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Environmental policy

Environmental policy

The cost of power: moving beyond LCOE

03 Mar 2018 Dave Elliott

Levelised Cost of Energy (LCOE) figures are widely used but are a poor measure of actual energy costs. Can we do better? Can balancing costs be included? And what are we actually measuring – the cost to generators or the cost to consumers, asks Dave Elliott

How much does energy cost? LCOEs – Levelised Costs of Energy – are widely used as a comparative measure. They give an estimate for the cost of energy generation from specific plants, but do this by averaging out the investment and running costs over the plant’s lifetime and comparing that with the value of the electricity generated. However, the costs and earnings can and do vary over time and are hard to predict. LCOEs also omit any associated grid balancing/backup costs. So they have big shortcomings. Can we do better?

Certainly there are many weaknesses in the LCOE approach. Finance costs will depend on interest rates and inflation both of which can change over time, sometimes dramatically. So may fuel and labour costs. Energy output may also vary for many reasons and in the case of renewables will vary with the weather. In that case, use is usually made of ‘capacity factors’ to reflect average likely delivered outputs, but in reality these variations are dealt with by balancing capacity and services, the cost of which, arguably, should be added to the cost of generation.

However, doing this is not simple. Studies by Imperial College London have suggested that in order to capture the full costs and benefits of variable renewables, we have to look at total system costs, including the cost of full grid balancing/backup, not just the individual component LCOE of generation and of individual backup plants. Robert Gross from Imperial has pointed out that “Demand response, flexible generation, storage and interconnection offer benefits to the system as a whole and building them as if they need to be dedicated to each specific variable renewable installation will result in over-investment. System costs should be charged to generators as cost-effectively as possible, but on the proviso that they are assessed at a system wide level rather than on an assumption that variable renewable installations need to self-balance.”

Similar views have emerged from other studies.  A World Bank study of variable renewable energy (VRE) system optimisation said that it was not helpful just to look at individual balancing or supply options in isolation, focusing just on the lowest cost ones: “Policy, planning and regulatory interventions should be designed to minimize overall system costs subject to meeting performance targets, rather than minimizing the costs of VRE generation alone.”

A study of optimal approaches to managing high renewable energy mixes in the US similarly stressed the need to select generation options appropriately, looking at total system costs, not individual component costs, and where possible, choosing supply options with output profiles that complemented each other.

Rough estimates of the extra balancing costs imposed by renewables on the energy system have been made and range from 10% to as much as 50%, depending on the assumptions and data used. For example, the 50% estimate is from the Potsdam Institute. They include what they call “profile costs”, the extra costs faced by conventional generation companies given that renewables, with their low marginal costs, can at times push conventional generation out of the market, undermining the company’s profits. Are their losses strictly a cost or just part of commercial reality?

Even if agreement can be reached on what to include in the costs, it is hard to identify future optimal mixes and the exact extra costs, given that the whole system may change – it’s a moving target, with many unknowns as to the future mix. The UK Energy Research Partnership (ERP) notes that “The value to the system is highly dependent on the technology mix on the system, and the effect of diminishing returns reduces the value of all technologies as they are added, but especially so of variable renewables which generate an increasing proportion at times of surplus energy.” Certainly, the ERP says, “Using a fixed number (like LCOE) to characterize a technology’s economic value is quite unhelpful in these circumstances.”

So the ERP, along with Imperial College and others, all agree, although sometimes for different reasons: LCOE is not a good enough measure. Some analysis has consequently tried to come up with new measures to include the extra costs. However, there is no consensus on how this should be done. For example, the Potsdam Institute makes use of ‘overall system costs’, including integration and, as noted above, more contentiously, profile costs.

Clearly, even leaving aside issues like that, it is not easy to assess the full likely costs: all generators (including nuclear) can need backup at times, not just renewables, and it is hard to assign fair shares of the costs of this provision to each generator in the overall supply mix. In the UK, a Capacity Market has been set up with auctions for balancing capacity. That provides a way to quantify costs, across the system, but doesn’t allocate them to specific generation projects. And the costs, as with generation costs, are just passed on to consumers.

The last point, of course, suggests another approach – start from the other end, the costs to energy users. In the UK, new renewable and nuclear projects are being supported by a Contract for Difference (CfD) subsidy system, backed up by the Capacity Market, with the extra cost being passed on by the power companies to energy consumers. In a review of Tidal Lagoons by the Tidal Lagoon Power Ltd, use was made of measures of costs to consumers, calculated not on the basis of LCOE, but on “equivalent CfD contract” costs, with the net present value of actually delivered electricity calculated over the lifetime of the project, taking capacity factors into account. However, grid costs were not included: while it was noted that some may increase the total cost, any flexibility provided (e.g. via storage) may offset that. The end result was some dramatically different cost figures. Whereas on an LCOE basis, lagoons look to be the most expensive option, on this consumer cost basis some lagoons came out cheaper long-term than all other energy options.

It is not immediately obvious that this is a fair rendition of reality, but then neither is an approach based on LCOEs, especially if it is just used for individual projects. For example, in the case of extra gas plants used for back-up power, their capacity factors may be very low (they only run occasionally), so their LCOE will be very high, but they can make a valuable contribution to balancing the overall system. A wider cost valuation framework is needed. I will be looking at some new attempts to take variability into account, including one from Imperial College, in my next post.

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