Can cost reflectivity survive a renewables world?
The importance of cost reflectivity has been central to economic regulation. Price signals that reflect the true underlying cost of an action are important when trying to incentivise the right behaviours through the whole value chain. In the power sector, this is true whether we are referring to decisions made by end consumers, or decisions made in the dispatch of a generation asset.
The ongoing rapid and disruptive shift to low carbon generation is being accompanied by a shift from generation technologies where short-run marginal costs are an important driver in economic decision making, to technologies where short-run marginal costs are near-zero. As this shift takes place, and as governments and regulators override the short-term market to take into account externalities (most obviously, the need to meet policy objectives to reduce carbon emissions), the principle of cost-reflectivity is being abandoned or, at best, distorted.
The end of a single market?
Let’s take an EU example – the home of the single market, and the “Target Model” that aims to align principles of cost reflectivity in power markets across the single market. Except that it only looks at short-run markets. And most of the cost stack of new generators is now outside of those markets.
An example of where this breaks down:
The price received by successful offshore wind projects in the UK’s CfD allocation round in early 2015 was in the range 114-120 £/MWh.
In the Netherlands, the recent Borssele offshore wind farm auction cleared at 72.7 €/MWh, or 82 €/MWh once transmission connection costs are considered.
Of course, we are not comparing apples with apples. The Dutch government took on much of the development risk for Borssele, whereas this was left to developers in the UK.
We can go further than the Borssele example. In Zambia, an auction for solar PV projects achieved a price of 60.2 $/MWh on one project. However, this auction was held under the IFC’s Scaling Solar programme. This is a great innovation to mobilise private sector investment into solar in countries that might sometimes be seen as ‘too difficult’, but the corollary is that the investor – and the consumer – is wrapped from many of the risks that would normally be included in a cost reflective tariff.
I’m not going to argue against any of these approaches – there are clear pros and cons we could debate about the various approaches taken: in the UK, in the Netherlands, and in Zambia. But as we move into a world of renewables, there is no common approach to maintaining cost reflectivity. I would certainly argue that the Netherlands will no longer have cost reflective electricity tariffs, for example.
The power sector is undergoing rapid change. Technology costs have been falling, and a plethora of different approaches to supporting new renewable technologies means that there is an increasing amount of inconsistency in how price signals are passed through the value chain.
Will this remain the case, or will a new consensus emerge, with common cost-reflectivity principles being adopted in the long-run pricing of generators? If technology costs continue to fall then maybe it will be possible to run auctions, or other procurement mechanisms, that are totally technology neutral, with common standards being adopted regionally or internationally? Or maybe we will continue to see risk trickle back from the bill-payer to the tax-payer, with the reintroduction of regulated retail prices?
It is unclear which path we are on. My hunch is that the regulators’ decision making will be forced by the decentralisation of energy services. On the one hand decentralisation could lead to greater consumer choice, and more innovative commercial offerings. This might, for example, lead to more Energy as a Service (“EaaS”) offerings, where consumers simply pay a monthly fee with some usage cap, as they might do for a broadband deal. This business model is being deployed in off-grid projects in Africa, and it could become more widely used in developed markets.
On the other hand, more extreme decentralisation scenarios could lead to what is commonly referred to as the “utility death spiral” as utility cost recovery is undermined by erosion of the charging base. It seems likely that the regressive nature of such an outcome means that governments would step in if such a scenario were to emerge, which could lead to a transfer from tax payers to bill payers that could totally undermine the economic signals leading consumers to cost effective decentralised solutions.
There are, of course, no easy solutions, but a long-term vision is urgently required that sets out whether we want to preserve the principle of cost reflectivity through the value chain and, if so, what a market that achieves this might look like in a decarbonised power sector.