In mid January, U.K. day ahead baseload power prices hit close to £200/MWh, and intra-day, half hourly auction prices on the N2Ex exchange reached an eye-watering £1500/MWh. This surge, and these record-breaking prices, followed the National’s Grid sixth supply margin notice of the winter season.
Although remarkable in itself, this was not an isolated event. Britain’s supply margins – the difference between available generation capacity and demand - have been under pressure for a number of years. Recent warnings from National Grid in relation to tightness within the electricity system have been rolling in since late November, with spikes in day-ahead pricing as a result. These capacity market notices, provided four hours in advance, are issued by the National Grid when there is a perceived risk of a supply-demand imbalance.
The primary driver of such warnings, and the associated volatility around day-ahead prices, is generally as a result of a shift to colder, calmer conditions typically associated with winter weather. Such a shift increases the nation’s gas demand for both heating load and power generation with renewable generation – particularly wind generated supply – falling, and with available capacity being squeezed as a result. Cold and calm conditions did, indeed, precipitate the extreme price volatility that we witnessed in early January. However, a combination of other factors has helped create the perfect storm that exacerbated this sharp and sudden climb.
Firstly, demand-side pressures have been greater than expected. Clearly, industrial output has fallen due the various restrictions and lockdown measures that have been introduced due to Covid, with demand for electricity from this sector consequently falling. However, some of the slack in industrial demand has been offset by a significant pick-up in residential heating demand – primarily due to working from home and school closures. This has been further exacerbated by a nationwide spell of cold weather and low temperatures, which saw U.K. power demand jump to levels close to those seen in the same period in 2020, in spite of the lockdown restrictions in place.
Secondly, electricity interconnectors between countries play an integral role for balancing Britain’s electricity demand requirements on the transmission network, specifically on a day-ahead basis. Under normal circumstances, higher U.K. prices would attract interconnector flows from neighbouring countries, namely France, the Netherlands and Northern Ireland. However, much of northwest Europe have also been experiencing similar cold temperatures and extreme weather events, leading to their own domestic capacity tightness. Furthermore, with the closure of the Netherlands connector for repairs and a reduction in France’s nuclear output to 82% due to a plant outage, this only helped further reduce available flows to the UK.
Thirdly, Brexit and the U.K.’s decoupling of the UK’s electricity market from the European energy markets from 1st January are also likely to have played a part. Previously, interconnector capacity was allocated implicitly together with electricity sold in the spot market, rather than the interconnector capacity being sold separately in explicit auctions as it is now. Although, it isn’t entirely clear the exact contribution this may have had to January’s dramatic spot market surge, such interconnector inefficiencies appear likely to have exacerbated the spike in prices.
Understanding the market dynamics behind energy price volatility is a key element in managing our clients’ energy exposure. By developing a Strategic Energy Risk Plan (SERP), NUS’ Markets, Trading and Risk (MTR) team enable our clients to manage these and other associated risks in a controlled and structured manner / fashion. With over 40 years combined experience in energy markets and risk management, MTR is well placed to provide the type of expertise necessary to deal with the increased market complexities as the U.K. generation mix becomes ever more diverse.
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