RenewableUK's Economist & Market Analyst, Michael Chesser, on proposals for radical reform to the UK's electricity market and how these could impact the renewables sector.
With the publication of the Energy Security Strategy, market reform is firmly on the agenda for the electricity sector. The Review of Electricity Market Arrangements (REMA) launched by BEIS on 12th April set out the ambition to rewrite the market rules. But this is not the first step down this road. For some time now discussions about market reform have been taking place to deliver net zero.
National Grid ESO’s Net Zero Market Reform project was established in early 2021; it aims to examine holistically the changes to current GB electricity market design that will be required to achieve net zero. On 22nd March 2022, NGESO hosted an event presenting the conclusions of their Net Zero Market Reform project and recommended the adoption of a nodal pricing system for GB market as the best market design to achieve net zero at the lowest whole system cost.
Since their presentation, Energy Systems Catapult and Octopus Energy have released a report on the benefits of reforming the market to locational marginal pricing. However, an area of concern remains unaddressed: the investment case.
Market reform is certainly needed, and industry welcomes this discussion. As was highlight during the ESO’s presentation, as well as several similar reports, there are many issues that are driving the need to reform: constraint costs are rising at an increasing rate; balancing the network is becoming more challenging; and market signals are inefficient to unlock the potential of flexibility sources. The solution the ESO proposes is the introduction of nodal pricing system that would create real-time, dynamic locational signals.
The introduction of nodal pricing system would be a fundamental shift in the way we manage the market in the UK. It would lead to increased price volatility and complexity (indeed, this is the objective in order to incentivise behaviour). This will, in turn, increase risk and adversely impact investor sentiment, which could slow the pace of deployment of renewable projects needed to reach net zero by 2050. In depth analysis of investor impact and cost of capital on renewables projects is something that has, so far been missing from reports. We hope our concerns about the investment case will be eased when the full report with a deeper analysis by NGESO is released later this month.
When discussing locational pricing, references to the markets of Ontario (Canada), New Zealand and particularly the American market of Electricity Reliability Council of Texas (ERCOT) are often cited as examples of where nodal pricing is operating and incentivising investment in renewables. However, this is anecdotal at best and I would caution against direct comparisons without taking the fuller picture into account.
Just because nodal pricing does not completely deter the investment case for renewables in Texas does not automatically mean that it would have the same impact here. For example, Texas does lead the US in installed wind capacity, with capacity increasing from 9.4GW to 38GW after the introduction of nodal pricing in December 2010. However, Texas invested heavily in transmission capacity to support wind, and until 2021 the US had a Renewable Electricity Production Tax Credit, worth up to $0.025/kWh (£19/MWh) for renewable generation projects. Furthermore, this capacity is entirely onshore wind and there was no evidence presented to suggest that Texan offshore wind could also be deployed at the same pace and scale as onshore wind.
Locational or nodal prices may well be an important part of the picture in future, especially for demand (which the Energy Security Strategy recognised). However, at present, the industry remains strongly concerned that the introduction of nodal pricing will hinder, rather than help investment in and the deployment of renewables in the GB market and at time when we need to be accelerating towards net zero, not putting the brakes on.