South coast (Cornwall, Sussex) ~1,100; Midlands ~1,050; North (Scotland) ~950–1,000. Uncertainty: ±5–7% typical for 30-year TMY (typical meteorological year). P50/P90/P10 yield assessment uses ±1 std dev around mean.
Clipping Loss (DC/AC Ratio >1): A 50 MW array with 1.1 DC/AC ratio (55 MWp DC, 50 MW AC inverter) clips (wastes) ~0.5–1% of peak production during midday peak irradiance (~11am–3pm on clear days). Clipping loss reduces annual yield by 0.5–1.5% depending on season and local irradiance. Benefit of clipping: lower inverter cost (£150–200/kW vs £300/kW if 1:1 ratio), and improved mid-morning/afternoon production profile (less volatile power swings for grid).
Long-term Degradation: Module LID (Light-Induced Degradation) is minimal (<1% in year 1) on modern PERC/monocrystalline panels. Steady-state degradation: 0.3–0.5%/year. PID (Potential-Induced Degradation) is controlled by grounding/biasing (1–2% loss if unmitigated, ~0% if managed). Conservative assumption: 0.5%/year linear degradation over 25 years = 12.5% lifetime degradation. Warranty: 90% output at 10 years, 80% at 25 years.