Solar Farm Yield Calculator

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Solar Farm Yield Model

Calculate annual generation and 25-year revenue from utility solar

DC Capacity (MWp)

DC/AC Ratio

Irradiance (kWh/m²/yr)

Performance Ratio (%)

Power Price (£/MWh)

Degradation (% per year)

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Year 1 Generation

Excludes network upgrade costs, planning risk, and merchant revenue risk. Assumes fixed power price over analysis period.

10–12%

UK Avg Capacity Factor

0.80–0.85

Performance Ratio

17GW

UK Solar Deployed (2024)

Utility Solar Farm Analysis

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.

🏠 Solar Farm Yield Explained

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.

📊 Solar Farm Performance Ratio

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.

Frequently Asked Questions

What is a good capacity factor for UK solar?

UK average is 10–12%. South coast (1,100 kWh/m²/yr) achieves 12–13%. Midlands/South (1,050 kWh/m²/yr) achieves 10–11%. Scotland (950 kWh/m²/yr) achieves 9–10%. Single-axis trackers add 20–25% to fixed-tilt CF. P50 yield is used for conservative estimates; P90 (90% confidence, low scenario) is ~10% lower.

What do P50 and P90 mean?

P50 (50th percentile) = 50% chance of achieving or exceeding this yield. P90 (90th percentile) = 90% confidence of achieving at least this yield (low-side estimate). For investment-grade projects, lenders require P90 yield forecasts to ensure debt service coverage. P50 is typically 5–10% higher than P90. Both assume 30-year irradiance data (TMY).

Is single-axis tracking worth it?

Yes, typically 15–20 year payback. Trackers cost £150–200/kW additional (vs fixed £100/kW), but generate 20–25% more energy annually. In UK merchant conditions (£70–80/MWh), the extra £14–20m annual revenue (for a 50 MW system) pays back the extra £7.5–10m CapEx in 5–7 years. Maintenance is minimal (quarterly checks, bearings every 10 years). Most new large-scale farms use trackers if land is available for spacing.

How does shading affect output?

Row-to-row shading (from panel height and spacing) is factored into PR (performance ratio). Unexpected shading from trees/buildings can reduce output 5–50% depending on timing and extent. Site surveys use satellite imagery (Google Earth, PVGIS Horizon angles) to identify shading risks. Shading avoidance is critical—even 1% all-day shade can reduce annual yield by 3–5%.

What planning consent does a solar farm need?

5–50 MW systems: standard planning application (18–30 month timeline). 50+ MW: NSIP (Nationally Significant Infrastructure Project), Examination in Public before Secretary of State (2–3 years). Most planning is granted, but cumulative landscape impact and agricultural land use are scrutinized. Ground-mounted systems can return to agricultural use after decommissioning (no permanent damage if properly managed).