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Is it possible to prepare for unexpected costs?

Operation and maintenance (O&M) costs for onshore wind farms account for 10% to 15% of total generation cost.

Repairs...0.3 per cent of original investment over 15 years
Repairs...0.3 per cent of original investment over 15 years

There are a number cost elements, but the biggest single contribution is the service contract, which accounts for about two-thirds of the total O&M cost (see table below).

Most O&M cost elements are predictable and controllable, with the possible exception of repair costs.

Although these nominally account for only a small proportion of the total, unforeseen repairs of expensive items, such as blades and generators, can significantly affect the profitability of a wind farm.

That is why considerable effort is focused on condition monitoring, as a way to obtain prior warning of component failures.

O&M costs can be expressed simply, by assuming that the total annual charges are a percentage of the original installed cost, with figures of 2% to 5% often used.

A more accurate calculation involves more detailed assessment of the individual components, with the results expressed either as €/kW per year of plated capacity, or as €/MWh of electricity expected to be generated.

One variation that can affect calculations of the overall cost is the land rent.

In the US, and possibly elsewhere, the developer commonly buys the land, removing rent from O&M costs and adding about $16/kW (€11/kW) to the installed cost, according to the California Energy Commission.

As an annual O&M cost, this translates to about $2/kW (€1.40/kW), one-third of the corresponding rental cost.

Elsewhere, developers often pay landowners rent based on turnover.

While repairs usually account for a modest proportion of O&M cost, the reliability of the turbine components is very important and any failures can have a significant impact on profitability.

Not only will a faulty component need to be replaced but there is a loss of revenue from electricity sales to be taken into account for turbine downtime during the repairs.

 
 

Pattern of repair costs

Analysis of the repair costs for German wind turbines, undertaken as part of the Wind Energy Measurement Programme, has shown that these tend to increase over time, as shown in the Pattern of repair costs diagram (see next page).

This pattern is typical of most machinery and simply reflects the fact that components wear out or fail with increasing frequency as they age.

Costs rise erratically, peaking at around €12/kW after ten years, before declining again, which may indicate that major replacements are often needed, or scheduled, around this time.

If this pattern of repair costs is taken as typical, the corresponding constant repair cost over a 15-year period is €3.6/kW — around 0.3% of the original investment cost — for a wind farm built for €1,300/kW.

There have been a number of high-profile cases where components such as gearboxes have been replaced early in the life of a wind farm.

Such early replacement may be covered by the guarantee, so the critical time is just after the guarantee expires — year four, say.

To show the effect of unforeseen repair costs on profitability, the diagram of unscheduled repairs (overleaf) estimates the impact on the equity returns from a notional wind farm that has unscheduled repairs after four or ten years of operation.

This farm had a total installed cost of €1,300/kW, financed by a ten-year 75% bank loan.

The wind farm receives €90/MWh for electricity generated. If the repairs accounted for 0.3% of the initial investment each year, as proposed above, the equity investors would derive a return of 15% over 15 years.

The analysis suggests that unscheduled repairs costing 1% of the original investment — after four or ten years — would cut equity return to about 14.7%, at most.

But, repairs after four years that absorbed 10% of the original investment would see the equity return fall to 11.9%; similar repairs after ten years would reduce it to 13.5%.

Raise repair costs to 20% of the investment, and equity return falls to 9.1% if needed after four years, or 11.8% after ten years.

These estimates do not account for revenue lost from electricity sales during repairs. Recent analysis suggests availability declines with age, and this too would need to be taken into account. 

 

What fails?

Generator and gearbox failures attract attention as these are high-cost items and the replacement process highly visible.

But data from the Institute for Solar Energy Supply Technology in Kassel, Germany (ISET) and the EU-funded Reliawind study show electrical equipment and control system failures to be the most frequent, at 2.5 to 5.5 incidents per ten machine-years.

At the other end of the scale, gearbox and generator failures each account for around one to 1.3 incidents per ten machine years. The ISET data are shown in the chart, right, which also shows the days out per failure.

Electrical and control system failures are generally rectified fairly quickly. Although gearboxes and generators fail less often, the outages needed to rectify any problems are longer.

When the numbers in the two charts are multiplied together, they estimate the average downtime of each of the components in ten years. Every item falls into the range of 0.4 to one day per year, although other data suggest that the figure for gearboxes could be as high as two days per year.

Reliable data on replacement costs for gearboxes and generators are elusive but gearboxes typically cost around 15% of the total cost of a turbine — or around 10% of the installed cost of a wind farm.

If the costs of installing replacements doubles their purchase price, then a worst case scenario would mean making provision for 20% of the initial cost to be incurred after about ten years.

In practice, it is unlikely that all the gearboxes would fail at the same time; some might fail earlier, some might last beyond 15 years.

The other high-cost items that could erode profitability are the rotor blades — 15% of turbine cost— and the generators (10%).

Continuing improvements in turbine design mean that estimating repair costs involves chasing a moving target.

However, the good news is that the moving target is going largely in one direction and that operation and maintenance costs will decrease into the future.

 

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