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Seeking Consensus on the Internalized Costs of Utility-Scale Solar PV

What is meant by “internalized costs”?

Internalized costs are the costs which can be accurately accounted for in our current systems. In energy production, these costs typically consist of capital costs, financing costs, operation and maintenance costs, and exploration costs. Some energy options incur these costs in various stages such as extraction, transportation and refinement. Profits and taxes are excluded wherever possible in order to isolate the pure cost of production.

Internalized costs of utility-scale solar PV

Solar PV costs depend strongly on several factors, the most important of which being the capital costs, capacity factor and discount rate. The current status of the internalized costs of utility-scale solar PV is well summarized in two recent reports from the IEA and BNEF.

To get an overview of capital costs, a graph compiled by the IEA Medium-Term Renewable Energy Market Report is given below.  

The BNEF World Energy Perspective document gives capacity factors of global solar farms in the range of 11-21%. Farms equipped with single or double-axis tracking systems can achieve higher capacity factors, but are generally more expensive than fixed-tilt farms on a LCOE basis due to the added CAPEX and OPEX of the trackers. Tracking systems will therefore be ignored in this analysis.  

Discount rates for onshore wind were discussed in the IEA Medium-Term Renewable Energy Market Report where examples were given for a developed nation (Germany) and a developing nation (South Africa). The risk involved in utility-scale solar should be similar to that of onshore wind. 


The LCOE of utility-scale solar PV is given below as a function of the capacity factor for different capital costs (at 6% financing costs) and financing costs (at $1800/kW capital costs). Other assumptions include O&M costs of $30/kW/yr and a plant lifetime of 30 years. The Excel file from which these figures were compiled can be downloaded here.


The cost of using utility-scale solar power for heat is given below.


As outlined in the previous article on the internalized costs of nuclear, transport costs using utility-scale solar PV energy will be estimated based on optimistic projected technologically mature synfuel production technology. Since synfuel plants will be operating predominantly during solar/wind peaks in a variable-dominated system, a synfuel plant capacity factor of 30% was employed. 


If you have a number that differs significantly from the estimates given above, please add it in the comments section below together with an explanation and a reference. 

Schalk Cloete's picture

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Schalk Cloete's picture
Schalk Cloete on November 4, 2014

DATA: Global average utility scale solar PV LCOE: $101/MWh. This is for a capital cost of $1800/kW, a capacity factor of 18% and a discount rate of 6%. The capacity factor is given towards the higher end of the given range of real world results (11-21%) since utility scale PV plants will generally be built in locations with the best solar insolation. 

Schalk Cloete's picture
Schalk Cloete on November 4, 2014

It does look strange that utility scale and residential rooftop solar PV costs the same in China, but this is the data compiled by the IEA and I just presented it as it was given. One reason could be that utility scale solar is mostly built in the sparsely populated western regions of China where solar insolation is good but labour and infrastructure is scarcer, while rooftop solar will be built in the densely populated eastern regions where lots of cheap labour is still available but solar insolation is generally quite poor. 

I also don’t see much room for further price reductions in residential rooftop, especially if Chinese labour costs keep rising at the current rate

Roger Arnold's picture
Roger Arnold on November 5, 2014


While I applaud the intent of “seeking consensus on the internalized costs of utility scale PV”, I don’t think that the easy data on module and installation costs really capture the more interesting economic issues for utilities. Missing from your definition of “internalized costs” are the issues of service life and collateral system costs. Those are important — albeit contentions — issues.

If I were a utility executive, I would want the financial cost analysis to reflect, as part of the internalized costs, the impact of PV deployment to the system as a whole. It should include the cost of backing service for nights and cloudy weather. PV advocates will downplay those costs, maintaining that normal load-following capabilities of the grid are sufficient to accommodate solar without significant financial impact. That’s arguably true, for low penetration levels.

For higher penetration levels, advocates will cite the capabilities of the new generation of flexible combined cycle gas turbines. They have faster ramping speeds, a broader throttling range for efficient operation, and are better able to withstand the stress of frequent cycling than older combined cycle gas turbines. However, “there ain’t no such thing as a free lunch”. That flexibility comes at a cost.

The capital cost of those units per kWh delivered annually is quite a bit higher than it is for older baseload-use combined cycle units. Partly, that’s because the new flexible units are inherently more expensive, relative to rated capacity, than the older baseload units. But mostly, it’s because in being used for backing service for irregular renewables, they deliver far fewer kWh each year than they are capable of delivering. The high capital cost for flexible backing service raises overall utility rates. It has to be counted as an integral part of the cost of grid-scale solar.

But good luck trying to quantify it.

The other big issue is service life of grid-scale solar. You didn’t state what lifetime was assumed, and the discount rate tends to reduce its imporatnce — as long as it’s at least 20 years or so. But it it? Unlike conventional nuclear power, where we have hard evidence of long lifetimes, all these newly economical solar PV modules don’t have much history to support optimistic service life projections. In fact, we do know of instances where cheap modules failed after only a few years of operation. That was supposed to be an anomoly from poor quality control in the economically stressed production factories, but if problems of that sort are common, how would we know?

For any capital-intensive resource like solar PV, service life is a risk factor that can play havoc with projections for internalized costs. But again, good luck trying to quantify it.

Schalk Cloete's picture
Schalk Cloete on November 7, 2014

Thanks for the detailed comment. I plan to discuss integration costs of intermittent renewables as an externalized costs in the next section of the Seeking Consensus column. Currently, these costs are mostly externalized because installers receive a fixed income from their PV installations regardless of what the electricity is actually worth at the time of production. This means that, from the point of view of the supplier, PV is as good as baseload (even though that is of course very far from the truth from a system perspective).

I used a 30 year lifetime in my analysis. Real world experience in PV lifetime will indeed be very interesting to observe. In general, PV plants can stay open as long as income from electricity sales exceed O&M costs. As a plant ages, income from electricity sales will decline (due to the forced internalization of intermittency costs and panel degradation) while O&M will go up due to panel wear. 

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