Q4 2018: What to expect in 2019Download PDF
by Dr Iain Staffell – Imperial College London
The New Year brings new challenges to Britain’s power system.
The capacity market was unexpectedly suspended, new low-carbon capacity has stalled and no-deal Brexit may disrupt carbon prices and the operation of interconnectors.
After a legal challenge by Tempus Energy (a smart grid start-up)1, the European Court of Justice brought the UK’s capacity market to a standstill in November2, suspending £1 billion per year worth of capacity payments. These were supposed to go to generators and flexible consumers for ensuring availability at times of peak demand, leaving many firms in the electricity market with a hole in their finances. The UK Government believes this will not impact security of supply this winter3, and analysts agree that the effects won’t be felt until this year. Some older power stations may resort to closing early on financial grounds4. This would lead to tighter supply margins, giving higher and more volatile prices next winter, possibly offsetting any reduction in consumer bills that would come from halting the capacity payments.
In the space of three months, Toshiba and Hitachi have shelved plans to build 9 GW of new nuclear reactors. Their combined capacity would have been sufficient to replace Britain’s entire fleet of aging nuclear reactors. Toshiba is closing its UK nuclear business after it failed to find a buyer for NuGen, and so “the economically rational decision is to withdraw from the UK nuclear power plant construction project”5. Hitachi have formally suspended investment into nuclear stations at Wylfa Newydd in Anglesey and Oldbury in Gloucestershire, describing them as “incompatible with the company’s economic rationality”.6
Unless new partners or financing deals can be found, these announcements place a 9 GW hole in the amount of low-carbon capacity that will be available in the coming decade. One view is that this collapse “should be seen as an opportunity rather than a risk, for the UK to prioritise renewables instead”7. However, the growth in wind and solar capacity has slowed down dramatically. In the last twelve months, fewer wind and solar projects were built than at any time since 2010 (see chart below). The government believes this slump will continue into the next decade.8
New solar PV and wind capacity installed in each calendar year
Finally, Brexit is just weeks away and will potentially have the biggest impact on Britain’s power system. If the UK leaves with no deal it will leave the Emissions Trading Scheme, the EU-wide market which puts a price on carbon. Government plans to replace this with a carbon tax of £16 per tonne, which would start in April 2019.9 However, the European Commission has already suspended Britain’s access to ETS carbon permits in an effort to limit disruption to the scheme.10 This leaves a potential gap from January through to March 2019, where Britain has no underlying carbon price, and so power stations are only subject to the Carbon Price Support.11
Until Britain’s relationship with the European Union is known, it is unclear what price fossil-fuelled power stations should be paying for carbon emissions during Quarter 1: around £40 if there is a deal (ETS plus CPS) or £18 if there is no deal (CPS only). Based on emissions during Q1 of 2018, this difference could amount to £450 million for Britain’s coal and gas power stations.12 If generators anticipate lower carbon prices, coal could make a comeback at the start of the year. Britain may also become a net exporter of electricity, including over the new interconnector to Belgium, as British generators will face lower carbon prices than those on the continent for the first time in five years.
However, those interconnectors may not be used as efficiently as they are today. Power flows over Britain’s interconnectors would go from being automatic to being decided by traders.13 At present, power implicitly flows from low- to high-priced countries: “buy cheap, sell dear”. While this would be the aim of traders, they are not perfect, and the loss of efficiency is expected to add “a couple of percent” onto the cost of generation.14This may, of course, be lost in the noise of currency fluctuations, which affect the cost of imported coal, gas and electricity. Sterling is widely forecast to move by 10% either way against the euro and dollar, depending on how smooth the transition is.15
All in all, don’t expect 2019 to be a quiet year for Britain’s power system.
2: Tempus argued that the scheme privileges generation over demand side response (DSR) due to the duration of contracts offered (up to 15 years, versus 1 year) and the means of cost recovery for DSR (all weekday winter evenings, rather than the specific periods of highest demand).
11: The Carbon Price Support of £18 per tonne of CO2 is levied on British power stations on top of the ETS (or carbon tax).
12: If Britain’s coal and gas stations emitted 20.5 million tonnes of CO2 (as they did in Q1 2018), they could expect to pay £370m for the Carbon Price Support (under no-deal), or £820 million if we stay in the ETS based on permit prices of £22 per tonne (the average during January 2019).
14: http://www.ukerc.ac.uk/news/elecxit-could-cost-270-million-a-year.html, Chatham House: Brexit – Deal or No Deal (25th January 2019)
15: https://www.telegraph.co.uk/financial-services/currency-exchange/international-money-transfers/pound-forecast-post-brexit/, https://www.theweek.co.uk/98984/what-the-brexit-vote-could-mean-for-sterling