• Charlotte Johnson

The (im)perfect storm: a winter outlook

The recent energy crisis has led to questions around whether or not there will be sufficient generation available on the system for winter this year. Whilst it is widely understood that wholesale electricity, gas and carbon prices have been increasing over the past year, in the UK in particular an (im)perfect storm of events has led to extreme pricing beyond those that can be explained simply by rising commodity costs.


September this year brought unseasonably low levels of wind generation, on September 15th of the 22 GW of installed onshore and offshore wind capacity only 10% or 2 GW was generating. Wind generation is often expressed as a percentage of the maximum feasible generation, known as a load factor. In the first three weeks of September, wind load factors were nearly 60% lower than the average load factor for the past five previous September months. Low levels of wind combined with unplanned and planned outages of thermal and nuclear plants led to a tight system. During the tightest system periods, a handful of thermal generators set power prices in excess of £2,500/MWh in the wholesale market and over £4,000/MWh in the Balancing Mechanism (Fig. 2).

Figure 1. - Average daily load factor for Sept-21 compared to the 5 Yr average. For the first three weeks of September, load factors averaged 13% in 2021, compared to 30% over the past 5 years.

Figure 2. - Low wind generation output coinciding with high system prices in the second week in September 2021.


In instances like this, National Grid often ends up paying significantly more to balance the system. Balancing costs are usually around £2-3m per day. However, on September 15th, they were over £29m for the day. These costs are recovered through a mechanism called BSUoS (balancing services use of system charges), a half hourly charge applied to consumption. Last year, BSUoS costs increased significantly during the pandemic when National Grid spent over £700m balancing the low levels of demand on the system during high levels of renewable generation. Events from September 2021 have increased BSUoS costs to rates nearly three times higher than last summer (Fig. 3).

Figure 3. - Half Hourly BSUoS costs from 2019 to Sept-2021. Will there be sufficient capacity on the system for this winter?


Although the UK currently has approximately 100 GW of installed generation capacity, not all of this can be called upon or is available all the time and therefore National Grid uses a term called the ‘derated-margin’ to illustrate the amount of excess capacity expected to be available against underlying peak demand. In their Winter 2021 outlook released last week, a de-rated margin of 3.9 GW was indicated for winter 2021 (Fig. 5), which is 0.4 GW lower than the ‘early view’ published in July and has likely been decreased owing to updated generation capacity and demand assumptions. For context, this is higher than the de-rated system margin on September 7th, 9th and 15th (2 GW) and still higher than the lowest margins in 2015/16.

Fig 4. The de-rated margins included in previous Winter Outlook Reports and highlights how, while this year is slightly lower than last year, it is still higher than the corresponding margin seen in 2015/16 and is the same as in 2016/17.


Peak demand over winter is usually over 42 GW or 10 GW higher than demand on the 15th of September. However, this winter, more nuclear and thermal generators should be online (Table 1) so more firm capacity would be available when needed. The biggest question posed is how expensive will this generation be?


Table 1.

Last year, up to six Electricity Margin Notices were issued (the first EMN since 2016). The majority of these notices were issued for the peak times. However, one was used on a weekend, on Sunday, December 6th, illustrating that margins can be tight at times of lower demand, if corresponding supply drops sufficiently. Each notice was cancelled ahead of time as there was an appropriate market response – prices rose, generation made itself available, interconnection flowed into GB – such that security of supply was always maintained through the peak periods. Nevertheless, it is likely that National Grid will use margin notices again this year to notify the market of tight margins and a loss of 2 GW of capacity could lead to the expected number of EMNs doubling.


What price will we have to pay for this capacity?


Traditionally, power plants have bid into the Balancing Mechanism at prices which largely reflect 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 renewable generation. As such they are bidding at higher prices to regain some of their costs.

For example, on September 15th, the CCGT capacity (as per the Final Physical Notification) benefited significantly from system tightness (Fig. 5), with monthly revenues doubling in September. Perhaps the most important driver of extreme pricing this winter for a system that is quite sensitive will be the weather, in particular wind. High levels of wind output will reduce the demand for gas assets.

Figure 5. Monthly revenue for CCGTs from Sept-20 to Sept-21.


It is not just about balancing supply and demand


Supply and demand are not the only part of the system that National Grid has to balance continuously and in real-time. Other challenges on the system include reactive power and inertia.


Winter months bring more inertia to the system as more thermal generators are online (thermal generators provide inertia when spinning) therefore, services such as frequency response are not in as high demand during this season. However, reactive power (an indicator of voltage) continues to be challenging during low demand periods at weekends/holidays. To mitigate this, National Grid contracts with (predominantly) thermal generators in advance to provide reactive power, and take actions via the Balancing Mechanism. As thermal plants retire and generation from renewables increases, a sustainable solution is needed for reactive power services from distributed energy resources.


Conclusion


In summary, evidence suggests that there should be sufficient generation on the system this winter, but it could come at a price. The UK relies on gas peaking plants for power during times of system tightness and owing to rising gas and carbon prices, this is costly. In the future, thermal plants will retire and the nuclear fleet will age, highlighting the need for low cost firm capacity during periods of low renewable output to secure power. Although short duration grid batteries are efficient at peak shaving/short term balancing and grid stability services, they will not replace firm capacity. However, there are possible solutions including, CCS, hydrogen CCGTs, nuclear, long duration storage and BECCs. Nevertheless, with the exception of nuclear, these technologies are not mature enough to be able to compete in the market without subsidies.



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