NG ESO’s winter outlook still understates risks and focuses on demand reduction

Today, National Grid ESO published its Winter Outlook for 2022/23, updating its position since the early outlook issued in July, which was widely seen as unrealistic. The position in July was that a capacity margin of 4.0 GW was expected, a small increase on 3.9 GW last year. While the final outlook does revise the figure downwards slightly, at 3.7 GW (6.3%) it still looks very optimistic. The Average Cold Spell (“ACS”) demand is assessed a little lower than in the early outlook at 58.3 GW versus 59.5 GW.

Unlike the early outlook which relied on interconnectors, NG ESO appears to now be relying on new tools it has developed to manage risk capacity risks – the coal contingency contracts and, in particular, demand reduction including the new Demand Flexibility Service though which businesses and households can be paid to move their demand out of peak hours.

NG ESO claims to have secured three contracts with coal generators “to keep 5 coal units open and on standby this winter to generate up to approximately 2 GW of additional power” – this is misleading…I asked EDF outright about the situation at West Burton A, and it confirmed that it has only agreed to make 1 unit available at any time, and then only at 80% of capacity. It would be more accurate to say that these contracts deliver 4 units at 1.9 GW (one 500 MW unit at Ratcliffe, two 500 MW units at Drax and one 500 MW unit at West Burton A operating at 80% capacity ie 400 MW).

The Demand Flexibility Service is projected by NG ESO to reduce demand by up to 2 GW, however, I have heard from industry sources that there is unlikely to be much take-up from the domestic sector since the prices offered are considered to be too low. It is also a day-ahead service that can only be accessed by households which have a functioning smart meter and act through their supplier or an aggregator. I do, however, believe that the public would respond well to voluntary demand reductions / load shifting requests should a system stress event occur, providing the required actions are appropriately communicated.

Winter outlook ignores the risks of low wind and is over-optimistic about imports

Another problem with NG ESO’s base case is that it assumes capacity across all providers (generation, storage, interconnection etc.) is available in line with Capacity Market commitments. This is likely to be optimistic for two reasons: not de-rating wind capacity enough and over-estimating imports.

The winter outlook models the capacity available to meet ACS demand. It would therefore make sense to consider the generation that is likely to be available during cold weather rather than the generation that is available on average through the year. There can be a high correlation between cold weather and still weather, so the de-rating factors used for wind in the Capacity Market which considers annual averages may be too high.

The Capacity Market de-rating factors for wind are 16.1% for both on-shore and off-shore wind (compared with 17.4% last year). However reducing this to 5% would cut de-rated capacity by just under 3 GW, and a reduction to 1% would be a reduction of more than 4 GW. On still days, wind output can be as low as 1% of installed capacity, so this is not an unrealistic scenario – low wind conditions can easily destroy the capacity margin.

In addition, the Capacity Market rules only require interconnectors to be available, they do not require them to be importing. An interconnector could meet its Capacity Market obligations whilst in export mode.

The risk of exports is high, since France has been consistently importing from GB since April when the corrosion problems with its reactors was first identified, and French grid operator RTE expects imports to continue through the winter (see below). In Norway, the Government is developing a mechanism whereby electricity exports would be restricted if reservoir levels are too low (see below), so there is no guarantee imports to GB would be available when needed.

NG ESO has considered a more pessimistic scenario which reflects lower import potential (no imports from France, the Netherlands or Belgium; but the full 1.4 GW of imports possible from Norway; and 0.4 GW exports to Northern Ireland & Ireland). It says that in this “hypothetical alternative scenario” it would deploy the reserved coal units and activate the Demand Flexibility Service. It believes the 4.0 GW available by these means would cover any import shortfall, with a spare margin of 3.3 GW. I would argue that imports from Norway are more at risk than those from the Netherlands and Belgium.

The Demand Flexibility Service will launch on 1 November – NG ESO sees particular potential from commercial organisations who can load shift, and says it has had positive feedback from businesses on the service.

“Without the deployment of the additional coal generation units or the new Demand Flexibility Service, the ESO would expect to see a reduction in margins. In this scenario on days when it was cold (therefore likely high demand), with low levels of wind (reduced available generation), there may be the potential to need to interrupt supply to some customers for limited periods of time in a managed and controlled manner. However, the ESO expects the mitigations outlined above to be effective,”
– National Grid ESO

NG ESO also recognises that an escalation of the situation in Europe affecting gas supplies to GB – a situation it considers unlikely – would further erode supply margins, potentially leading to supply interruptions for short periods. This has caught the media’s attention today and I have done multiple interviews on the subject of whether rolling blackouts are likely this winter. In my opinion, they are not, before we would encounter blackouts, there are various measures that would be taken:

• Voluntary, compensated, demand reductions by businesses and households
• Mandatory demand reductions by businesses
• Appeals for unpaid voluntary demand reductions from households

This last measure could be very effective if properly communicated. However, this is not a desirable way to run the electricity system – it is important to recognise the risks and manage them proactively, ahead of time, rather than relying on short-term demand reduction to avoid blackouts.

Norwegian government developing measures to link electricity exports to reservoir levels

NG ESO appears to believe there are no risks to imports from Norway. However, the Norwegian government has announced measures that would restrict exports if reservoir levels were too low. The details of the scheme are yet to be announced, but the intent is clear.

On the 19 September, the Norwegian Parliament was recalled from its summer recess to debate the energy crisis. The Energy and Petroleum Minister Terje Aasland gave a speech in which he outlined various measures the Government is implementing to address the current energy crisis in the country where prices have soared over the past year. These include:

• A reduction in the electricity tax for 2022
• An increase in the electricity subsidy scheme for households to provide up to 90% relief on bills from 1 September (up from 80% last year). A typical family in southern Norway will now receive an electricity subsidy of around NOK 45,600 (£3,830) this year
• A mandatory reporting scheme for large hydropower producers to support security of supply, with producers being asked to hold back the water
• A new management mechanism to ensure more water is saved when reservoir levels are low and that the export of power in such cases is limited
• Market reforms to facilitate a simpler end-user market for electricity with better fixed price agreements that can provide greater predictability
• Increased measures to support households in reducing energy use or producing their own energy, and the government will make it easier for commercial buildings and housing associations to install rooftop solar panels
• Up to NOK 10 billion (£0.84 billion) of Statnett’s additional income will be used to prevent a significant increase network costs in southern Norway
• A business support package worth NOK 3 billion (£ billion) to help power-intensive companies, and contribute to reductions in energy consumption through energy management systems, insulation and installation of solar panels. Businesses are also being encouraged to switch to fixed price contracts. (Interestingly, unlike the business support package in the UK, the Norwegian scheme prevents recipients from paying dividends next year.)

The details of the hydro management mechanism are due to be published this autumn. Low hydro levels in the south of the country continue to be a cause for concern – in NO2 levels continue to hover around the 20-year minimum, and so far, the autumn is proving to be dry. At this time of year, both higher rainfall and snow in the mountains which quickly melts can boost reservoir levels by around 10% before snow begins to settle in mid-November, but so far this is not happening at the usual rate.

“Rationing has also been mentioned as a possibility in Norway. It is nevertheless important to say that our energy authorities consider the probability to be low, but that underlines the seriousness…In the long term, there are only three measures that can really improve the situation in the Norwegian power supply – more power, more networks and more efficient use of our energy.

These are measures that prepare the ground for a green reindustrialisation of Norway and are leading the way for the government’s energy policy. In the short term, the government’s priority is to continue the work to protect and relieve people, organizations and businesses in the demanding situation. In 2022, we will spend around NOK 44 billion. on targeted measures to help cover the high electricity costs,”
– Terje Aasland, Norwegian Energy and Petroleum Minister

There have only been two years in the past three decades in which there has been less rainfall than this year: 2003 and 1996 in southern Norway, and 1996 and 1991 in eastern Norway. There has been unusually low rainfall since the autumn of 2021, which has led to very low groundwater and water levels.

At the same time, hydro levels in the north of the country are at record high levels, with low prices and abundant water making it difficult to optimise hydro plant operation. But the lack of north-south transmission capacity means that this surplus cannot be used in the more densely populated south of the country. With plans for electrification, it is expected that these surpluses will be eliminated in the coming years without the need for additional transmission infrastructure.

It was interesting that Aasland referred to decisions in other countries that are harming Norwegian interests such as the closure (or potential closure) of nuclear power plants in certain EU countries. Although Germany has now decided to keep two of its three remaining nuclear power stations open beyond the year-end closure date, the other will still close, as will the Doel 3 reactor in Belgium which is closing as part of that country’s nuclear exit plan (an action which has attracted local protests due to the energy crisis).

French grid operator expects to rely on imports this winter

Back in April EDF discovered corrosion problems in the cooling circuits of its P4 and N4 reactors, and was required by the French nuclear regulator, Autorité de Sûreté Nucléaire (“ASN”) to take them offline for inspection and repair. Since then, France has switched from being a net exporter to net importer of electricity, including from GB.

EDF has identified the pipework being most susceptible to the cracking – in the N4 reactors, these are in the safety injection circuit located in the “cold leg” (the pipes of the main primary circuit which go from the motor pump units to the reactor vessel) and in the pump lines of the shutdown reactor cooling circuit. In the P4 reactors, it is the pipelines of just the injection circuit located in the cold leg. In late July, ASN approved a three-year programme presented by EDF for rectifying the problems.

“As you know, 32 reactors are shut down, some for stress corrosion and others for routine maintenance. EDF has undertaken to restart all the reactors this winter. We are monitoring the situation closely with weekly updates and we are being especially vigilant to ensure that this schedule is kept,”
– Agnès Pannier-Runacher, Minister of Energy Transition

EDF has committed to re-starting all of its reactors this winter, with the French government pressurising it to maintain its timetable. According to EDF’s projected schedule, 27 reactors will restart by the end of December, with a further 5 starting between early January and mid-February 2023. This will return all 32 of the currently closed reactors to service, however the ultimate decisions rest with ASN.

Industry insiders question the company’s ability to meet these targets, particularly for the 12 reactors closed due to the corrosion problems. Repairing them requires long and complex processes, and the President of ASN, Bernard Doroszczuk, has warned that other problems may be detected, leading to the further closures. Some contractors working on the repairs have apparently agreed to relax their rules on radiation exposure limits to allow workers to spend more time on the job, although these times will still be well within legal standards.

In its winter outlook, French grid operator RTE said it expects to ask households, businesses and local governments to reduce energy consumption several times over the winter months, to avoid rotating power cuts although it does not expect any total blackouts. The risk of power cuts could be minimised by reducing electricity demand by 1% to 5% in most cases, but reductions of up to 15% could be needed in the worst weather situations, particularly between 8 am and 1 pm, and from 6 pm to 8 pm, on weekdays. There are also supply risks in the autumn due to the low availability of hydroelectric power – 33 TWh compared with an average of 43 TWh in previous years.

“If winter is mild, you probably won’t hear from us. If the winter is very cold, the likelihood is for about 10 red EcoWatt alerts,”
 – Xavier Piechaczyk, Chairman, RTE

RTE presented three scenarios:

• In the best case scenario, nuclear reactors will quickly restart and reach 82% capacity by January 2023. This case also requires European gas markets to encounter little to no pressure, or for consumption to be strongly reduced;
• In the base and most likely scenario, about 75% of France’s nuclear capacity will be available in January, requiring significant electricity imports, with demand reductions also potentially needed, albeit in small amounts. In the event of very cold weather, temporary or localised cuts in electricity would need to be made;
• In the worst-case scenario, with both gas and nuclear shortages, power cuts would be “unavoidable if consumption does not decrease” even if the winter is mild.

To avoid full blackouts, RTE has said it can activate contracts allowing it to disconnect large electricity users, reduce voltage on the grid for a few hours, and implement rotating power cuts of up to two hours. The grid operator believes that the most extreme situations would require an unlikely combination of factors including very cold weather, a fuel shortage limiting the use of gas-fired plant and electricity imports, or very deteriorated nuclear output. In the worst-case scenario, the demand reduction alert known as “EcoWatt” could be used on 20 to 30 days during the winter.

RTE’s scenarios are closely linked to the availability of gas which is increasingly used for electricity generation in France. Gas use in the French power sector doubled in the first half of 2021 (to 24 TWh), and again in the second half of 2022 to reach about 39 TWh, according to gas network operators GRTGaz and Teréga who estimate that in a hard winter, the availability of gas could fall by 2.0% – 4.7%. A mild winter would be unlikely to affect gas supplies.

This has led the grid operators to urge consumers to save both gas and electricity produced by gas, to avoid depleting stored reserves too early in the winter, and for the throughput of LNG terminals to be optimised. GRTgaz is recommending that consumers reduce their heating by 1°C, saying this could lead to a 7% reduction in gas consumption. There are also voluntary paid cut-off schemes for industry, which have the potential to save 200 GWh per day, or about 5% of consumption on a very cold day. However, the gas operator has said that cuts will only be imposed on industrial consumers as a last resort.

Looking to the future, France is pressing ahead with its next generation EPR2 technology with plans to begin construction on the first reactor by May 2027.

“The goal is for the procedural part and authorisations to last less than five years and for construction work on the first EPR2 (rector) to start before the end of the presidential term, before May 2027…The latest timetable … sees commercial operations starting from 2035-36,”
– French government spokesperson

EDF plans to construct these reactors on three existing sites: two at Penly, in the Seine-Maritime region, two at Gravelines, in northern France, and two in either Bugey in eastern France, or Tricastin in southern France.

Suggestions that electricity may be rationed after all

Despite multiple assurances from Prime Minister Liz Truss that there will be no electricity rationing in GB (not something that politicians can control in any case), there are now indications that BEIS is working with NG ESO and industry on demand reduction and load-shifting measures, as fears grow over potential electricity shortages. According to the Guardian, households could be asked to turn down thermostats, and to use appliances at times when energy demand is lower. The system would make use of the alert service that NG ESO uses to notify consumers by text, phone call or email when there are power cuts.

A public information campaign could help consumers to ease pressure on energy supplies by providing advice on changes to consumption patterns. Until now, the Government has resisted calls to ask the public to cut energy use, unlike its counterparts in Europe, however, analysis carried out by BEIS suggests that Britain could experience power cuts for four days in January if there are gas shortages and the weather is particularly severe.

It is clear that despite all of its previous rhetoric, NG ESO is finally recognising that the system could be tight enough to require load shedding this winter. Hopefully this will be achieved purely through voluntary means, but there is a risk of mandatory supply disruptions, particularly for businesses. However, the system operator still seems to be in denial as to the extent of the risks, which is not encouraging. I would urge NG ESO to consider whether its de-rating methodology is appropriate in the ACS case and reduce the contribution from wind. It should also recognise that the behaviour of interconnectors in system stress situations has never been tested in real life, and could deliver undesirable results such as exports rather than imports.

We need additional measures to ensure energy security this winter. The Government should:

• Negotiate to return the Calon CCGTs to the market as soon as possible
• Lift emissions regulations limiting the use of on-site diesel generation
• Explore dual-fuelling of CCGTs to protect gas supplies in the event of a gas disruption
• Negotiate with Norway to secure imports in times of system stress in exchange for exports at other times

I am no more re-assured by this updated analysis that I was by the early winter outlook. While I hope that capacity margins will remain comfortable through the winter, hope is not an appropriate way to manage risk. We need a more honest and accurate appraisal of the downsides, and appropriate action, if we are to avoid harmful supply disruptions this winter.