What are the risks related to solar power investment?

Highlights

  • A cumulative cash flow analysis is presented for utility-scale solar PV.
  • The large effect of discount rate on levelized costs is illustrated. 
  • Value declines and integration costs cause a $60/MWh increase in the levelized cost under the base-case assumptions. 
  • This translates to a very large 13% decrease in annualized investment returns if solar market share increases by 1% per year over the plant lifetime.
  • This investment risk is not as large as it seems because the steady increases in solar market share that cause these negative returns will never happen if solar generators are not shielded from their value declines and integration costs.   

Introduction

An earlier article offered some qualitative discussions on the risks involved in several mainstream energy options. Following the previous article on onshore wind, the next four articles will present a quantitative analysis of these risks for utility-scale solar PV, nuclear, natural gas and coal.

All the most influential assumptions will be clearly explained and their impact on the results will be quantified. This will give the reader the opportunity to clearly see the quantified impact of the risk under the assumptions they think are the most appropriate.

Methodology

Results will be presented in the form of a discounted cash flow analysis for only 1 kW utility solar PV 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 as $1800/kW. This was found to be a good global average when adjusting for purchasing power parity (see previous article). O&M costs are taken as 1% of the capital cost per year and these costs are assumed to increase linearly by 1% per year. Plant output is assumed to fall by 2% in the first year and linearly by 0.8% per year afterwards.  Inverter replacement every 15 years is included at a cost of $100/kW (hardware and installation).

After the initial $1800 capital investment, the annual cash flows from electricity sales at an average wholesale price of $60/MWh and a capacity factor of 18% are shown below. The linear decline in plant performance is clearly visible, as well as the linear increase in O&M (although O&M costs are relatively small). Inverter replacement costs are also notable. Note that the 18% capacity factor is selected to be optimistic next to the global average that has hovered around 15% for the past 4 years according to BP data.

Using this information, a cumulative cash flow curve can be constructed (below). As shown, the initial $1800 investment is recovered in year 28 when no discounting is applied (discount rate of 0%). When a discount rate of 1.4% is applied, 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 1.4%. Under a more realistic discount rate of 10%, the initial investment cannot be recovered.

Subsequently, the effects of the value declines and cost increases related to intermittency (discussed in the previous article) are included. Firstly, the added cost of grid connection is included as an up-front cost. It is assumed that the average distance between the solar farm and the consumer is 100 km, yielding an added capital cost of $200 at a transmission cost of $2/kW/km.

Secondly, 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.

Thirdy, 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 solar market share is 2% (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, not even half of the initial investment can now be recovered, even under a 0% discount rate. The plant starts making a loss at the time of the first inverter replacement at year 15 as declining revenues fall below increasing costs.

Effect of the discount rate

As outlined in the previous article, a 10% discount rate is seen as the floor for prioritizing economically efficient infrastructure investments in the developing world. 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 solar 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 solar farm will be lower.

The graph shows that the required electricity price almost quadruples as the discount rate is increased from 0% to 15%. Inclusion of the value decline, balancing costs and grid costs increases the required electricity price by about $60/MWh at 0% discount rate with a moderate increasing trend towards higher discount rates. This impact is double that of wind power because of solar’s more pronounced intermittency and high correlation with other solar generators.

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 a little less than 0% when solar 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 0.6%. A much larger 8% drop occurs when the value decline is added. Further addition of balancing costs also has a large effect, reducing the annualized investment return to -13.5%.

The magnitude of the drop in investment returns is strongly influenced by the rate of solar power expansion over the lifetime of the plant (grey bars). More solar on the grid will reduce the value and increase the balancing costs of all solar generators. An increase in the rate of solar expansion from 0.5% to 1% per year lowers the investment return by 7%, while a further increase in expansion rate to 1.5% per year cuts another 5% off the annualized return.

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 a little over 2%.

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 a little over 2.5%.

Conclusions

This article has quantified the large negative effects of solar intermittency on project economics. The potential that these costs will eventually be fairly attributed to solar generators presents a major risk for solar farm investors.

Even when these intermittency effects are completely ignored, the global average solar farm does not give any return on investment without direct subsidization. As always, however, I have to stress that there are locations where solar is much more attractive. For example, the US South-West can achieve very impressive capacity factors up to 30% thanks to an excellent solar resource and high inverter loading ratios (which also increases capital costs to about $2200). Under these assumptions, the annualized investment return amounts to 2.2% (with no accountability for intermittency effects). Such high capacity factors will also significantly reduce the value decline.

When intermittency costs are correctly accounted for, the investment returns fall drastically – substantially more than for wind power. The annualized return on investment drops from -0.6% to -13.5% when intermittency costs and value declines are accounted for under the base-case assumptions.

The most influential factor in the analysis is the rate of solar power expansion. Higher expansion rates lead to larger investment losses. Interestingly, this dynamic actually reduces the investment risk because the steady increases in solar market share that cause this risk will not take place if value declines and integration costs are fairly assigned to solar generators.

This reinforces the earlier notion that continued solar power expansion will require perpetual subsidies. If solar 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.

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