Great Britain saw 80 hours of negative pricing in the first nine months of 2020 as instances of negative day ahead prices more than double across Europe.
This is compared with 2019, with levels of negative day ahead prices in 2020 – which came in at 0.8% of the time on average – also being typically three to four times higher than between 2015 and 2018, according to new research from EnAppSys.
It found that the lowest price in GB was -£38.80/MWh, recorded on 23 May 2020 at 15:30. On that occasion, prices fell dramatically due to high levels of renewables combined with low demand due to the COVID-19 lockdown.
Other European countries recorded more extreme negative pricing, with Belgium seeing prices of -€115.31/MWh (-£104.88/MWH) on 13 April and Germany seeing prices of -€83.94/MWh (-£76.34/MWh) for eight hours on 21 April.
Countries with high wind demand were particularly affected, with EnAppSys pointing to Ireland, Germany and Denmark as examples. Ireland – which includes both the Republic of Ireland and Northern Ireland – saw 36% of its overall energy demand covered by wind generation and negative prices for 4.2% of the time, significantly higher than the European average.
In fact, Ireland recorded 136 hours of negative prices over the period, with its lowest price coming in at -€41.09/MWh (-£37.37) on the 23rd May 2020, the same day GB recorded its lowest price. This came at 5:00 in the morning when wind exceeded demand.
The markets became “much more volatile” in 2020, according to Alena Nispel, business analyst at EnAppSys, due to the lower demand from COVID-19 lockdowns, higher volumes of renewables and increasing interconnection between markets.
One possible solution to this, however, is battery storage, with Nispel stating that it can act “to reduce these impacts – at least as far as it is economically sensible to do so”.
Providing more detail, Rob Lalor, director of EnAppSys, explained how as more renewables come onto the grid, increasing volatility, battery storage can shift “large volumes” of wind or solar away from peak output into other periods of the day by charging during peak periods and discharging later on.
However, Lalor went on to say: “When moving power from one period to another, storage assets need to move that power as cheaply as possible, taking into account the size and frequency of those shifts.
“There are economic limits imposed upon storage based on economic return per storage cycle and number of cycles/usages per year. The target is to pay off capital at a reasonable return whilst accounting for any costs of running or general operation. If the market allows multiple cycles/uses a day, this return can be achieved on smaller spreads than in a market that only allows a few cycles/uses per year.”
Other solutions cited by EnAppSys include technologies that can provide services without active power, reducing the generation required from conventional sources.
In particular, it pointed to the introduction of synchronous condensers in Britain, which provide inertia in an alternative to the traditional large generators.
“Replacing these power stations with an alternative such as a synchronous condenser – a motor that effectively still spins and provides inertia but without being attached to a generator – means that these plants can be switched off and more renewables can be accommodated in the market. This in turn acts to reduce instances of negative pricing,” Nispel said.
National Grid ESO awarded £328 million worth of contracts to six companies to provide inertia without generating power. Drax is already providing the service, with Welsh Power beginning work on its site last month.