Ever since I began my blog I have been warning about falling winter capacity margins and the risks to security of supply in the British electricity market. There are compelling reasons why this winter may see these concerns crystallise into real risks to energy supplies, particularly to industrial consumers who are increasingly worried about involuntary curtailment in order to protect supplies to the domestic market.
Winter capacity margins have been in steady decline in recent years. The reason for this is the closure of conventional generation: coal plant has been steadily retiring due to old age and in anticipation of the statutory closure deadline of October 2024. Less efficient gas plant has been closing, and there are two more modern power stations in a state of preservation following the bankruptcy of their operator. Finally, nuclear retirements and lower availability are beginning to bite as the fleet ages.
Last winter the capacity margin was just 3.9 GW. Nuclear availability was assumed to be the average of the past 3 years – possibly a bit optimistic for an end-of-life fleet, and the net interconnector imports at peak demand were assumed to be 4.2 GW.
There are four ways in which the capacity margin for this coming winter will be different from last year:
The first is that around 4 GW of coal plant is set to close by September this year:
2 GW West Burton A plant
Last two coal units at Drax with a combined capacity of 1.4 GW
One 500 MW unit at Ratcliffe
The second is that almost 2 GW of nuclear capacity is due to close this year. The Government has reportedly asked EDF to consider keeping Hinkley Point B open, but this may not be feasible since the closure was motivated by age and safety reasons.
The third is that the situation with the French nuclear fleet may mean we switch from importing electricity from France to exporting to France.
And the fourth is that the Norwegian electricity commission might restrict Norwegian electricity exports.
Currently around half of the nuclear reactors in France are offline following the identification of defects in the pipes that make up the cooling systems of the reactors. These faults have been identified as part of routine maintenance and EDF is now having to undertake widespread inspections. This is having a significant impact on power flows in Europe, with Britain now routinely exporting to France.
This first chart shows daily net interconnector flows to the GB market since 2017, excluding 2020 and 2021 which were abnormal due to covid. As you can see, GB typically imports electricity, but the past few weeks have seen a jump in exports with GB becoming a net exporter more often than not.
If we exclude imports from Norway, that trend is even more clear.
Last year, Norway opened two 1.4 GW interconnectors, one with Britain and the other with Germany. Since then, power prices in the south of Norway have risen by a factor of ten with the Government now subsidising end users to the tune of 80% of their bills. The country is now facing record low hydrological levels and so far the year is proving to be dry, so the water reserves are not being replaced as expected.
The unusually high prices and concerns over hydro levels have become politically contentious, so the government has instituted an energy commission that is due to report in December. It is clear that both Germany and Britain are treating imports in general as a substitute for domestic generation capacity (and in the case of Germany, also as a substitute for domestic transmission capacity) to the detriment of their neighbours. In part this is due to mis-conceptions about the Norwegian power system – even senior executives at National Grid are on the record as saying that Norway can import cheap wind energy to pump water and restore hydro levels, but this is not possible in practice.
Norway has 33 GW of installed hydro capacity but only 1.4 GW of that has pumping capabilities, and some of those sites are limited to seasonal pumping since the pumps have complex coupling requirements. It is actually not possible for Norway to restore its hydro levels by pumping – the best it can do is use imports to displace discharges from its reservoirs. But if cheap imports are available at night when domestic demand is low, that will be of limited benefit.
So I believe that it is entirely possible that Norway will impose restrictions on electricity exports. This would be my advice to the Norwegian government since there is no justification for Norwegian citizens to face record high electricity prices due to the policy choices of other countries. Of course, some may argue that Norway has signed agreements that would prevent this, but against a backdrop of Europe’s growing reliance on Norwegian gas, I believe Norway has more than enough market power to impose any restrictions it chooses on electricity exports.
The final sign of trouble for this winter is that the T-1 capacity auction had a shortfall of 365 MW ie less electricity was procured than the Government had targeted. Since the target was set at the level of capacity that pre-qualified for the auction it may be the case that the Government would have set it higher if it could. On top of this, a quarter of the capacity was awarded to assets that had not yet been built, introducing significant delivery risk.
Putting all of this together it is entirely possible that capacity margins this winter will be around zero leaving the system extremely vulnerable to unplanned outages. I’m hearing that large industrial users are very worried they will be required to reduce consumption in order to protect supplies to the domestic market, and my analysis indicates that these concerns are entirely reasonable. A sensible strategy at this point would be for these consumers to secure back-up diesel generation and fuel supplies, and explore ways of shifting production to times of lower demand such as at night and during weekends, although not all businesses would have that degree of flexibility.
Government has apparently reached out to the operators of the remaining coal power stations to remain open this winter, as well as Hinkley Point B. It could also reach out to the owners to the two mothballed Calon CCGTs to being those assets back into the market. Re-opening the T-1 capacity auction might be a mechanism for incentivising these assets and others to provide additional capacity to the market.
It will be interesting to see how National Grid ESO assesses the capacity margins for next winter. It must be hoping for an early resolution of the French nuclear problems, because being a net electricity exporter in winter will have serious consequences for capacity margins. Longer-term, it is essential that policymakers remember that all facets of the energy trilemma: security of supply and affordability as well as de-carbonisation, are appropriately balanced. The new focus on nuclear power is positive if the right choices are made (ie not relying on the troubled EPR technology) but it seems increasingly inevitable that we will need to shore up our fossil-fuel generation base, firstly by keeping the coal plants operational longer, and ideally at least until Hinkley Point C opens, and secondly by ensuring adequate gas generation capacity. We are rapidly running out of options, and if action is not taken soon, there may be no choice other than to commit to more CCGTs in order to guarantee security of electricity supplies over the medium term.