Michael Grubb

The European energy crisis and electricity market (re)design

The European energy crisis was driven by gas, but amplified through electricity – where fossil fuels largely set the price, even though more than half the system is now non-fossil. This has prompted a huge debate about the way the European (and UK) electricity market operates – and whether and how it could be reformed.

Congratulations to the Oxford Energy Forum for convening a Special Issue for us geeks in the field – “Electricity market design during the Energy Transition and the Energy Crisis”.  Published on Friday 12th May, my own contribution, ‘Disentangling the debate on electricity market (re)design and ‘split markets’’ builds on and summarises recent work with colleagues at our Institute (UCL ISR) on ‘Navigating the Energy-Climate Crisis’.  It has built up to a series of four working papers, along with a recent policy report on decarbonising electricity for industrial electrification, published with the Aldersgate Group who supported the work along with the Institute of New Economic Thinking.

My OEF article summarises the fundamentals: why a single market based on short-run operating costs has caused problems and is not, on its own, adequate for the energy transition.

To be clear, the European Single Electricity Market does a great job at what it was designed to do—reflect, on a short-run basis, the cost of bringing on generation to meet demand at a specific time, anywhere across Europe.

But therein lie the problems. Firstly, it is a short run—very short run, marginal-cost-on-all market. The price in that market, received by all generators selling into it, feeds through almost all electricity consumption.

Secondly, most electricity systems are already split in terms of generation investments. Both nuclear stations and renewable energy technologies have in reality been financed primarily through additional mechanisms to support investment. Indeed, the most efficient mechanisms are those providing long-term price security, such as fixed feed-in tariffs or contracts-for-difference.

Moreover, these generators have very low operating costs. The figure below shows the British electricity ‘merit order’ structure (ranking based on generators’ short-run operating costs per unit output: vertical axis) plotted against their average annual output (for renewables) or available capacity (for thermal plant) in 2022 (horizontal axis). It is essentially what economists term a marginal cost curve – but strikingly, aside from biomass, it is not remotely continuous: compared to the average demand (33.5GW), the system was split almost evenly between plants that cost very little to run, and gas generation. The market structure, of course, meant that gas set the price; econometric studies show that in 2021, gas set the electricity price 98% of the time in Britain despite being only 40 per cent of generation.

Therein lay the great energy ‘winter of discontent’, and the reorientation of the UK government’s Review of Electricity Market Arrangements towards a wider range of fundamental questions. Namely, do we want short-run marginal prices applied to all generation and all consumption, or do we differentiate—and if so, why and how? And, if investment structures reflect long-run marginal costs – ie. the cost embodied in the contracts that financed the construction – should these to relate to consumer pricing—and if so, how?

In the current structure, all generators get the price required to ‘clear’ the market – ie. to bring on the most expensive generator required to meet demand in any given hour. In economic terms: ‘pay as clear’.  So most of the time renewables get the price of the most expensive fossil fuel plant required to meet demand.  But we are starting to see more periods when there is enough trenewables (plus nuclear) to meet demand – at which point, the market price collapses close to zero – known as ‘cannibalisation’.  If these sources just sold in to the electricity market at their operating cost they would never recover their capital costs. If they are guaranteed an output price, they bid negatively to make sure they can generate and so still get that guaranteed price. Competitive electricity markets are already beginning to see short periods of negative prices, alongside the wild high prices seen for much of 2022.

In economic terms this gap between short-run and long-run marginal costs will only increase, certainly in volume terms. In both the UK and the EU, non-fossil generation is expected to account for more than 75 per cent of generation by 2030—within seven years. The currently fossil-fuel-price-setting marginal cost curve element of the figure above is not only migrating rapidly to the right, it is on a trajectory to phase-out, reflecting the operational costs of fossil fuel generation.

The short-run prices are really important, for example to encourage storage – but how long can the disappearing fossil fuel tail continue to wag the dog of a renewables-based electricity system?

To read on and discover our analysis of the problem and proposed solutions to electricity market redesign, click ‘here’ for the Oxford Forum summary, or for detail, visit our working papers series: the evidence of historical prices (WP1); the revenues from the Energy Crisis (WP2); the underlying economic challenges (WP3); and what we coudl do about it (WP4).






More Outreach

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COPped out?  The Global Stocktake on Mitigation and and its implications

The Mitigation section of UEA Consensus on the Global Stocktake avoids the issue that should lie at the heart of a robust international agreement: what should be done if the “nationally determined” offers don’t add up to the agreed goals (they don’t – as acknowledged) and won’t (as is obvious). Understanding why is crucial for understanding what the COP can and cannot do – and hence the need to look beyond.

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