Day-ahead power prices in the UK twice spiked to highs of more than £100/MWh in the last two weeks as the UK power system experienced very tight supply margins. But why did prices hit record highs on a balmy day in mid-September, rather than the depths of mid-winter? And what does this say for the winter ahead when cold temperatures push demand to its peaks for the year?
Tight supply margins were initially forecast by National Grid for the week-commencing 12 September 2016. Day-ahead prices for Tuesday 13 September jumped to £60/MWh – an increase of over 50% from the previous week and the highest prompt price since late 2014. However, the Day-ahead market surged a day later as National Grid forecast negative margins for Thursday 15 September. Concerns that available supply levels would not be able to meet expected peak demand on the day triggered a spike in Day-ahead prices to over £150/MWh – the highest price in over ten years. Within-day prices climbed even higher, with auction prices for the hour to 8pm on the Thursday night – when margins were at their tightest – hitting a maximum of £999/MWh.
Despite the substantial price surge, National Grid did not issue any system alerts, or utilised any of its emergency balancing tools to reduce peak demand. Many of the balancing tools are not included in National Grid’s margin forecast, acting only as reserve power in last resort cases.
While Day-ahead prices fell sharply on Friday 16 September, tight margins continued to contribute to a price premium and contracts for delivery early the following week again spiked above £100/MWh. Hourly auction prices hit £960/MWh as National Grid again forecast negative supply margins at times on Monday 19 September. Prices have since dropped back below £40/MWh, but the issue has raised concerns over a possible repeat situation occurring during the colder winter months when demand will be at its highest.
Why were margins so tight?
Low wind generation and a series of outages – planned and unplanned – were the main contributory factors for tight supply margins in the last few weeks. During the September maintenance period known plant unavailability was over 16GW. By 12 September this had fallen to 8GW. However, a series of unplanned failures at the Hunterston, Heysham and Hartlepool nuclear plants led to a sharp fall in nuclear plant availability, tightening supply once again. Unavailable nuclear generation peaked at nearly 3GW on 17 September, a five-fold increase in outages since the previous week, while unavailable coal plant reached around 4GW by 17 September. CCGT plant outages also increased week-on-week by over 1GW, while an unplanned outage on the French IFA power interconnector and planned maintenance on the Dutch BritNed link added to the reduced supply picture.
The resultant spike in Day-ahead prices did offer an incentive for plant to generate, with several coal power stations making themselves available to help boost supply margins. An additional 2GW of available supply helped to offset the nuclear and CCGT outages, but overall supply was still tighter.
The increased outages contributed to a drop in supply availability recorded as a unit’s Maximum Export Limit (MEL). Overall plant MEL dropped from 43GW during peak demand periods on 5 September to just 38.5GW for 12 September.
Going into the days with low margins, there were additional issues over a sharp drop in wind generation. Wind output averaged 2GW on Monday 12 September before tumbling to just 0.4GW by Thursday. Prices soared with the system requiring additional supply to make up for the lower wind availability. Day-ahead prices fell sharply the following day as peak wind generation reached 5GW. Prompt prices spiked again the following Monday as wind generation fell further, averaging just 0.3GW across the day.
What was the response to the rising prices?
Power plant, predominantly coal-fired power stations, which had not nominated to generate on that day, responded to the higher price, driven by traditional market principles of supply and demand. A lack of profitability in coal-fired generation in recent years had contributed to significant coal plant closures in the last year. Over 6GW of coal capacity has closed since the start of 2016. Coal burn dropped sharply as plant closed at the end of March and its share of the UK fuel mix has been steadily swallowed up by gas-fired generation. At present, total coal capacity in the UK is just under 12GW from seven remaining power plants. In addition, one unit from Fiddlers Ferry is part of the Supplemental Balancing Reserve (SBR) and will be available from November only when called on by National Grid. Two Eggborough units are also part of the SBR providing an additional 775MW as required during the winter.
On 10 September there was less than 6GW of coal availability, with around 6GW of plant capacity reporting a MEL of zero on the day. However, as margins tightened, and prices rose coal plant was encouraged back online. By 15 September, when margins were at their tightest, total MEL availability from coal plant had reached 8.5GW. Over 2.5GW of previously unavailable coal plant, which had not been offline for any notified maintenance or outage, had been made available – notably two units at the Aberthaw plant, and one each at Drax, Cottam, West Burton and Ratcliffe.
Physical generation climbed, boosting margins and ensuring the system avoided any significant supply issues. Average coal-fired generation rose to over 4GW on Thursday 15 September, up from lows of just 0.06GW from the previous week.
It’s the summer – what happened to demand?
When Day-ahead power prices hit record highs at over £150/MWh, several reports pointed to the unseasonably mild temperatures the UK was experiencing at the time, citing increased use of air conditioning units driving up demand as the driver for higher prices.
However, peak demand moved very little week-on-week at that time, remaining just below the 38GW mark. This was around 2GW lower than the same time last year. This was despite maximum temperatures in the UK at the time being more than 10 degrees warmer than the corresponding week in 2015. Demand was not a significant driver in the higher power prices seen in September, rather it was reductions on the generation side which triggered the tighter margins.
How does this affect the winter outlook?
This winter’s margins are forecast at just 2GW or about 4% of last year’s highest demand (51.3GW on 18 January). However within this margin an expectation of wind generation is included. The grid is typically forecasting usable wind output of over 4GW through December and January this winter. However, generation is often significantly different. Over the last two winters wind generation was at one third of normal levels about ten per cent of the time, and it is these outliers that will stress the system this winter, and cause price spikes.
National Grid have already confirmed they will have an increased bank of reserve generation available and expect to utilise its range of balancing tools far more frequently. Close to 4GW of additional supply has been secured as part of the Supplemental Balancing Reserve, which can be called upon if required in an emergency situation. The cost of administering these tools will be passed onto consumers in the form of higher non-commodity charges. However, it is with the wholesale side of the bill where consumers can best take advantage of the fluctuations expected as the energy market navigates an uncertain winter season. Below seasonal normal temperatures for December, combined with lower than forecast wind output would tighten supplies and could drive up Day-ahead power prices similar to recent weeks.