Bans on subsidies (in some countries) and reduced costs have hit total investment in onshore wind. Meanwhile, market share continues to grow across the EU28. Wind energy now accounts for almost 20% of installed capacity for power generation which makes researcher Schalk Cloete’s sobering analysis of risks for onshore wind well worth reading. Following up on his previous article, he examines current assumptions and argues that the discount rate and declines in value (combined with cost of integration) take their toll on returns…
Establishing a formula
The conclusions reached are based on an analysis of discounted cash flow for only 1 kW onshore wind over a one year construction period followed by an operating period that lasts for as long as the plant is profitable or up to a maximum of 40 years. The investment is made in the first year, followed by the annual receipt of revenues from electricity sales and payment of operating and maintenance (O&M) costs.
Capital costs are taken to be $2000/kW, a good global average when adjusting for purchasing power parity (see previous article) and O&M costs are taken to be 2.5% of the capital cost per year and these costs remained constant over the plant lifetime. However, according to the most recent US wind technologies market report , turbine performance begins to decline at a linear rate of 2% after the ninth operating year.
After the initial $2000 capital investment, the annual cash flows from electricity sales at an average wholesale price of $60/MWh and a capacity factor of 30% (shown below). The linear decline in plant performance is clearly visible after year 9 – even though, based on BP data , the 30% capacity factor is optimistic compared with the global average that has hovered around 26% for the past 5 years .
Using this information without a discount rate (i.e. applying discount rate of 0%) you will eventually see a return . Apply a discount rate of 2% and the net return on investment is zero. In other words, this analysis would return a levelized cost of electricity of $60/MWh if the discount rate is set to 2%. But a more realistic discount rate would be 8% meaning the initial investment cannot be recovered.
Now it gets technical
Subsequently, the effects of the value declines and cost increases related to intermittency (“integration costs” discussed in the previous article) have to be factored in.
- The added cost of grid connection – an up-front cost with average distances between the wind farm and the consumer at 100 km, yielding an added capital cost of $200/kW at a transmission cost of $2/kW/km
- Balancing costs are assumed to scale directly with the wind energy market share, adding $0.3/MWh for every percentage point of market share. This is about half the current balancing cost in Germany.
- The value decline of wind power is modelled according to the following market value factor. At market shares higher than 15%, the linear trend is extrapolated.
Wind and solar value factors (a value factor of 1 is for a generator with a constant output) as a function of their respective market shares (source).
The following annual cash flows are generated when these assumptions are applied to a plant constructed when the wind market share is 5% (current global average) and increasing by 1% per year up to a maximum of 40%. The more rapid decline in revenue (caused by the value decline) and the increased balancing costs are clearly visible.
As shown in the cumulative cash flow analysis below, the initial investment can now no longer be recovered, even under a 0% discount rate. In fact, the plant starts to lose money around year 24 as declining revenues fall below increasing costs.
Effect of the discount rate
The effect of discount rate on the average electricity price required is shown below with and without the value declines and cost increases from intermittency. Note that the average electricity price required is used here instead of the levelized cost of electricity to account for the value decline of wind power with increasing market share. This measure can be interpreted as the average market price over an entire year that will yield a zero return on investment with a specified discount rate. The actual electricity price received by the wind farm will be lower.
The graph clearly shows a large increase in the required electricity price as the discount rate is increased. Inclusion of the value decline, balancing costs and grid costs increases the required electricity price by about $30/MWh at all discount rates.
Quantifying the risk
Next, the influence of the risk of accountability for value declines and cost increases caused by intermittency will be quantified. This quantification is done by determining the discount rate giving zero return on investment when the average electricity price is set to $60/MWh. The annualized return on investment is then quantified as the discount rate minus 2% to account for margin erosion from technological improvements of new plants that come online during the plant lifetime as well as financial/legislative costs (paying the bankers and lawyers involved in setting up financing for the plant).
As shown below, the investment return is exactly 0% when wind farms carry no accountability for intermittency costs (blue bar). The sensitivity to the three different intermittency effects is shown by the orange bars. When a 100 km grid connection is included, the annualized investment return drops by only 0.7%. Adding the value decline effect causes a much larger 4.6% drop. Further addition of the balancing costs also has a large effect, reducing the total annualized investment return to almost -8%.
The magnitude of the drop in investment returns is strongly influenced by the rate of wind power expansion over the lifetime of the plant (grey bars). More wind on the grid will reduce the value and increase the balancing costs of all wind generators. Every increase in the wind expansion rate of 0.5% market share per year drops the annualized investment return by about 4%.
The effect of added grid expansion costs (yellow bars) is smaller. Increasing the required grid connection from 100 km to 500 km (thus increasing the added up-front cost from $200/kW to $1000/kW) only decreases the annualized investment return by 2.7%.
Finally, the effect of balancing costs is shown by the green bars. Every increase of $0.2/MWh per % of wind market share decreases the investment return by about 2%.
Anticipating the potential for substantial intermittency costs to eventually be fairly attributed to wind generators presents a major risk for wind farm investors. And even when these intermittency effects are ignored, the global average wind turbine does not give a reasonable return on investment without direct subsidisation. Of course, there are locations where wind is much more attractive (for example, the US great plains achieve an 8.7% return at 45% capacity factor and $1600/kW capital cost), where wind energy remains attractive at relatively low market shares.
When intermittency costs are correctly accounted for, the investment returns fall drastically. The annualised return on investment drops from 0% to -8% when intermittency costs and value declines are taken into account.
The most influential factor in the analysis is the rate of wind power expansion. Higher expansion rates lead to larger investment losses. Interestingly, this dynamic reduces the risk for onshore wind investment because the strong increases in wind market share that cause this risk will not take place if value declines and integration costs are fairly assigned to wind generators.
All of this reinforces the notion that continued wind power expansion will require perpetual subsidies. If wind power is to have the impact envisioned by green advocates, the large investment losses caused by their value declines and integration costs will need to be borne by other sectors of the economy for decades to come.
Editor’s note: This article published over our new contributor’s platform, you can register here