It’s been a dramatic start to 2021 for Britain’s electricity system, with record high prices recorded in both the nation's day ahead market and its Balancing Mechanism.
As low winds and cold temperatures began to tighten capacity on the grid, National Grid ESO - Britain's system operator - issued a number of Electricity Margin Notices (EMN). There have been six this winter already, a number not seen since 2008.
Following each of the most recent EMNs there has been a dramatic reaction in the day-ahead markets, with prices in the N2EX market hitting £1,500/MWh (US$2,051/MWh) on 13 January after the most recent notice was issued.
The imbalance market has seen similar reactions, hitting £4,000/MWh between 19:30 and 20:30 on 8 January. This is the highest unit price seen since 2001, in the infancy of the New Electricity Trading Arrangements.
Feeling the chill – falling temperatures and tight margins
The key reasons for the record highs are similar to those seen most winters, with energy usage growing as the temperature falls, creating higher levels of demand. In general, demand is around 30% higher in the winter than in the summer in Britain.
Colder weather also often means lower wind generation, whilst winter's lower irradiation also means lower solar generation. As such, renewables cannot be counted on to the same extent as at other times of the year to provide generation.
National Grid ESO has to turn to fossil fuel generation often to make up the difference, typically contracting coal and CCGT units. However, this year there is less capacity available here as well, in particular with only four remaining coal fired stations as the aging fleet is being retired ahead of the 2025 ban.
Last year saw the closure of SSE’s Fiddlers Ferry, and RWE’s Aberthaw B closed in 2019. This limits the potential baseload contribution for coal, tightening margins during periods of low wind generation such as we have seen early in 2021.
Whilst gas makes up a significant portion of the electricity mix still – accounting for 30.9% of the electricity mix in 2020 according to National Grid ESO – Caton Energy going into administration in 2020 has impacted availability, with Severn Power Station, Baglan Bay Power Station and Sutton Bridge CCGT power station’s all closing as a result.
Additional planned maintenance being undertaken at power stations has further impacted availability, along with unplanned outages at a number of sites.
Interconnector outages - a lack of lifelines
The importance of interconnectors and the reliance Britain's power system places on them has come into greater focus. The BritNed interconnector with the Netherlands has been down since September now, and remains out.
“There is still no news on the Dutch IC that is offline until 1 February but there is a likelihood for that to be extended given the lack of information and nature of the outage and REMITs,” added Adam Lewis, partner at Hartree Solutions.
Collectively these factors have added up to tighter margins on Britain’s grid, leaving National Grid ESO without a full safety buffer of supply, driving up demand and causing prices to jump. This has been further impacted to a certain extent by Brexit.
The UK officially left the European Union on 31 December 2020 and as a result, the British electricity market is no longer part of EUphemia – the EU + Pan-European Hybrid Electricity Market Integration Algorithm. Decoupling from EUphemia does not in and of itself create higher prices, but it does lead to a level of complexity in trading that has contributed to high prices in the first few weeks of 2021.
“The Day Ahead auctions continue to have large divergences with the N2EX auction clearing at £1,499.62 for 5pm today [13 January], £500 higher than the EPEX auction – the largest spread since Brexit led the UK to decouple from Europe,” highlighted Hartree’s Lewis.
A combination of these factors has created something of a perfect storm for high prices in the UK.
Could battery storage have made a difference?
One comment highlighted by industry watchers, is the lack of available storage in the UK capable of reacting to periods like this. Aaron Lally, managing partner at UK-based cleantech trading house VEST Energy for example said there continues to be an underinvestment in the battery storage sector, leading to more power market volatility.
“This market tightness has been masked since late 2016 due to warmer than seasonal weather and high renewable generation across Europe. During 2020, we have seen seasonal/cooler weather lead supply shortages and price spikes during March, September and Q4. We will see further events during January given the current weather pattern with the potential return of the 'Beast from the East’.”
“During most tight days, the price spikes are concentrated across 2-3 hours. With battery storage at 2 hour duration and increasing, it makes these assets perfect for supplying power to meet these price spikes.”
Volatility will remain common without additional investment he added, both through this winter and beyond. The UK currently has over 1GW of storage, and an ever growing pipeline of projects with a total of 14GW of planned battery projects across 700+ sites in the UK.
Since changes to planning legislation in 2020, storage projects are no longer limited to 50MW in England and 350MW in Wales as well, opening up the market for much more sizeable projects to help tackle these volatile price periods. Already, we’ve seen the country’s largest project to date – InterGen’s 640MWh Essex site –approved by the government.
Ultimately, high prices are wholly negative, as they can be an incentive for further project development as EnAppSys’s director Phil Hewitt pointed out.
“A power station that’s marginal is going to make reasonable money in periods of high prices, which might mean it will decide to stick around for another year or maybe somebody who’s developing battery projects or developing gas peakers or maybe even CCGTs is going to look at these high prices and say, ‘well, there we go, I can make money in this market'. So they're going to be more encouraged to build."
