Tight margins are to characterise this year’s winter period, with significant price spikes in the Balancing Mechanism possible.
This is the central theme of National Grid ESO’s Winter Outlook 2021, released today (7 October). It details how although the ESO is forecasting there will be sufficient capacity for the period to ensure safe and secure electricity system operation, the tight margins and price volatility seen last winter will also be present this year.
The forecast Loss of Load Expectation (LOLE) is 0.3 hours in the ESO’s base case scenario, with a range of 1.2 hours in the low case and <0.1 hours in the high case, which is within the reliability standard of three hours set by the government.
This is an increase on the LOLE forecast in the early view of the winter outlook, published in July. However, the de-rated margin for the period has decreased from the early view by 0.4GW, with it now expected to be 3.9GW. While this is lower than last year, it is still higher than in some recent years, with a higher peak demand forecast due to all COVID-19 related demand suppression assumptions lifted.
Tight margins and EMNs
Electricity Margin Notices (EMNs) are set to return this year, with 2020 being the first time EMNs were issued since 2016. Six in total were issued over the winter period, with National Grid ESO now expecting a similar number for this year.
While the ESO was clear that margin notices are a normal operational tool to highlight when margins are looking tight ahead of real-time, it did also state that there was a significant rise in the number issued last year. This was primarily due to the forecast supply margin being tighter than the previous three years, and elements of the generation portfolio underperforming.
In all cases when an EMN was issued, there was an appropriate market response, with prices rising, generation making itself available and interconnection flowing into GB. The ESO expects a similar market response for this year.
However, it also looked at how the risk of EMNs may change if plants which are near end of life have a fault which leads to permanent closure. If a total of 2GW of capacity – roughly equivalent to one coal and one nuclear plant – closes this way, then the expected number of EMNs could double.
Tight margins are likely throughout December to mid-January, excluding the Christmas period. The ESO’s sensitivity analysis indicates that the tightest margins could occur in the first two weeks of December.
However, Fintan Slye, executive director of ESO, said: “Margins are well within the reliability standard and therefore we are confident that there will be enough capacity available to keep Britain’s lights on.”
Any tight margin days could see significant price spikes in the Balancing Mechanism, while forward prices are high due to external pressures such as high gas prices. This will increase balancing costs even if the volume of system actions remains consistent with previous winters.
Traditionally, power plants have bid into the Balancing Mechanism at prices which largely reflected the marginal cost of running the plant over that period, with capital and operational costs recouped over a longer period through forward markets and/or long-term contracts.
However, fossil fuel plants are now operating less of the time due to increases in wind and solar, with a greater proportion of their generation now occurring through the Balancing Mechanism. As such they are bidding at higher prices to recoup some of their costs, particularly during tight margin days.
Last winter saw imbalance prices reach £4,000/MWh on several occasions, with the day ahead wholesale price also exceeding £1,000/MWh. While this tended to take place over periods when EMNs were in force, there have already been examples of this effect in September of this year and in periods for which there is no EMN in force.
Transmission demand and forward prices
Normalised weather corrected transmission system demand is set to be higher than last year due to the removal of COVID-19 restrictions. The normalised peak transmission demand is expected in mid-December based on the ESO’s latest forecasts, with this expected to be 46.9GW. The minimum operational surplus is projected to be throughout December to mid-January excluding the Christmas period.
Minimum demand is expected to be 20.7GW, while maximum triad avoidance is expected to be 1.2GW.
Forward prices, including peak prices, are expected to be ahead of those in continental Europe for the majority of the winter period, with forward prices for baseload electricity during winter 2021/22 in GB higher than those in the French, Dutch and Belgian markets. As such, the ESO expects similar import/export patterns over the corresponding interconnectors as last winter.
There may be some occasions where GB exports to continental Europe, although this is unlikely to be during peak times. Should GB experience some tight/stress periods, the ESO expects GB prices to escalate and interconnectors to import.
National Grid ESO’s actions
National Grid ESO outlined how it may need to take actions across its five core areas to maintain operability of the network over the winter period.
Managing reactive power and hence voltage levels continues to be challenging during low demand periods, it said, and therefore actions needed to be taken could include:
- Contracting generators in advance to be available to provide reactive power
- Taking within-day trading actions, or bid/offer acceptances, via the Balancing Mechanism so that generators provide reactive power capability
- Working with transmission operators to ensure an appropriate outage plan for reactive equipment maintenance so critical reactive equipment can be in service to manage voltage when needed
- Taking within-day action to manage MW flows across the network and voltage levels
The ESO also pointed to Dynamic Containment, which was launched last year and has seen volumes continue to grow to over 900MW.
Dynamic Containment High will be launched this month, which will allow larger demand losses to be secured.
Costs for frequency response will increase as a result of the increased volume of response being procured, but this increase will be partially offset by a decrease in the cost of individual loss risk controls due to fewer targeted actions being taken on large infeed and outfeed loss risks, including generators and interconnectors.