The lifetime of wind power turbines is quite long. They are normally certified to work for over twenty years and many still run since the 1980’s. Efficiency starts to decrease only after 9-10 years of operation.
In this regard, we should build the economic model for the development of the Eolian Fund which would take into account some sort of the technology index, as core engineering approaches may change several times during the life of a single turbine.
Of course, both the revenue and cost parts of the cash flow depend on technology. However, it is reasonable to take into account only the changes in expenses, since all calculations are carried out nominally, for 1 “virtual” megawatt of rated power.
Unlike revenues that depend on unpredictable changes in the electricity market (depending, in its turn, on fossil fuel prices), as well as on politicians affecting the form and level of support for the renewable energy industry, the upfront costs of wind turbines and their maintenance can be predicted quite accurately.
Costs are almost the same in different countries and are determined mainly by the technology used. Access to capital — the main item of expenditure — is internationally equal today, at least within Europe. In contrast to that, revenues are almost entirely determined by local factors and, therefore, the Fund can directly influence them by varying the degree of presence in a particular country.
After taking into account inevitable changes in costs due to the development of technology, the model of the “elementary” generator in our model will improve greatly because further changes in the revenue part can be partially leveled by fund effects: the lower the energy price, the lower the current fair value of a generating facility, th
Why Rotor Size Matters?
Since the potential energy sales are roughly proportional to the “size” of generators in MW, that nominal power figure is often considered as the core numerical factor. Some people think like this: “we got a 2MW generator, so if we have an efficiency of 50%, we receive 24 MWh per day.”
That is wrong. Conventional measures of technical efficiency or capacity factors are misleading or even meaningless in the wind power discourse.
The economics of wind power is fundamentally different from the commonly understood economics of conventional units such as gas-burning turbines. A gas turbine plant converts a storable, dispatchable, and costly energy source into electrical energy. Wind turbines deal with a fluctuating, impossible-to-store, and free energy source.
Once we take into account the Betz’s limit and other factors that limit efficiency, it is only about 10-30% of the power of the wind that we can actually capture and convert into usable electricity. Fortunately, in the economic sense, it doesn’t really matter. We don’t need to catch “all the wind” because it is free anyway.
What is essentially happening when rotor blades are rotating is that the kinetic energy of the mass in motion is being converted into other forms of energy. The power (formally defined as the derivative of the energy with respect to time and practically understood as the ability to “generate as many Watts in 1 hour”) is linearly proportional to the area “swept” by rotor blades. In other words, we mainly deal with the parameter “diameter squared”.
In this formula, Rho stands for air density, A — for swept area, v — for wind speed (the power strongly depends on the wind speed — as the exponential function of the third degree), and Cp — for efficiency coefficient.
That’s why wind turbines are generally priced proportional to rotor blade length squared and not to rated power in MW. The ratio between rotor area and generator size is secondary and depends on the wind climate. In general, it is best to use fairly large generators for a given rotor diameter (or smaller rotors for a given generator size). This makes even more sense in areas with higher mean wind speed.
So, naturally, we want to make the rotors as large as possible. In the early days of the industry, small sizes of 20-60 kW generators were very clearly not optimum for system economics. Besides the general dependence we described above, small wind turbines suffered from low towers so they couldn’t “clear obstacles” to wind flow and escape the worst conditions of turbulence and wind shear near the surface.
Unfortunately, blades’ weight grows faster with diameter than swept area because the latter “lives” in two dimensions and the former — in three. So the big enough thing will eventually break, let alone the highly non-linear growth of construction Unfortunately, a blades’ weight grows faster with diameter than swept area because the latter “lives” in two dimensions and the former in three. So, it is much less profitable to create large blades due to diminishing returns in addition to the highly non-linear growth of construction complexity and costs.
Another very important factor is scaling of controls, electrical connection to grid, and maintenance. The Fund will deal at the comparatively high point in the value chain of power generation. We do not refer to kilowatt-hours delivered at the location of the turbine, at the electricity outlet or somewhere in between. We are talking about high voltage statistically predictable delivery including ancillary grid services. At some size, the cost of a larger turbine will grow faster than the resulting energy output and revenue, making further size increases uneconomic.
However, studies show there’s still significant potential for further turbine scaling. Constraints will certainly enter at some point in time, but so far, turbines have room to grow, offering the promise that this already-mature energy technology will see still higher efficiency and lower costs in the future. To date, the decade-long average annual growth is approximately 3%.
Rotor diameters of the turbines added in 2017 are in the range of 48-180 metres with an average value of 113 metres. Despite this large range, 50 percent of the wind turbines were built with a rotor diameter in the narrow band between 112 and 122 metres. The maximum rotor diameter of the turbines designed for the onshore market rose by 11 metres to 142 metres in 2017 and is now held by a Siemens SWT-3.15-142. The mean rotor diameter of the decommissioned wind turbines in 2017 was 62 metres.
Cost Estimation Model
We are basing on the following premises:
- In the current familiar class of installations (2-3 MW) there are and there will be, for quite a while, many attracting bids, too attractive to reject. Accordingly, for these installations, no technology-related cost changes are foreseen. Costs will slowly increase with the age of the turbines. Decisions of the economic feasibility of replacing a turbine that has not yet lived up its certified period are difficult to consider theoretically, in isolation from the specific case, so, in our model, we limit ourselves to mere sales of installations older than 20 years, at their residual value.
- Most likely, we will have no reason to purchase older generators of a smaller class of power and size.
- Generators that belong to the newer classes (4 MW and above) represent the source of significant error range in costs estimations. This “next class” may bring us some big surprises. The wind industry has quite a history of under-predicting the growth rates of turbines. Below are the results of the recent expert survey. As you can see, the distribution of answers is quite broad; experts generally can’t agree on future turbine size.
Below is the expected distribution of different classes of equipment in the Eolian Fund based on simple extrapolation of the current trend minus all classes of equipment below 2 MW.
For the newer class, in neutral/modest scenarios, the leveraged cost of wind energy generation is anticipated to decline by a few percent annually. Besides larger rotors, there are several categories of factors that have an impact: advancements in design, taller towers, reduced financing costs, better component and materials durability and reliability.
In Europe specifically, the market moves towards larger turbines a bit faster than the rest of the world because of land constraints. The transition to higher-megawatt turbines is warmed by the fact that the market generally favors larger equipment so more power-purchase agreements can be signed by newer farms. It is becoming much less a competition of various government subsidies and much more a competition of technology generations. Europe altogether is expected to have the greatest reliance on large turbines with 3-megawatt and 4-megawatt models making up nearly 100 percent of the market by the end of 2023.