How this wind turbine calculator works
Most wind calculators ask for an “average wind speed” and multiply it by a fixed factor. That ignores the two things that decide a turbine’s output: how the wind is distributed over the year and how fast it blows at hub height. This tool does both properly.
When you pick a site it downloads a full year (8,760 hours) of NASA POWER wind speeds at 10 m and 50 m above ground, plus air temperature and the site elevation. For every hour it:
- extrapolates the wind to your hub height with a shear exponent measured from NASA’s own 10 m and 50 m data, separately for each month and hour of the day (stable nights have much stronger shear than sunny afternoons), or with a terrain class or your own α;
- computes air density from elevation and temperature; a turbine at 1,000 m elevation sees about 10% thinner air than at the coast;
- reads the power curve of the turbine at that density-corrected speed (the IEC 61400-12-1 normalisation);
- sums the year and subtracts wake, availability, electrical and other losses.
Manual mode skips the download: give a mean speed from the Global Wind Atlas or your own mast, its height and the Weibull shape factor k, and the calculator integrates the power curve over a Weibull distribution instead (see the Weibull calculator).
The formula
AEP_net = Σ_hours P(v_hub,t) × (1 − wake) × availability × (1 − electrical) × (1 − other) Capacity factor = AEP_net / (P_rated × 8,760 h)
A is the swept area of the rotor (π·D²/4) and Cp the power coefficient, which can never exceed the Betz limit of 59.3%. Real rotors peak at 45–48%; small turbines usually reach only 25–35%, so the generic curves used here scale peak Cp with turbine size.
Worked example: a 3.6 MW turbine in Dobrogea, Romania
The default case places one low-wind 3.6 MW turbine with a 136 m rotor on a 120 m tower near Cogealac, in Romania’s windiest region. With 2024 NASA weather the shear exponent derived from the data is about 0.16, giving a mean speed of roughly 7.1 m/s at hub height and a wind power density near 360 W/m².
The simulation produces about 14,200 MWh gross. After 3% unavailability, 2% electrical losses and 3% other losses, net output is roughly 13,000 MWh a year, a capacity factor near 41%, enough for over 3,500 average EU households. January and February each produce more than twice as much as June or August.
At 1,350 €/kW the turbine costs about €4.9 million. Selling every MWh at €75 brings in close to €1 million in the first year; with €40/kW/yr O&M the investment pays back in under six years, with an LCOE around €44/MWh. Note this is a single turbine with no wake losses. A wind farm in the same place would lose another 5–10%.
How to read the results
- Annual energy (net): first-year delivered energy after all losses.
- Capacity factor and full-load hours are the fairest way to compare sites and turbines of different sizes. 3,000 full-load hours equals a 34% capacity factor.
- Mean wind at hub and the IEC class (I–IV) tell you which turbine family is designed for the site; low-wind (class III–IV) machines have big rotors relative to their generator.
- Specific power (W per m² of rotor) is the key design number: 200–260 W/m² suits moderate wind and gives high capacity factors; 350+ W/m² suits strong offshore wind.
- The histogram chart shows hours per year in each 1 m/s bin against the power curve. Energy comes mostly from the bins just below rated speed; the rare storm hours contribute little.
Typical values
| Turbine class | Rotor Ø | Hub height | Mean wind at hub | Typical capacity factor |
|---|---|---|---|---|
| Micro (1–3 kW) | 2–4 m | 10–18 m | 4–5 m/s | 8–18% |
| Small (5–20 kW) | 6–10 m | 18–36 m | 4.5–6 m/s | 12–25% |
| Medium (100 kW) | 20–27 m | 30–50 m | 5–6.5 m/s | 18–30% |
| Onshore 2–3 MW | 90–120 m | 80–120 m | 6.5–8 m/s | 28–40% |
| Onshore 4–7 MW | 140–175 m | 120–170 m | 6.5–8.5 m/s | 33–48% |
| Offshore 8–15 MW | 165–240 m | 110–150 m | 9–10.5 m/s | 40–55% |
Tips to get more energy
- Go higher. Above rough terrain each extra 10 m of tower can add 3–5% energy. For small turbines, a tower that lifts the rotor at least 10 m above anything within 150 m is the single most important decision.
- Choose the rotor for the wind, not the generator. At moderate sites a 4 MW turbine with a 150 m rotor out-produces a 5 MW turbine with a 130 m rotor.
- Avoid turbulence. Roofs, trees and buildings create gusty, turbulent flow that small turbines handle badly. Real output is often 30–50% below the brochure.
- Space wind farm turbines at least 3–5 rotor diameters across and 6–10 along the prevailing wind to keep wake losses below 10% (see the wind farm calculator).
- Check different years. Annual wind energy varies ±10% from year to year; switch the weather year in the advanced options.
Limitations
The power curves are generic, built from rotor size and rated power. They are accurate to within a few percent for modern pitch-regulated machines, but not a substitute for a manufacturer’s certified curve. NASA reanalysis data smooths out local terrain effects and hourly means hide turbulence. The model does not include curtailment by the grid operator, icing periods, noise or bat-protection shutdowns, unless you add them to other losses. Finance is pre-tax, without grid fees or financing costs; use the wind farm calculator for debt and equity returns.
Method & assumptions
Wind at hub height. NASA POWER provides hourly wind speed at 10 m and 50 m. In auto mode we derive the shear exponent α = ln(v₅₀/v₁₀)/ln 5 for every month and hour of day (clamped to 0.06–0.40, so stable nights and mixed afternoons are treated differently) and extrapolate each hour with the power law v_hub = v₅₀ (h/50)^α. Alternatively a terrain roughness class or your own α is applied.
Air density is computed hourly from site elevation + hub height (barometric formula) and air temperature lapsed to hub height; wind speed is density-normalised as in IEC 61400-12-1 (v·(ρ/1.225)^⅓) before entering the power curve.
Power curve. A generic curve P = ½ρACp(v)v³, smoothly capped at rated power, with a peak Cp that depends on turbine size (≈0.28 for micro turbines up to 0.46 for utility-scale rotors). In manual mode the hours at each speed come from a Weibull distribution with your mean speed and shape k.
Net energy = gross × (1 − wake) × availability × (1 − electrical) × (1 − other). Capacity factor = net energy ÷ (rated power × 8,760 h). Money: projected over the project life with degradation, price escalation and O&M growing 2%/yr; LCOE is discounted cost ÷ discounted energy.
Frequently asked questions
How much electricity does a wind turbine produce per year?
What is a good capacity factor for a wind turbine?
What wind speed do I need for a wind turbine to be worthwhile?
How much does a wind turbine cost?
Why does hub height matter so much?
Is NASA wind data accurate enough?
Sources & references
- NASA POWER — Prediction Of Worldwide Energy Resources (hourly MERRA-2 wind at 10 m and 50 m)
- IEC 61400-12-1: Wind energy generation systems — Power performance measurements of electricity producing wind turbines
- IRENA — Renewable Power Generation Costs in 2023
- NREL Annual Technology Baseline (land-based and offshore wind)
- Burton, T., Jenkins, N., Sharpe, D., Bossanyi, E. — Wind Energy Handbook, 2nd ed., Wiley
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