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Low wind and high demand squeeze the GB power market
There are signs of squeezed power market supply and demand margins. Last week saw National Grid ESO issue two Electricity Margin Notices (the new name for the Notice of Inadequate System Margin, or “NISM”), warning of a potential shortfall in electricity generation in the GB market, and encouraging more generation onto the system. The last time such an alert was sent out was in May 2016, but September saw the first Capacity Market Notice since late 2016.
Both of these instances saw low wind generation – not an unusual situation during cold winter high pressure weather systems – think of all those clear, cold and above all still, frosty days. They were also characterised by the use of coal to meet demand.
The first Electricity Margin Notice was issued just after 8pm on Tuesday last week (3 November), when a 740 MW shortfall was predicted between 4.30-6.30pm on Wednesday. An update was released at 10am on Wednesday stating that the shortfall had dropped to 477 MW and shortly after 1pm the alert was withdrawn, indicating that sufficient new generation had been attracted into the market.
However, 7 hours later, a second notice was issued for the same time period on Thursday evening, this time predicting a 466 MW shortfall. This was revised down to 316 MW by Thursday morning, and withdrawn at 2pm that afternoon.
According to the Energy and Climate Intelligence Unit, the predicted deficit for Wednesday was partly the result of the series of outages: three nuclear power stations were offline (Hinkley Point B, Heysham 1, and Dungeness B), as well as five CCGTs (Carrington, Fawley, Pembroke, Kings Lynn and Coryton) and the Drax biomass plant. There was also a partial outage at the East Anglia One offshore windfarm, while imports via interconnectors were expected to be low due to reduced nuclear output in France. Coal plant fired up to meet the shortfalls.
Although National Grid ESO emphasised that the expected shortfalls did not take account of its reserves – meaning blackouts were unlikely – various market observers suggested otherwise.
“The actual impact of those very high winds earlier on in the week was that we saw something which we very rarely see in the UK power market – negative pricing. You’re in that position then all of a sudden you had this drop off in wind, and wind power output was less than forecast. And then temperatures dropped. We had a mini anti-cyclone over the UK so that’s when you get stone cold temperatures and no wind at all, which is when we always see these big price spikes. And the fact that wind power had been asked to switch off just a day before or so would have meant there wasn’t as much generation which was ready and running as you would normally expect,” – Jamie Stewart, managing editor for energy at ICIS
The situation was compounded by uncertainty over the levels of demand as the UK began its second national lockdown – unlike in the first lockdown in the Spring, the new lockdown began as the country experienced its first proper cold spell of the winter with most parts of the country seeing night-time frosts, meaning people working from home would be using more heating. And with sunset in the South of England now at 4:30pm, much more lighting is also needed.
Will it happen again?
The excess wind power at the start of the week pushed power prices into negative territory, creating a dis-incentive for generators to begin ramping ahead of the predicted demand uptick. Jonathan Marshall, of the Energy and Climate Intelligence Unit told The Times newspaper that the warnings showed that “the rapid transition in Britain’s electricity system is outpacing the changes in governance and regulation needed” to encourage the emergence of more flexible technologies such as batteries which would have allowed the excess wind power available from the storms earlier in the week to have been stored for later use when wind levels and temperatures both fell.
While National Grid ESO emphasised that low wind output was only one factor causing the alerts, it acknowledged that balancing the grid is becoming increasingly complex as more intermittent generation is brought online. More than 10,000 wind turbines now operate in the GB market with a theoretical maximum output of 24 GW. Over a typical year, their output averages about third of that level, equivalent to the annual energy needs of 18 million homes. However, there have been times this winter when wind has produced barely a tenth of its potential output, below the 16% assumed in NG ESO’s winter planning, and once again, coal is ramping up to fill the gap.
Of course, in a net zero carbon world, there will be no coal around – the UK is committed to closing its remaining coal plant by October 2024. The Capacity Market was designed to incentivise new generation to replace exiting coal and aging gas and nuclear plant, but so far the most successful technologies in the Capacity Market have been small-scale gas and diesel engines, which are also incompatible with a zero-carbon world.
While system margins now look better with the warmer weather, more shortages are likely through the winter, particularly with two large CCGTS, Severn (850 MW) and Sutton Bridge (850 MW), being essentially mothballed last summer when their operator, Calon Energy, went into administration. The Severn plant was only commissioned in 2010, indicating that even relatively new and efficient gas plant is struggling to remain economic
“This doesn’t seem to be a one-off. These shortage events look increasingly common in the market and should be expected to continue throughout the winter. The loss of Calon in such a manner – during a period when the market is seeing these tight margins – raises the question of whether the capacity mechanism has sufficiently ensured that plants will be able to make up the ‘missing money’ that results from plants having to meet the proportion of demand that is not met by renewables and other subsidised generation, whilst stepping aside during periods when renewable output levels are strong.” – Paul Verrill, director of EnAppSys
The four-year ahead nature of the Capacity Market auctions means that operators must estimate years in advance what additional income they require from the Capacity Market in order to be economic, but four years is a long time in a rapidly changing market. While there are penalties for non-delivery, if an operator falls into insolvency, or even if they pay the penalty, the market will still be short and need to find the missing capacity from elsewhere, which may well be at higher prices.
Capacity Market Notice issued in September
September also saw some tight capacity margins, spiking prices and the first Capacity Market Notice since Q4 2016 issued on 15 September.
A capacity market notice can be issued for one of three reasons:
The System Operator gives a Demand Reduction Instruction or an Emergency Manual Disconnection Instruction to one or more DNOs
An Inadequate System Margin is forecast (at least 4 hours in the future)
Automatic Low Frequency Demand Disconnection takes place
In this case rule 2 was satisfied.
After an instruction is issued, generators holding a Capacity Market contract must be ready to generate during the time the short fall is forecast to occur (assuming they are not performing any other ancillary services). Other market participants not holding capacity contracts can also react to the market conditions and capitalise on the high market prices and volatility that are likely to coincide with the shortfall.
The Notice was cancelled when National Grid ESO was able to reverse the scheduled flows on the interconnectors, primarily with France. After the Day Ahead auctions, GB was set to export electricity to the Continent, but NG ESO was able to secure imports, primarily from France but also from the Netherlands and Belgium, using bilateral contracts. This supplied an additional 2 GW to the system, easing pressure on margins. NG ESO’s trades were at prices of up to £607.57 /MWh with these high price levels filtering through into the cash-out price.
The charts below indicate the generation mix and demand during September, and the within day and cash-out prices for the month:
On the 15 September, prices spiked, with the system price reaching over £500 /MWh against a backdrop of high demand alongside low wind generation across northern Europe, which limited electricity available for import as well as creating a domestic shortfall. High prices were seen across Europe, with hourly prices of over €1,100 /MWh in Belgium and almost €4,000 /MWh in quarter-hourly trading in Germany.
“The biggest issue was that all of Western Europe had the same problem. This meant that, whereas countries would normally trade across the interconnectors to solve their issues, this was not really an option yesterday. This shows again how important it is to look at the European power market as an interconnected and interdependent system. The interconnectors can solve problems, but they also allow the problems of other markets to seep through to neighbours,” – Jean-Peal Harreman, director of energy market data analyst EnAppSys BV
The chart also shows that coal ran multiple times during the month to meet rising demand, at times making up 7.6% of all generation.
A combination of never-ending subsidies and tight margins spell bad news for consumers
The failure of Calon and the ongoing difficulties of attracting new large gas plant into the Capacity Market indicate that the move away from market-based to subsidy-driven mechanisms is undermining both existing and new conventional generation.
Since the inception of the Energy Market Reform in 2013, successive governments have determined that consumers should subsidise specific renewable technologies in order to reduce the consumption of fossil fuels and hence reduce carbon emissions. However, in so doing, the economics for conventional generation were undermined, and so the Capacity Market was created in order to provide support, primarily to gas plant. Unfortunately, even with the Capacity Market, very little new large gas plant has been brought forward, and low utilisation rates mean the economics remain under pressure.
SSE’s 840 MW Keadby plant is one of the few new CCGTs being built in the UK and is on track for commissioning in 2022, with a gas turbine weighing as much as an Airbus A-380 arriving on-site from Germany in June. The plant secured a capacity contract in the 2023/24 capacity auction which took place in March this year.
“I don’t think it will be the last traditional gas plant we build but it will be the last one that doesn’t have carbon capture or hydrogen involved with it,” – Alistair Phillips-Davies, chief executive officer of SSE
Now there are ambitions plans for new gas generation powered by hydrogen, but this will require even more subsidies both for the power stations and for the carbon capture that is likely to be required in the production of carbon-free hydrogen.
Consumers are getting the worst of both worlds, paying a high price for the subsidies that currently support almost every form of generation currently on the system, while periods of tight margins see spikes in wholesale prices. And at the other end of the spectrum, periods of low demand and high renewables output as were seen in the Spring lockdown – widely considered a sign of the future of the markets – saw balancing costs triple.
And all the while, despite the talk of de-carbonising not just the electricity system but the whole economy, we still turn to coal to keep the lights on.