How this calculator works
A wind farm is a capital-intensive machine whose fuel is free: almost all of the cost is paid before the first kilowatt-hour, and the rest of its life is a long stream of fairly predictable revenue. This calculator builds the core of a developer’s project model on one page:
- Energy (P50). Enter the wind speed at hub height (with a Weibull k) and the turbine’s specific power, or simply a net capacity factor. With wind speed, a generic power curve is integrated over the wind distribution at your site’s air density, then reduced by total losses (wakes, availability, electrical, curtailment).
- Cash flow. Revenue at your PPA or market price with annual indexation; fixed O&M (including land lease and insurance), variable O&M, output degradation and decommissioning in the final year.
- Financing. A share of capex is funded by a level-annuity loan; the rest is equity. You get project (unlevered) IRR, equity IRR, NPV at your WACC, and the debt service coverage ratio (DSCR) every year.
- Impact. Layout area from rotor diameter and spacing, households supplied and CO₂ avoided.
The formulas
Worked example: a 54 MW onshore project
The defaults model 12 turbines of 4.5 MW (54 MW) with a specific power of 300 W/m² (a 138 m rotor) on 120 m towers, at a site with 7.5 m/s mean wind at hub height and k = 2.
- Gross capacity factor 43%; after 15% losses the net capacity factor is about 36.8%, or roughly 174 GWh a year, enough for 48,000 average EU homes.
- Capex at 1,400 €/kW is €75.6 million; fixed O&M of 42 €/kW/yr adds €2.3 million a year plus variable costs.
- Over 30 years at a 6.5% WACC, the LCOE is about €54/MWh.
- Selling at €68/MWh with 1.5% indexation, the project IRR is about 12.6% and the unlevered NPV €55 million.
- With 70% debt at 5.5% over 15 years, debt service is €5.3 million a year, the minimum DSCR is about 1.75 and the equity IRR around 20% (pre-tax).
Drop the wind speed to 6.5 m/s and the capacity factor falls to about 29%. The LCOE then climbs to roughly the €68 PPA price and the minimum DSCR drops to a marginal 1.28, which shows how sensitive wind economics are to the resource.
How to read the results
- P50 energy is the median expectation. Lenders size debt on P90 (the level exceeded 90% of years), typically 8–12% lower for a single year; test it by lowering the capacity factor or raising losses.
- LCOE vs price. If the price is below LCOE, the project destroys value at your discount rate, whatever the payback.
- Project vs equity IRR. Debt raises equity returns when the project IRR exceeds the interest rate, at the cost of a thinner DSCR cushion.
- The cash-flow chart stacks revenue against O&M and debt service; the line (right axis) is cumulative equity cash, which turns positive at the equity payback year.
Typical values
| Parameter | Onshore (Europe/US) | Offshore |
|---|---|---|
| Turbine size | 4–7 MW | 12–15 MW |
| Specific power | 230–330 W/m² | 330–400 W/m² |
| Net capacity factor | 28–42% | 40–52% |
| Capex | 1,100–1,800 per kW | 2,500–4,500 per kW |
| Fixed O&M | 30–55 per kW-yr | 60–110 per kW-yr |
| Total losses | 12–18% | 10–15% |
| Debt share / tenor | 60–80% / 15–18 yrs | 60–75% / 15–20 yrs |
| Design life | 25–30 yrs | 25–30 yrs |
Tips
- The wind resource dominates. One m/s of extra mean wind speed changes LCOE by 20–30%; invest in a 12–24 month measurement campaign.
- Lower specific power at moderate sites. Bigger rotors on the same generator raise capacity factor and revenue per MW, and depend less on the windiest (often lowest-priced) hours.
- Spacing is a trade-off. Tighter layouts fit more MW on a lease but raise wake losses; 4 × 7 rotor diameters is a common starting point.
- Model P90 and price downside before committing to a debt structure; a minimum DSCR below ~1.2 on P50 is a red flag.
- Compare technologies with the LCOE calculator and refine single-turbine yield with the wind turbine calculator.
Limitations
This is a screening model. It is pre-tax (no corporate tax, depreciation or tax equity), ignores grid connection charges, balancing costs, price cannibalisation in windy hours and curtailment unless included in losses, and uses one generic power curve with an aggregate loss factor instead of a wake model. Debt is a simple annuity without sculpting, reserve accounts or construction-period interest. Use it to compare options and test sensitivities before commissioning a bankable energy-yield assessment and financial model.
Method & assumptions
Energy. Rotor diameter D = √(4P/(π·SP)). With mean speed, gross yield = 8,760 h × ∫P(v)·f(v)dv with a generic power curve (peak Cp 0.46) and Weibull f(v), at air density for the site elevation; net = gross × (1 − losses). Cash flow: revenue = MWh × price (indexed), opex = fixed (+2%/yr) + variable, decommissioning in the final year. LCOE = (capex + Σ opex_t/(1+r)^t) / Σ MWh_t/(1+r)^t. Equity funds capex × (1 − debt share); debt is repaid as a level annuity; DSCR = cash flow available for debt service ÷ debt service. Area: turbines on a grid spaced sx·D across and sy·D along the prevailing wind.
Frequently asked questions
How much does it cost to build a wind farm?
What is the LCOE of onshore wind?
How much land does a wind farm need?
What is a good equity IRR for a wind project?
What DSCR do banks require for wind farms?
How many homes can a wind farm power?
How many turbines are in a 100 MW wind farm?
Sources & references
- IRENA — Renewable Power Generation Costs in 2023
- NREL Annual Technology Baseline — land-based and offshore wind costs
- Denholm, P., Hand, M., Jackson, M., Ong, S. (2009). Land-Use Requirements of Modern Wind Power Plants in the United States. NREL/TP-6A2-45834
- Short, W., Packey, D., Holt, T. (1995). A Manual for the Economic Evaluation of Energy Efficiency and Renewable Energy Technologies. NREL/TP-462-5173
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