The (im)perfect storm
Two weeks into the new year and National Grid ESO (NG ESO) has already issued three Electricity Margin Notices (EMN) and one capacity market notice due to system tightness.
This has led to high prices. In addition, the UK leaving the Internal Energy Market (IEM) created further complexities including the decoupling of the GB day-ahead auctions.
The first EMN arrived on Tuesday, January 5th for Wednesday 16:00–19:00 due to a margin shortfall of 584MW (Table 1). Day Ahead prices responded with the hourly N2EX and EPEX auctions reaching £1,000.04 / MWh (the highest DA price in the hourly auction) and £737.45 / MWh respectively, a difference of £263 / MWh between the hours 17:00–18:00 (Fig. 1). In the Balancing Mechanism, West Burton B stepped up to the mark, with a bid accepted at £3,000 / MWh.
On Thursday 7th, NG ESO issued another EMN for Friday. However, they cancelled this warning at 2pm the next day. For the second time that week, EDF’s West Burton B2 and B3 had successful bids at £4,000 / MWh in the Balancing Mechanism, resulting in an imbalance price as high as £4,000 / MWh on Friday evening, concluding an eventful week.
This week, NG ESO issued an EMN for Wednesday, due to high demand and low wind generation. As a result, day-ahead hourly auction prices reached £1500/MWh for N2EX and £1000/MWh for EPEX. Similar prices can be seen for the tonight too (Fig. 1).
On top of this, on Friday, January 8th at 2.04pm a capacity market notice was issued for 6.30pm, once again, this was cancelled 30 minutes later. The transmission demand and operation margin forecast was 45,081MW compared to the aggregate capacity of BM units expected to be 45,275MW leaving a margin of 194MW.
What caused these prices?
This week’s price volatility was driven by drops in temperature leading to higher electricity demand during low wind generation. However, there were some other factors extenuating the situation.
For context, last week the peak system demand forecast was 47.9GW[1] (although the outturn was lower at 46.54GW), compared to the highest system demand so far this winter which was 47.27GW on December 7th. As well as, the cold weather, it has not been very windy. For example, yesterday the wind generation forecast was as low as 3GW compared to 8GW yesterday and a peak of 7GW today (Fig. 2).
Adding more fuel to the fire, EDF nuclear plants Hinkley B and Dungeness B are offline on long-term shutdowns leaving a total of 2GW of nuclear baseload capacity missing. In addition, the 1GW Britned interconnector went offline on an unplanned shutdown on December 8th. It is scheduled to return on February 1st.
Day-ahead auction decoupling
Although much of the price volatility seen over the past two weeks was driven by the changing nature of the GB generation mix, there is now also the added impact of Brexit and the decoupling of GB market auctions from EUphemia (EU + Pan-European Hybrid Electricity Market Integration Algorithm) — an algorithm that links the EU’s day-ahead electricity markets.
As a result of leaving the IEM, the two main auctions in GB have decoupled from each other, which means that the two main day-ahead auctions (operated by Nordpool and EPEX-Spot) can clear at different prices. This auction decoupling is a result of Brexit whereby the Euphemia market coupling algorithm is not applied to the GB Day Ahead market.
Will this price volatility continue?
As Great Britain strives to reach an offshore wind target of 40GW by 2030 to decarbonise its energy system, it is likely that volatility is here to stay given the current system design. Enabled by cost-reflective pricing and forecasting, optimisation and control capabilities, this presents significant revenue opportunities for flexible technologies such as battery storage, DSR and electric vehicles, which can shift generation and consumption in response to real-time pricing.
Author: Senior Commercial Analyst, Charlotte Johnson
[1] The actual demand was lower at 46.54GW.
