Early winter outlook confims our reliance on interconnectors

As the country basks in a heatwave, National Grid ESO has published its early outlook for next winter (this is the third year it has issued an early outlook, and it has come out a month earlier than in the past two years). The base case spare margin has increased from 3.7 GW last winter to 4.8 GW for this winter (last year the early outlook expected the spare margin to be 4.0 GW but this was later reduced to 3.7 GW when the final outlook was published in November).

The Demand Flexibility Service (“DFS”) is going to continue because ESO believes it is “prudent” to do so, but the coal contingency may be finished – the two units at West Burton A have now closed and are being de-commissioned, the one unit at Ratcliffe has returned to normal commercial operations. The two units at Drax notionally closed at the end of March, but apparently there are ongoing discussions to retain them as a contingency for next year (something Drax itself denies saying it has already started to de-commission them). It’s possible Drax is trying to leverage its market power since the station is essential for grid stability in its region, and it would be challenging for the market to lose generating capacity of this size, but the real issue isn’t coal but its biomass subsidies which are at risk of being removed.

In any case, by law all coal power stations must close by the end of October 2024 ie will not be available next winter. It could be argued that NG ESO needs to learn to do without, although it would be better if the mandatory closure date was altered. The closure date was brought forward in 2020 when the Government said it would implement an emissions intensity limit of 450 gCO₂/kWh on the use of coal for electricity generation. The Government decided not to introduce emergency powers allowing the Secretary of State to suspend or modify the coal phase-out arrangements, something which now looks to have been short sighted. An impact assessment at the time had suggested there would be no security of supply risk associated with the early closure of coal plant.

The Government announced in June 2021 that it would introduce legislation to ensure the closure of coal power stations by 1 October 2024 “at the earliest opportunity”, but I have not been able to find the relevant legislation, so cannot comment on whether it did in the end include powers for the Secretary of State to delay the coal exit, or whether new legislation would be required.

Role of interconnectors: some of last year’s threats have retreated but fundamental risks remain

As with last year’s early outlook, the main headline is that interconnectors are expected to save the day if the GB market is tight. Last year, NG ESO had to move back from that position in its final winter outlook because the situations in both France and Norway were very tight. NG ESO assured us that Norwegian supplies would be secure despite worryingly low reservoir levels, and the fact that the French demand peaks and our occur at slightly different times meant the TSOs could juggle between themselves to ensure both Britain and France could receive imports from each other when needed. I remain unconvinced by that argument.

Norway’s reservoirs are looking healthier this year – water levels in the key NO2 region are just shy of the 20-year median where last year they were close to 20-year lows.

The situation in France has also eased, although it will take time to fully resolve the stress corrosion issue. While another three French reactors have opened since my last update in mid-March, and one is supposed to re-start today, three more remain off-line:

However, this is far from the end of the story. In April, French nuclear regulator, ASN approved EDF’s updated inspection and repair schedule following the additional defects discovered in March at Penly 1, Penly 2 and Cattenhom 3. EDF’s revised schedule provides for an acceleration of inspections of welds of the RIS (safety injection circuit to inject borated water in the event of a primary circuit failure) and RRA (cooling circuit used during reactor shutdowns) systems on which repairs had been necessary during the original construction of the reactors. EDF said 90% of the repaired welds it identified as a priority due to their repair conditions will be inspected before the end of 2023, with the remainder being reviewed by the end of Q1 2024. ASN has identified Nogent 1 and Curas 2 as particular priorities. EDF said it still expects output from its French nuclear power plants to be in the range 300-330 TWh in 2023.

This winter, RTE expects 28 of the country’s 56 reactors to be off-line at one point or another, with the largest concentration (as expected) at the beginning and end of the winter. Of course there is a risk that reactors with outages early in winter will have delayed returns to service, potentially leading to market tightness during the coldest months.

The French nuclear fleet is aging, and it is natural to expect its reliability to fall over time. Only one new reactor is under construction – the 1.6 GW Flamanville 3 – which might open in the first quarter of next year. French policy-makers are becoming increasingly concerned about a “cliff-edge” of reactor closures. The initial life expectations for these reactors was 40 years, although now EDF intends to keep them open for 50 or even 60 years.

If they begin to close after 50 years, the closures will begin before the end of this decade, with the loss of 3.6 GW before 2030 and 33.9 GW by the end of 2035. Even if life extensions to 60 years are authorised, it is inevitable that reliability and therefore availability will fall. With new EPRs taking at least a decade to deliver and no projects other than Flamanville 3 in the pipeline, the next new reactor is unlikely to open before 2035.

So while the initial impact of the stress corrosion problem has abated, there is a strong chance that other issues, whether systemic or affecting individual reactors, will reduce French nuclear output in future, and this will inevitably affect the availability of exports.

While the prospect of blackouts this winter may be lower than last, underlying risks are still growing

Last winter I was concerned about the reliance on interconnectors, and indeed, NG ESO moved away from this position ahead of the winter due to the issues in Norway and France, instead introducing the DFS and coal contingency. In its final winter outlook last year, NG ESO raised the prospect of blackouts due to a potential shortage of gas should the EU restrict interconnector exports due to gas market tightness in Europe.

This year, the specific issues in Norway and France have eased, and there is no mention in the early outlook of concerns over gas supplies. However, there are still threats to gas security should Europe be unable to re-fill its storage facilities before next winter. I was never particularly persuaded by NG ESO’s fears over gas supplies last winter, but it is interesting that this has been completely ignored in this year’s outlook.

Before last year I had been consistently warning that Britain was facing a capacity crunch in the middle of this decade, as conventional generation is progressively replaced with intermittent renewable generation, leading to weather related security of supply risks. With the exception of France and Norway, most of our neighbouring countries are, like us, following a strongly wind-led energy transition. These nearby countries also share similar weather to us, and there can be times when all of these countries experience low wind output at the same time. This was observed during last summer’s heatwave when for around six weeks wind output was depressed (along with lower hydro production) across much of northern Europe. The risk is that collectively these countries wish to import more electricity at any time than France and Norway have available to export, or imports are constrained by interconnector capacity.

Today’s generation mix is a good indicator of the problem – on a hot summer’s day there is little wind output and we are relying on imports. If anything were to put those imports at risk – eg similar low wind output in our connected markets, then things could get very tight, particularly in winter when there is minimal solar generation.

In Britain, the remaining 2 GW of coal plant is required to close before the start of Winter 2024-25 and two of the last five nuclear power stations (together 2.3 GW) are due to close at the end of Winter 2025-26. On the plus side, a new CCGT was awarded a capacity contract in this year’s T-4 auction and should open ahead of winter 2026-27.

I long have been concerned that the Capacity Market is not delivering enough new capacity to replace closing plant, particularly given the planned increases in demand due to electrification, a trend which is already underway with the expansion in electric car and heat pump use. These increases in demand will further stress the system, including in summer if people start to use heat pumps for cooling, creating demand for domestic air conditioning which is currently minimal. The strategy to manage this appears to be to rely on interconnectors and demand management.

As noted above, interconnectors might not be available when needed, and a reliance on interconnectors increases the concentration of risk since most of the interconnectors are large in capacity terms compared with a typical power station so an unplanned outage would have a bigger impact. And while there can be benefits to demand management, there can also be significant harms. Last winter saw some consumers going to great lengths to secure savings in the DFS, sitting in the cold and the dark to avoid electricity use, creating real welfare concerns. There are also economic consequences should businesses be required to turn down output in order to prevent blackouts.

There might be a smaller risk of blackouts this coming winter than last year, but the underlying risks inherent in our approach to the energy transition are still growing. The margin for error is reducing, and the risk that businesses will be forced to cut consumption in order to prevent a blackout is increasing year on year. NG ESO expects the spare capacity margin to be higher this winter than two years ago, largely based on new interconnectors having opened, but it de-rates these interconnectors using Capacity Market de-rating factors, which have never been tested in practice. And the Capacity Market rules only require interconnectors to be operating – there is nothing to prevent them from exporting during a system stress event, making the capacity issue worse.

NG ESO’s approach to managing security of supply through the energy transition seems to be highly theoretical, and fully take account of correlated risks. Indeed, as I have previously noted, ESO ignores the relationship between cold weather and still weather, using de-rating margins for wind based on average annual load factors, rather than average cold weather load factors which are likely to be much lower. It also says that it models the European power system when thinking about import availability, and while that is important, there’s a lot riding on those models being correct. Any modelling errors could have serious consequences, which may not become apparent until it is too late.

While I can understand NG ESO’s desire to re-assure the market, and give the Government confidence it can manage the grid through the transition to net zero, I would be happier if it gave a more comprehensive assessment of the risks we face and they way in which they overlap. I can’t help thinking that ESO is giving us all a false sense of security, and if its analysis is wrong – remembering that ESO’s analysis also underpins the Capacity Market and the amounts of capacity procured each year – there could be big trouble.