In our last blog post, Professor Tim Green took a look at what we now know about what happened on Friday, 9 August. The full report is still not due until early September, but we asked Dr Aidan Rhodes to tell us what this could mean for the future of the grid.
As we now know, on Friday the 9 August, just before the start of the rush hour, the National Grid suffered an unexpected loss of power from two power stations. This resulted in about 5% of the UK’s power demand to disconnect from the system temporarily to stabilise the grid before backup reserves kicked in – this lasted about 15-35 minutes and had knock on effects in several areas, particularly the transport system.
This has raised two main concerns, firstly about the integration of renewables and the type of back-up services needed, especially as the amount of inertia on the system decreases, which Tim covers in his blog. The second is that on a cloudy, windless winter’s day, the UK just may not have enough electricity generation to satisfy demand.
Should we be concerned? As we move towards a power system that is made up of more renewable power and more decentralised, will reliability inevitably decrease? Were the power cuts of 9 August a vision of worse troubles ahead? Reports of other ‘near-misses’ by National Grid compounded these worries among some observers.
In 2017, myself and a few others at Energy Futures Lab researched this question, which led to the publication of our first Briefing Paper on UK electricity security.
What did we find out? Firstly, over the past decade, the UK’s electricity system has remained secure, with the vast majority (99.9%) of blackouts being caused by faults in the local distribution network. There has only been one other power cut caused by loss of supply in the last 25 years – in May 2008, when the large Sizewell B nuclear power plant tripped out. During this time, we’ve seen a substantial shift in how our electricity is generated. Coal generation has fallen almost to nothing, from an average of 35-40% (15-20GW) in 2013 and wind and solar have increased markedly, leading to over half the UK’s electricity being provided from renewables (including hydro and biomass) in June 2017. Gas generation has filled a lot of the gap left by coal, rising over 50% since 2013. Peak winter demand is also dropping slowly, with a clear trend downwards over the past five years.
With these large changes in the generation mix of the electricity system over the last decade, is our electricity system secure enough to provide adequate supply at all times, especially over the demanding winter months? The good news on this front is that the Capacity Margin – the excess of total generation capacity over total forecast demand – has been robust over the last couple of winters. In 2018-19, the capacity margin was 10.3% above underlying demand, and in 2018/19 the margin increased to 11.7%. National Grid will release this year’s Capacity margin in October in the annual Winter Outlook Report.
This increase in margin is partially due to the Capacity Market, which is an auction-based market in which generators bid to provide guaranteed capacity (they will be available to provide electricity) over the winter period. Auctions take place four years in advance to allow time for new power stations to be built and have now been completed for the winters up until 2020/21, with sufficient capacity has been procured to cover anticipated peak demand until then. The Capacity Market has been criticised for allowing more polluting plant to stay on the system and for incentivising the use of polluting smaller diesel generators, as well as not doing as much as it could to incentivise demand-side management. With the operation of the market, it is unlikely that we will see blackouts caused by lack of supply in the next few years.
There is however a sticking point – in November 2018, the Capacity Market was suspended following a successful state-aid court case brought to the European Courts by Tempus Energy, who argued that the Capacity Market unfairly favoured conventional generation over demand-side and decentralised technologies through differing contract lengths. The main scheme is still suspended, though a one-year (T-1) capacity auction has been held for this winter to cover the gap. It is likely that this suspension will be solved one way or another – a judicial review is currently scheduled to begin on the 11 November, and if the UK leaves the EU on a no-deal Brexit, state-aid rules will cease to apply.
So, the near-term is looking relatively secure, but what about the longer-term? As we look further ahead into the 2020s there will be a need to ensure that remaining coal and older nuclear and gas-fired power stations are replaced. However, the principal concern is not whether we can build enough new capacity but how to ensure that capacity is low-carbon. We need to use all the technological solutions available to us – there is no single magic bullet to providing low-carbon electricity securely and cost-effectively. There will be a need for some flexible conventional gas-fired plant, together with demand-side response, storage systems and interconnection with other countries. All these technologies need to be used together to ensure that the British power system is reliable, low-carbon and cost effective.