Today National Grid ESO has published its early view of the Winter Outlook for 2022/23. Unbelievably, it believes the capacity margin will be slightly higher than last year at 4.0 GW compared with 3.9 GW. This strikes me as extreme wishful thinking which does no-one any favours.
“Our current assessment indicates that we expect system margins to be broadly in line with recent winters. It shows that we expect there to be sufficient available capacity to meet demand, with a de-rated margin of 4.0 GW, equivalent to 6.7%,” – National Grid ESO
Looking at the detail (and unfortunately the data book has not been made available so far), it is clear that NG ESO expects to rely in interconnectors to meet peak winter demand which remains unchanged at 59.5 GW. I have no particular objection to demand being broadly flat, but I have a significant objection to the capacity margin improving when the past year has seen the loss of 2 GW of nuclear (Hunterston B and Hinkley Point B) and 2.1 GW of coal (1.6 GW of West Burton A and 500 MW at Ratcliffe).
NG ESO claims in its report that:
“Our Base Case assumes normal market conditions. this means that we assume there is no disruption to fuel supplies for thermal power stations and that electricity interconnectors between Great Britain and Europe continue to operate in response to market signals, including scarcity prices, as they have done in previous winters.
We assume that interconnectors are able to provide 5.7 GW net imports at times when GB needs it. This is consistent with their Capacity Market obligations. Our Base Case assumes 2.7 GW additional interconnector capacity that was not available last winter. This includes Eleclink which is now operational, and both IFA and NSL operating at full capacity.
There is uncertainty on the availability of the French nuclear fleet for winter. This could lead to more export flows from Great Britain to France when our system margins are not tight. We are continuing to monitor the outlook in France and will undertake further assessments ahead of the Winter Outlook Report in the autumn.”
Following a fire at Sellindge last year, the capacity on IFA-1 continues to be reduced. The latest REMIT disclosures indicate capacity will remain at 1 GW until 30 October when it will increase to 1.5 GW. There is currently no date given for a full return to service although there have been reports that it may not be until October 2023. NG ESO’s claim that it will be fully available therefore conflicts with the REMIT notices and needs to be challenged: asset operators are required to inform the market promptly of expected changes to their availability, and not to share these with third parties before informing the market.
This means that if we are guided by the publicly available information about IFA-1, the available interconnector capacity on a nameplate basis is 2.2 GW higher than last year for the majority of the winter (500 MW on IFA-1, 700 MW on NSL which was only operating at 50% capacity last winter, and 1,000 MW on Eleclink which was not operational last year), and not 2.7 GW. However, the behaviour of these interconnectors is likely to be markedly different.
“If you look at the forward prices, French winter prices are above GB winter prices. So I would be concerned that it’s not necessarily the case that we would be able to get what we need,” – Thomas Edwards, senior modelling consultant, Cornwall Insight
It does not appear that NG ESO has adjusted the de-rating factors for the interconnectors despite obviously different market conditions.
France is now consistently importing from GB as a result of the problems with the nuclear fleet, and forward prices indicate that exports from Britain to France will continue this winter. Since France has more electric heating than Britain, its electricity demand increases faster when temperatures drop – it is likely that at times of high demand in Britain there will be higher demand in France. Assuming that the full import capacity will be available whenever Britain needs it seems extremely ambitious, and the reliability of interconnector provision under the Capacity Market has never been tested in practice – if it turns out not be possible to switch from export to import mode, then the payment of penalties will be of little comfort if blackouts result.
The situation in Norway is also a cause for concern. Statnett has declared the situation in south Norway (NO2) – the region from which the country exports – to be “pressed” with the reservoir filling rate at its lowest for the last 20 years with only 48.3% against the median rate for week 29 for 2002 to 2021 of 72.8%. East Norway (NO1) also has a historically low filling rate for week 29 of 66.6% versus a median of 79.8%. Reservoir levels are at their lowest since 1996 and there is growing talk of potential electricity rationing – Statnett has predicted a 5-20% chance of electricity rationing this winter, and has announced that Norway is likely to have a higher than normal reliance on imports this winter but that businesses should prepare for situations where “access to imports are lower than usual”.
Norway is unusual in that it has a “stock” of electricity in the form of its hydro reserves that are available for use. Interconnector flows are based on short-term price differentials, and do not account for the possibility that using this stock now means it may not be available later when needed. There are press reports that the government is considering its options to restrict exports.
“Restrictions on the export of electricity to Europe may be one of the measures that is needed,” – Elisabeth Sæther, state secretary at the Ministry of Oil and Energy
This sounds drastic, but it would actually be in Europe and the UK’s best interest. Norway has electrified a significant portion of its offshore gas production infrastructure, and according to Equinor, can no longer revert to conventional fossil-fuel power. This means that if there are electricity shortages in the south of Norway, gas production including from the giant Troll field which supplies the UK, could be disrupted.
In addition to its (heroic) assumptions on interconnectors, we can see the following differences since last year’s outlook:
Thermal generation has increased
Renewable generation has increased significantly
Storage has more than doubled
“Other” has collapsed
Without the data book it is difficult to analyse these effects, particularly why the “other” category, which last year included demand-side response and embedded generation has fallen so much. One possible explanation is that thermal embedded generation has been re-categorised into the Thermal category (last year’s data book had a category called “Other embedded generation”, if this was primarily thermal that could account for some of the difference. The de-rated capacity of that category was 11.4 GW). The Thermal category does not include the standby deals done with EDF for West Burton A or Drax, so presumably the total excludes the full 3.4 GW capacity of these plants.
I have asked NG ESO if it can explain these differences more fully and will update this post if I receive any new information.
“National Grid is assuming that interconnectors behave by market rules. We believe this is a risky position to take. EnAppSys analysis suggests that the French Interconnectors (up to 4 GW) may be unreliable importers into GB in the winter. This is due to the problems with the nuclear fleet in France and the high price of gas on the continent due to the war in Ukraine and the well-documented issues with gas from Russia,” – Phil Hewitt, director at EnApSyss
If National Grid has not adjusted its assumptions on import levels in light of the market changes described above, then it is seriously mis-leading the market as to the true picture this winter. It seems beyond wishful thinking to believe our winter capacity margin this year will be higher than last.