Welcome to this afternoon’s session of the Energy Security and Net Zero Select Committee. With the events in the middle east, the issue of energy security is clearly of great interest and we will be addressing it shortly. Welcome to our panel, who are here to talk about the cost of energy, which will equally be very relevant, given what is happening in the middle east. I will ask the panel to introduce themselves, and then we are going to ask for a short statement from the chair of Ofgem about what is happening.

I am Akshay Kaul. I am Director General for Infrastructure at Ofgem.

I am Jonathan Brearley, the CEO of Ofgem.

I am Fintan Slye, the CEO of the National Energy System Operator.

I am Claire Dykta, the Director of Strategy and Policy at the National Energy System Operator.

Jonathan is the CEO, apologies—it has been a long week already. Thank you very much for offering to make a statement. Please, over to you.

Thank you, Chair. Naturally there is a lot of concern around the situation in the middle east, including the potential impact on consumers here. I would like to start by saying our thoughts and deepest sympathies are with everyone involved and those who have been affected. I also know that many families and businesses will be concerned about the impact this conflict will have on energy bills. Clearly, as we saw in the Russia-Ukraine conflict, our gas supply cannot be separated from global events. It is important to make clear that our energy supplies remain secure. Britain continues to benefit from a diverse gas supply, which provides the market with the flexibility it needs in times of disruption. In the short term, until the end of June, customers will be on fixed tariffs or protected by the price cap. Although we remain at the early stages of this conflict, if the strait of Hormuz remains closed for a prolonged period of time, it is likely that this will create significant upward pressure on prices that customers will pay for their gas and electricity. For example, with electricity, gas still sets the price for the majority of the time. I know that, already, there is a great deal of speculation about the scale and extent of those price changes, but, genuinely, it is too early to tell. In my experience, gas traders find it extremely difficult to calibrate the sorts of risks we are facing, and therefore market projections are not a reliable guide to the future. Examining the impacts for the energy sector, I would say that we are in a significantly stronger position than we were in 2021. Suppliers are more financially resilient, with a significantly lower risk of failure, and the price cap is already more adaptable to changing market conditions. We have regular monitoring of the market conditions and will increase the intensity of this as the situation evolves. Equally, we have improved the standards of care for customers and continue to work to improve supplier treatment of those in debt, and we hope to introduce our debt relief scheme imminently. At the end of this week I will be meeting supplier CEOs and we will maintain close contact with the industry and with consumer groups to surface and quickly address any unforeseen and unintended consequences. Finally, I welcome this Committee’s investigation into the costs of energy. I know that we will debate non-commodity costs, but this week’s events demonstrate to me that it is vital that we diversify our risk away from over-reliance on the international gas markets and continue to work strategically to provide a more stable place for the energy bills for British households and businesses. Thank you.

Thank you very much indeed, Jonathan. My colleagues may well have their own questions. You talked about the price cap protecting customers until the end of June. Ed Davey quoted a figure of £500 in Prime Minister’s questions for the increase in the price cap. Can you just reassure us that this is not where we are going to be in the short term, at the very least?

To be very clear, we know what the price will be until the end of June because the price cap was announced recently. We know that that is a reduction on where it was before, but it is simply too early to tell where prices will go. A lot of that depends on the scale and duration of the interruptions and the ability of the gas market to recover. I know there is lots of speculation out there about what might happen. Genuinely, I believe it is too early to tell.

Thank you. The Chancellor is meeting the industry and the representatives of North sea operators this afternoon, and they may be doing so as we meet. Something that has been raised by quite a few people is whether North sea production can be used in the short term to increase our supply and maintain our prices of gas. Can you just address that?

Ultimately, what we do with the North sea is a matter for Ministers, but it is very hard to see—certainly in the short term—that any change in North sea production would have a big impact on international prices. Ultimately, this price is set globally and it depends on big global dynamics. Therefore, big geopolitical changes like Russia-Ukraine, or indeed like we are seeing in the middle east, are the things driving the sorts of spikes that we see.

You said, “in the short term”. Is it possible in the long term to affect the price?

I think we have to accept that, even if we ramped up production in the North sea, I do not see a huge impact on the international price, unless somehow we ringfenced our market from others, but the fact is we will always need to import. I am not sure I see how that works.

You talked about diversifying our risk away from over-reliance on international markets. Is that another way of saying that the energy transition is very much in our interests and that is what the current crisis and indeed Ukraine have highlighted?

Of course, I know there is the big political debate about the scale and pace and about how we diversify, but I think we are seeing again the impacts of being over-reliant on one source of fuel. The transition we are on has the advantage of allowing us to have a more stable place when we get there.

Yes. Fintan, any comment on the points that I have just discussed with Jonathan?

The point I would make as well, though, just to reassure the Committee and other people, is that our energy supplies in Great Britain remain secure, and gas and electricity margins are adequate and in line with what we would expect at this time. I think the impact of the price rises in wholesale gas that we are seeing will take time to bleed through into bills, as Jonathan said. I would agree that it depends on how long that lasts. I think the point is well made that diversification away from gas, and the fact that the price is set on international global markets, does provide a degree of protection to customers in Great Britain.

Thank you very much. There are a lot of people who want to ask questions on this.

In your statement, Jonathan, you said that gas still sets the price for electricity the majority of the time. My question is why? If renewables went over 50% of UK delivery in 2024, and if we include other low-carbon measures, like nuclear power, that takes us up to 60%. So why are we still stuck with electricity being pegged to gas?

When you look at the dynamics in the wholesale market, in effect what sets the price is the marginal plant—the plant that is at the top of the stack for the demand we have for that day. Very often that remains gas.

Is this assessment done on a daily basis?

It is done more frequently than that. It is done at least half-hourly, so it is done in a very short term. For some of that plant, for a plant that is new—in renewables, contracts for difference—in effect the difference is repaid back to customers. But we still have a lot of legacy renewable plant on a system that was designed to be a top-up over and above the market price. That plant, plus the gas plant we have in the market, is still costing customers more than it should. Over time, as we build out more renewables, we will be in a different place and they will start becoming the marginal plant and that will change.

When do you think that will be?

I think NESO said by 2030. What was our thinking on that?

By 2030, gas will only be 5% of the mix. I think the—

Will it definitely, given grid connections, given constraints? We are going to talk about those things, but will it be?

The challenge to get to clean power by 2030 is a huge challenge and requires a—we use the term—Herculean effort right across the industry to deliver it. We can happily delve into the elements of it, but real, good progress has been made across that. Undoubtedly, gas by 2030 will be significantly less than it is today in terms of being part of the fuel mix. The other element of changing how that feeds through into prices is the reformed national pricing programme that the Government are launching. That is around how you change the market rules and the way prices are set, such that that is fit for the future and fit for purpose. What we have at the moment is a market mechanism and a market design that were built for a different era, and we need to transform that. That is what is termed the reformed national pricing programme. So the change in physical mix, but also the change in the market rules as to how that feeds through, are important.

You are getting into some of the questions we were going to come to later, but it is a very interesting point. As you have talked about the reformed national pricing approach, can you explain what it is?

Reformed national pricing is the market design programme that was born out of what was previously the review of the electricity market arrangements, or the REMA programme, where the Government looked at how the wholesale price should be set: should it be a national price or a zonal price? In the middle of last year the Government took a policy decision that the basic wholesale pricing mechanism should be a single wholesale price and that a programme should be launched to follow that up and ask what the changes are that we then need to make to ensure that it is efficient, ensures security supply and delivers value for customers. It is a holistic market design programme launched on foot of the decision to retain a single wholesale national price for electricity. It has a number of strands, some of which are being led by DESNZ from a policy perspective, some of which are settlement and billing-type changes, which will be led by NESO, and some of which are transmission charging workstreams, which will be led by Ofgem.

Chair, I understand that the reformed national pricing delivery plan will be published by the Department in due course.

In due course—it is so wonderfully reassuring of you to tell us that. What do you mean, Fintan, by “settlement and billing”, or is it too early to say?

A few weeks ago we published a call for input, setting out some of the potential changes that you could make to settlement and billing arrangements in the system. It includes things like, should you have a shorter settlement period? Should you change how different types of technologies bid into the market? It is a number of changes. At the moment, we are just at the call for input stage, so we have set out a few ideas and are looking for industry input into that.

Presumably the intention is for both business and domestic consumers to have access to electricity when it is cheap. Do I have that right? Is that the essence of it or one of the essences?

That is absolutely one of the essences. Some of the reforms that we are proposing allow for and facilitate much smaller players, potentially down to batteries and houses, being able to participate in the market and to leverage those assets in a way that they can minimise their bills as well. Yes, that is a core part of it.

Which we will learn more about in due course.

Jonathan, just to go back to your statement at the beginning, there were a couple of “in due course”-type phrases that I want to gently explore. First of all, in terms of the strait of Hormuz being closed for “a prolonged period of time”, I have read analysis suggesting that two weeks would be manageable, but that anything beyond that could start an impact. Could you expand a little on what your interpretation of a prolonged period of time is? Similarly, you talked about monitoring of market conditions and increasing the intensity of monitoring. How do you increase intensity of monitoring beyond very good Google searches? What do you mean by “monitoring” market conditions, and how does that happen?

On the impact in terms of the strait of Hormuz, I have heard—this is only in conversation with traders—there is a sort of assumption of around two weeks, and that is what is playing into the price increases we have seen today. I am afraid we do not have analysis that says what it might mean if it is a month or three or four months. What we are beginning to do—which is what we did in the crisis—is to look at base case, best case and worst case. You have to play into that all sorts of other geopolitical events that might happen. We do not have anything ready, but we are happy to come back and talk about that when we have.

At what point do you think it will create the significant upward pressure you referred to in your statement?

We are already seeing the wholesale market increase. That will feed through ultimately to the next round of the price cap, but it is not a black or white answer at the moment; this will be a graduation. My point is very simple: if someone is drawing a line from the price today and saying, “That is what is going to happen with the price cap,” I do not think that is robust, because this is moving too fast. On intensity of monitoring, I will be clearer. We have regular updates on the financial situation of the suppliers. We are already contacting each supplier to make sure we understand exactly what is happening to them as a result of this. That is all part of the framework we put in after the Russia-Ukraine crisis to monitor resilience.

It is increasing the contact with suppliers?

And the information we get from them.

That is fine, thank you.

The consumer and industrial pain is going to be deferred as a result of what you are saying, because unlike, for example, at the petrol pumps, the price is not directly reflecting changes in market conditions. What you are saying is that you are going to prevent the energy companies responding with a price mechanism towards consumers immediately because of the price cap. Is that right?

In a sense, that is right. The price cap, by its nature, defers the impacts for customers, but it is important to understand how energy companies trade behind that. Energy companies buy forward based on the price cap formula. What we ask of companies is to be largely majority hedged against what their customer base on a standard variable tariff have. In a sense, they are paying roughly what is charged in the price cap; it is just that they are buying the energy forward, which is what we would rather have than simply buying on the spot market.

I am told that a fortnight ago a cargo of liquefied natural gas from the United States would cost about $25 million, delivered to Europe, and now that cost is about $50 million, delivered to Europe. Are you saying that the energy companies should not be buying at that price or are you going to, in a sense, insulate them against those prices with a cost-plus structure so that, whatever their costs are, you are going to be able to allow those costs to be recovered from consumers?

For the gas that most companies have bought today for their customers who are on the price cap, they will have hedged that; they will have bought that forward, in effect, three months ago. The price they pay would have been set three months ago, so I guess it would be closer to the $25 million that you described previously. The companies all hedge against the price cap formula, which asks them basically to buy it in advance. That means this impact does not go away— you are right—but it does mean that that will feed through to the forward buying they will be doing for when that price cap changes. You have some problems at the margins, absolutely, but right now the disparity between a well-hedged company and what they get through the priceback should not be high, except for one sort of big differential, which is where the volumes that customers end up using are different from their projections. For example, one of the things you look for is, are there big changes in the weather, which would drive that other way?

How confident are you that all the major players in the industry have themselves insulated by having long-term contracts? That was the problem last time—that a lot of the companies went bust and the taxpayer ended up bailing them out. Can you assure us that that is not going to happen again?

We monitor very closely. We have two things that we did not have in 2021. We monitor very closely that hedging strategy, so the vast majority are hedged. We also monitor the amount of capital they need to hold to make sure they have an insurance against something like this. Now, the sector is on a journey—it is not in the perfect place—and we have been very open about that in our reporting, and indeed at this Committee. However, it is a much more robust place than it was before. The one thing I do need to emphasise, though, is that we are not designing a zero-failure regime. We are very cognisant that if we tighten those regulations too much, we simply do not have diversity and competition in the market. So there is always a balance. We cannot ever offer any guarantees. Even if the weekend and the Monday had not happened, we cannot offer guarantees there will be no failures, but we are in a much stronger position.

What can you do to stop profiteering? Obviously if I have hedged and I have my supply for $25 million instead of $50 million, I could go out and sell that in a subsidiary market now and make profits for my company. Will I then be able to pass on those costs ultimately to the consumer through the price cap?

In a sense there is always trading, as I say, around the margins of what your customers need, but you are obliged to provide your customers under the contracts you have with them. I think the major profiteering in the industry is not in the retail market. Ultimately, in the retail market, we set a regulated return, and the market has been at or below that in the last few years. What we do know is that those people that bring the gas out of the ground—the gas explorers and the people who get the gas out of the ground—are the ones where the big profits are made, and that is not something that Ofgem regulates.

We have seen the lists showing that we have the highest electricity prices in Europe, both for industrial users and consumers. Do you think that, because of the way in which our market is regulated, our prices for consumers will now be below the highest levels in Europe, both for industrial and domestic consumers?

The reason we have higher industrial prices than other countries—and it does vary—is principally the level at which our economy depends on gas and the fact that we are investing in our infrastructure to change it, including network costs. If the gas price goes up, I suspect that we will continue to pay relatively high prices. The reason why I argue for diversity—I know there is a debate in this Committee about what we should diversify to—is that I think that, at the moment, we are attached too much to a market that has been incredibly volatile. The new reality we have to face is that the geopolitical situation we have now means we cannot have confidence in the forward prices that were published last week, where everyone was telling me gas prices were low, because things change quickly. No one is arguing against using gas, and we need gas as part of our system, but what we are saying is that we think we need to diversify away from that.

The companies that have hedged successfully against this sort of price hike will be able to take that benefit for themselves, rather than have to pass it on to the consumer?

They will still need to provide that energy for their customers; they still need to pass it to their customers. So only around the margins, if it is a warmer day and they have less power than they need or less gas than they need.

I just want to follow up on what you are saying: the retailers are not where you think the profiteering is, but they have also hedged against things by their forward pricing. What is the knock-on impact beyond them in the market? Is our price cap mechanism in isolation not significant enough to have an effect on that wider international market?

Looking at our experience through 2021 and 2022, I think that our market is not significant enough to materially change the time basis of the energy market internationally. But there are some concerns that were raised. What you do is you concentrate British trading at a certain point in time. If you go back five or 10 years, different companies will have different hedging strategies; they will have different products they are buying over different times. For domestic customers, that is all concentrated around three months. I do not think that will be an issue at the scale and pace we are seeing at the moment, but it was something we were aware of, and there were consequential impacts on the wholesale markets when we went through this in 2022.

You have been talking about network costs, and I have some questions about non-commodity costs for you, Jonathan and Akshay. We heard from Rachel Fletcher of Octopus Energy that non-commodity costs are adding about £300 of pressure on to a typical bill. She questioned whether the investment, the expansion or the upgrades of the network were necessary and claimed that networks are “massively” underutilised and that demand has been falling for the last decade or so—she was not the only person to make that point to the Committee—and there is “massive” uncertainty about how quickly demand will increase. Does she have a point?

Chair, I think on electricity demand, it is true that demand has been falling from 2005 to 2025. There was a secular decline because of energy efficiency of the economy, but that has recently reversed. We are now seeing a growth in electricity demand being driven by the take-up of electrification of heat and transport technologies. That is, in the main, an issue when we think about the economics of the distribution grid. When you are talking about transmission for now, the big story on transmission is that we are building a lot of renewable generation up in the north and the east, in particular, offshore. That power has to be brought into the cities. If we do not build the network to connect the sources of power to the cities, all we are going to do is drive up the constraint costs—the costs of balancing the power system. We have seen that over the last 15 years: those costs have gone up from less than £100 million a year to £2.7 billion in the latest figures that we have.

Yes. Rachel Fletcher also questioned whether these network costs should be paid for in advance.

Network costs are essentially added on to the regulated asset base and then they are paid for by consumers over 45 years. The current generation of consumers will pay a small fraction of the total investment.

I think that perhaps what she is alluding to is a proposal that I know some people in the market, particularly suppliers, have come forward with, which is the idea that we securitise some of this and then almost charge it back in 10 years’ time to customers. That is something that we are open to, but so far we have found the impacts just on networks are quite marginal, so a wider, more strategic intervention would be needed.

If that is not a viable option, how do we, as a Committee, make recommendations to the Government on how to cut energy bills when it comes to non-commodity costs?

I would just say, on that last option, that it is something we would be happy to continue to work with the industry on. It is just about the materiality of it and whether we think it is going to make a significant impact on bills. I think it is worth stepping back and thinking, “What are we trying to do with the system that we are building and those non-commodity costs?” In a sense, where the market has changed is that if we are going to have the large-scale systemic change we are planning, you need to make sure your strategic planning is done in an effective way. I have been around different forms of the Government, the regulator and the industry in the last 15 years. I do believe that the creation of NESO is a big step forward in allowing us to better strategically plan our networks. Part of the reason we are running the networks programme we have today is based on the engineering planning that NESO does. Secondly, as Fintan says, getting the operation of that market right and getting our market arrangements in place through reformed national pricing is very important. Once you can locate your generation in the most efficient place, and once you have the most efficient network to connect all that together, it is about how you operate that more efficiently. The third thing I would say, Chair, is that there are big policy choices the Government could make. Now, it is not for us to give you an idea as to what our preference is, but the Chancellor is obviously—

That is what I asked you to do, to be fair.

I will stray a bit outside of Ofgem’s remit, which is unusual for me, as you know. The Chancellor made a big policy decision in the spring statement, and we have seen levies move on to taxation. I do not have to protect the country’s fiscal position, so I don’t see all the trade-offs, but it seems to me you are moving from a set of costs that are generally not very progressive, or indeed regressive, in the energy system to costs that are progressive elsewhere. Obviously, as the regulator that is concerned about reducing costs, we would welcome interventions like that. When you think about the warm homes plan and the potential to reduce the impact on bills, that again is something that we would support in principle.

Is the £300 in non-commodity costs that Rachel Fletcher quoted being added to a typical bill a good prediction between now and 2030, or do you have an alternative figure?

We set out our estimate of how network charges would evolve because of the RIIO transmission controls that we published last year. We see, essentially, the network charges rising by about £110. Those will be offset by constrained cost savings and a reduction in the wholesale power prices, because renewables will be displacing expensive gas on the system. That benefit, we reckon, is about £80. When we set out our impact assessment of what the impact is of these price control decisions on bills, the net impact is about £30, or about £2.50 a month.

Increase?

Increase.

Okay, so not £300.

I think she may be referring to networks plus the cost of things like contracts for difference, so it may be that you have had those two together.

Is that overall figure something you recognise then?

I think we would have to come back to you on CfD costs, yes.

It does depend on what exactly she was talking about. We can certainly follow up.

We would be very interested in what you think the figure is, if you can tell us.

Fine. We will come back.

Fintan, do you have a view?

Claire?

Without repeating what Jonathan and Akshay said, the one thing that we have not mentioned is how much energy is used and when. We have talked about policy costs, networks and things, but there is also opportunity in terms of reducing the impact of bills for individuals—whether that is houses or businesses—by continuing to roll out energy-efficiency measures. We talked about that in the advice we gave to the Government when they were creating their CP 2030 plan. That could cut energy usage by 5% to 10% by 2030, which will have a direct impact on bills. Also what we refer to as flexibility—so not running your tumble dryer between 5 pm and 7 pm, if you are on a tariff that rewards you for that—can save your average consumer £200 to £300 a year off their bill.

Yes. We have been very unimpressed by the suggestion that people have to get up at 3 o’clock in the morning to turn their washing machine on. You are lucky that Polly Billington isn’t here—if you have watched previous sessions, you will understand the reference. What you have just given us is that if people cut their usage, that is the best way of cutting their bills.

Through efficiency—not making unacceptable choices about, “If I forgo this, my bill will be cheaper.” It is things like efficient light bulbs, so things that people are already installing in factories and homes, and continuing that roll-out.

Has that not already been done? The energy-efficiency roll-out?

Not everywhere, no. We think there is further potential for that in the next five years.

It is worth just adding to what my colleague said that we are seeing a growth in time-based tariffs. I know all the challenges around it, but particularly as you see the growth of electric vehicles, for example, that is a good partner with people who begin to transition, accepting that not everybody is in that position.

Yes, and lots of household appliances do have timers on them. I appreciate that too. The Climate Change Committee is projecting significant falls in bills by 2050. Is it sufficiently taking into account non-commodity costs and their potential to rise? In reality, are we going to be stuck with high bills for the foreseeable future?

I will defer to Fintan to talk about the 2030 analysis and what that says about costs, but ultimately we see costs of the system to 2030 being roughly stable, and then you do begin to see costs falling after that. But I have to say that all of that is based upon technology assumptions, and we have to accept that all of these things have quite big error bars around them.

In the analysis we did to 2030, as Jonathan said, we looked at the transition to clean power, as we set out in the advice, and we compared that against a counterfactual. Broadly, the system costs taken as a whole were the same. As part of the analysis that we do, one of the key pieces we do is the future energy scenarios work, which looks even further out, to 2050, and at how energy bills might evolve over that period. Claire led that work. Do you want to say a little around what that said around bills as a percentage of energy costs?

As Fintan said, what the future energy scenarios do is look at different pathways to meet the legislative targets. Across those pathways we identified that total energy costs—that is non-commodity as well as commodity—would move from about 10% of GDP, which is where they are today, to approximately 5% to 6% of GDP by 2050. Our analysis is different to the Climate Change Committee’s, but it is commensurate in terms of the outcomes that it comes out with.

So you are confident that bills will come down.

What ends up in bills is always a function of policy choices, but the system costs—that includes everything from replacing boilers through to the commodity costs—do become a smaller proportion of GDP by 2050. What is also important, in the context of the last few days, is the impact it has in terms of volatility as well. In 2022, we saw a significant increase, when the proportion of GDP made up by energy costs went up by about 1.8%. If we were in 2050 and had the same impact, the increased spend would only be about 0.3% because we would be so much less exposed to the impact of gas prices, as Jonathan was saying earlier.

Thank you very much. Mike Reader has some questions on RIIO and TNUoS.

Constraint costs, as Akshay was saying—I am sure everyone in this Committee as well aware of this—are a function of the system design, both the physical and the market design. The largest proportion of them are due to generators that are connected in the north of the country not being able to generate, because the infrastructure isn’t there yet to transport that energy down to the centres of demand. The system is designed in that way, so there is an efficient level of constraint cost, otherwise you would end up by building a system to cover every eventuality. The network plans that the network companies are delivering under their RIIO price controls put that network in place. Where these costs are borne is a decision for the Government, but it would not stop those costs being incurred. The important thing is to deliver the network that, as Akshay was saying, offsets those costs.

It is the fundamental design of the market arrangements in the UK, as we were saying. The market arrangements here are largely the same as they were at the point of privatisation. There have been some changes. That is the way the market is designed. The market programmes that Fintan was talking about earlier that the Government are running do look at those types of questions and ask the more fundamental design questions about where costs are incurred and about policy decisions.

We have just published the call for input, so let’s be clear that we are at the very early stages of looking for input on all of this, but the focus at the moment is how to minimise the overall costs. At the end of the day, because of the way the system is, consumers end up picking up the bill. Even if you were to charge those constraint costs to generators that would just up the amount that they bid into the system, and ultimately consumers would pay. We have a mechanism at the moment where they are recovered through what is called balancing services use of system charges. We will look at other ways that they could potentially be recovered, but the focus at the moment, being transparent about it, is around how we get a market design and a system that delivers the most efficient outcomes and then have a cost allocation question after that.

I think we recently published a state of the market report covering the performance of the networks across a range of different criteria, including on cost, reliability, carbon and quality of service. By and large, the performance of the industry on RIIO-2, as well as recently on RIIO-3, has been very good. Reliability is extremely strong. Their performance in terms of storm resilience has improved. Ever since Storm Arwen, we have been relentlessly working with them to improve how quickly they get people connected back on to power. Their customer service scores have been improving. Overall, in terms of network charges, Britain is middle of the range when we benchmark ourselves across other countries. Overall, the incentives in RIIO seem to be working pretty well. What is coming up now are two iconic problems in network regulation. One is connections, and the other is the build of the network to bring all these constraint costs down. I think that is the iconic challenge for these network companies. We are going to be hot on their case to get them to build the network to time and budget and connect people as quickly as possible.

Sorry to jump in, but it is worth just describing a bit how we see the system evolving. Underneath the question, I think there is a genuine question we have about whether the network regulation we have in place today is going to be clear enough about the progress the companies are making on a whole number of fronts. We read the Cunliffe report with interest, for example, and we are thinking about how we reshape network regulation to look more intensively not only at how they are running and managing their assets but, as Akshay says, as we enter this build programme for transmission—doubtless there will be similar programmes in distribution—at how we make sure we are holding companies to account in a much more granular way. That is something that Ofgem is developing, but I think all infrastructure regulators will be doing something similar.

In a sense we have a set of trade-offs that you ultimately need to make. Claire mentioned time of use of energy, and in a sense greater flexibility—greater use of batteries, and having greater flexibility in our demand, where we can—will offset the need for generation and networks. The programme that Fintan has described—the sense of how we deliver the strategic plan that NESO is working on, and then how we operate the system efficiently—will absolutely define the level of network costs that we see in the system. The second part is that, once we have all that in place, it is down to the regulators, down to us, to make sure that the amounts that we allow in the bill reflect efficient delivery—coming back to your point—and that customers get what they need out of it. Now that we have settled RIIO, our preoccupation is genuinely making sure customers get what was promised out of the programme, and that comes back to the questions that were asked previously about 2030 delivery. We spend most of our time talking to networks now about, “Are you delivering the change in infrastructure that we think we have asked customers to pay for?”

I think we talked a bit about this. The regulated asset base already automatically spreads them out over 45 years, but a number of stakeholders have said to us that, to the extent that we are investing as a country ahead of need—I think this will come up most visibly in the distribution sector—and to the extent that we are saying to the networks, “Expand your networks in anticipation of the heat and transport demand that is to come in the future,” there is a good case for spreading that out further into the future and not charging it all to current consumers. That is where we are looking at more innovative mechanisms like securitisation and so on to see if we can have that effect. It is too early to say, first, how much this anticipatory investment ahead of need is going to be in the distribution grid and, secondly, how much difference this kind of thing will make to the amounts that people pay per year on their energy bill. It is a bit too early to say.

I want to talk about the distribution use of system costs. Jonathan, obviously we have had some delay and some chopping and changing when it comes to the significant code review, but could you say how much you think we might see distribution network investment costs go up in the future? Do you think they are going to end up being the biggest part of network costs?

Akshay?

Again, we are in the process of doing the price review for distribution, which will start from 2028 and run until 2033. Next year we will have a much better feel for what the investment programme of the distribution companies looks like, and therefore what the scale of that investment is likely to be. My current assessment is that it is unlikely to be at the same scale of increase that we are seeing in the transmission sector. That is only because, in the transmission sector, we are trying to catch up quickly with the huge increase in renewable generation that is already on the system or shortly coming on the system, whereas with the distribution grids, we have a little more time to make sure we get ahead of the demand.

When the National Infrastructure Commission estimated a total of £37 billion to £50 billion was required in the distribution network investment up to 2050—although there is potential to reduce that through maximising consumer flexibility—are you saying that you don’t see that making a significant difference on the bills that eventually come through to consumers?

In terms of the effect on bills, because the regulated asset base smooths all this out over 45 years, it takes a lot to move the bill impact of network charges materially. If we have, for instance, the rate of expenditure in the distribution grid going up by 10% or 20%—which would not be an implausible guesstimate—that would have a very small effect of about £1 or a couple of pounds per year on the household bill.

To be clear, there may still be an increase in distribution costs, but if you compare that number to what we are spending on transmission in a shorter period of time, that is a lot more.

My next question may not be so relevant, then, because I was going to say how might ED3, the next price control, keep these costs reasonable? Your argument is that, in the grand scheme of things, even if they change quite significantly, overall the actual change that consumers will see will be very small.

No. In fact, we have been quite persuaded by the National Infrastructure Commission’s report, which argued in favour of getting ahead of demand and investing once in the distribution grid for a long period of time to take us to 2050. We want to make sure that we balance that, as Jonathan was saying, with the full use of flexibility of demand, because on the distribution grid that can make a tremendous difference to how much you need to reinforce the distribution grid and when you need to reinforce the distribution grid.

Look, I think distribution is different to transmission, in the sense that you have higher voltage network and lower voltage network. The higher voltage network in distribution is a little bit more like transmission: you have to build that strategically; you cannot adapt as you go. As you get to the wires that connect our homes and through the streets, that is much more adaptable. In my mind, the trick with this price control will be making sure that, as our projections versus reality become clear, we can adapt more what we need to spend, and we don’t necessarily have to be locked in quite so early, whereas with transmission at some point you have to make a judgment because these are 12 to 14-year projects, and even the build is four or five years long.

Are five-year periods of price control long enough to incentivise suppliers and consumers to take up flexibility?

For flexibility, I think the incentives that we are putting in are going to be strong and will be sufficient. The thing we are trying to do alongside the incentives for flexibility is put in place a longer-term spatial planning framework for both the national system as well as the transmission and distribution systems, so that we can plan properly for the uptake of heat pumps, electric vehicles and solar panels in each area across the country and then use flexibility to optimise the timing and the scale of the network reinforcement that is needed.

At the distribution level, that is more flexible?

It is.

It does not need the same level of deployment. Does that long-term plan make much difference in that context? I can see why it is very important for the distribution network—the higher-voltage ends of the distribution network—but ultimately you can make decisions on a much more short-term basis when you see what is happening with the flexibility. Is that what you are saying?

To me, the trick in designing the price control is to make sure that your strategic investment is matching regional plans and that then, as far as you can be, you are allowing the companies to be adaptable to where demand occurs and the rate at which it occurs. Inevitably, in the projections we have on things like electric vehicles and heat pumps, there will always be a deviation year on year, and it is about making sure we don’t overbuild or underbuild against the changes that we see in the market. That is why I think you have to get your design of the price control right and, indeed, through the regional energy system planning, which is beginning to get going, making sure that those things are aligned and we understand strategic needs in different areas. One last thing I would say on the length of price controls, is that we did have eight years on RIIO. The downside of a very long price control is, again, if it gets out of sync with reality in ways you cannot predict, that could become quite big after eight years.

I want to ask a couple of questions around balancing costs, which you touched on earlier. But, Jonathan, I just want briefly to go back to your initial statement around increasing intensity of market research. While we have been meeting, there has been a report that energy firms are pulling all their fixed deals off the shelves in response to what they see as a forthcoming rise in price caps. When you are meeting them, do you urge them to stop doing that?

I think it is something we have to accept, going back to the conversation that we had, that if you are under the price cap, you are under the system that I have described. Energy companies are going to find it hard to hedge forward—which we want them to do in all their purchasing—in the same terms they could a week ago. We are going to work very hard to make sure that we protect customers. We are going to make sure that we are cognisant of customers in vulnerable circumstances, but I can understand that those offers are becoming uneconomic.

I did not mean to put you on the spot. I mentioned it because it has come out and I referred to it earlier on. On balancing costs, the overwhelming majority of that, about £1.7 billion in 2024-25, came from thermal constraint costs and physical infrastructure. Can you outline why that has happened? Will the increase in infrastructure that we are hopefully seeing being built reduce the balancing costs going forward and, if so, by how much and how quickly? That is probably for Claire or Fintan.

You are absolutely right that the majority of the balancing costs incurred at the moment are due to thermal constraint costs. The main driver of that is trying to move generation from the north of the country—typically offshore wind in Scotland and down the east coast—to the centres of demand in the south-east of the country. In terms of network build, which Jonathan has talked about, the programme that the network companies are engaged in to deliver out to 2030 and beyond, is the network that is needed in order to mitigate those constraints and bring them down. When we are doing the plans, we continually look at levels of constraint and network build and there is a trade-off between those two things. What we see when we look out to 2030 is that constraint costs are likely to rise up until 2030.

Will that be thermal restraint costs that are likely to rise? Is the idea then that, by 2030, the infrastructure will be better and that will fall?

Yes.

Will the thermal constraint costs remain the biggest opportunity to reduce overall balancing costs?

Yes.

That is where the savings should happen.

That is where the savings should happen. As the networks projects commission—unfortunately, you need them—they are not there one day, but they are the next day; you get all of the benefit on the next day. Constraint costs rise, and then the transmission owner’s programme has those big transmission programmes delivering in 2028, 2029 and 2030. Those constraint costs then fall, and that is the thermal constraint cost.

Right now it is £1.7 billion out of £2.7 billion. Would you have any hope or target or thought in your head about where that might end up by, say, 2030? Percentage-wise is perhaps a fairer way to put it.

We do have a graph of what that looks like out to 2030. We see it go up to about £8 billion in 2030 and then come back to around £2 billion post that. It goes up and down then after that.

Why would it go up and down if we are saying we have the infrastructure built, so we should have less constraints? Why is there not a peak and then it tails off?

Because even after 2030, you continue to build generation facilities and you continue then to need to build network.

One should naturally continuously cycle to catch up with the other?

Yes. What we are seeing at the moment is that lead times for transmission infrastructure are considerably longer than the lead times for the generation infrastructure.

Will we ever see that balancing cost at a much lower level consistently, or will it cycle the whole time?

You will not see it come down; you will not see the thermal constraint number come down to zero.

It will roughly make up the same proportion or the same number for the foreseeable future?

Yes. It has risen this year over last year. It will fall back post 2030 a bit, I think. But you are never going to get the thermal constraint number down to zero, because that would mean that you have built and invested in a network that never has, for any five minutes of any year, any constraint on it. So there is a balance.

The clue is in the name. What is an acceptable balancing cost, or what is the level you think you should be able to get to if everything is working perfectly well or as well as it can?

Looking out post 2030, when you pull back network delivery times—there is a huge programme of work under way to do that—we see balancing costs in the range of around £2 billion per annum in that period. Remember, in balancing costs, the thermal constraint is the biggest element at the moment, but there is also a chunk of other costs in there around services that we need to purchase in order to safely and securely balance the system, like buying inertia, buying reserve from the system. We will always need to do those things as well—to purchase services from the market, be that batteries, generators or networks—to balance the system.

Very briefly, as someone who spent quite a large part of their life trying to get renewables projects consented in Scotland, one of the biggest barriers we had with the public was complaints around constraint costs and wind farms being paid to be turned off. It was a recurring theme everywhere we went, which was frustrating, as you can imagine. Are there things that NESO can do to provide additional flexibility to bring that down and that complaint level down? Again, if you are talking about moving generation closer, you are going to have the problem we had, frankly, in Scotland replicated in other parts. Are the things you can do to stop that if we are trying to build generation faster?

I think there are two major things. One is better long-term strategic planning, such that you actually build the network, such that it is there at the same time as the generation wants to connect. At the moment it has been reactionary. The generation would have a contract and then you would initiate the programme to connect it, but the lead times got completely disconnected. With strategic spatial energy planning and then moving into—there are acronyms for all of them, I can assure you—what is called the central strategic network plan, which is the actual network delivery, that is designed to allow the network to be built at a time to meet the generation when it is due to connect, wherever it is due to connect, such that you get a more long-term strategic line of plan. Therefore, in the long term, that will reduce constraints because you will not have this mismatch between them. The other piece in the short term is stuff that we can do operationally just to manage the system in a more economical way to eke every last megawatt out of all of the transmission lines. That is things like new technology in our control room to allow us to issue more instructions and be nimbler in how we balance the system, but also working with the transmission owners to deploy new technology on the lines. There is a major programme under way. It started before RIIO-3, but got significantly scaled up in RIIO-3, around dynamic line rating. This is where you install advanced technology on the transmission lines that allows you to push more power through them when the conditions are right. It is very fortunate that our problem tends to be that our transmission lines are constrained when it is windy in Scotland, and the wind allows you to cool the lines and push more power down through them. There is the potential to deploy that technology in a way that does—

Who knew that Scottish weather would be helpful. Thank you.

Why would it ever be acceptable, or would it ever be acceptable, to see constraint costs going to £2 billion or higher?

Sorry, Chair, just—

Constraint costs. Akshay, you were saying they were £100 million. They are going to go to £2 billion. Did I get that right?

They are currently at about £2.7 billion.

Why is that acceptable?

The balancing costs are £2.7 billion. I think the constraint cost is £1.7 billion out of those. I think there are two parts to the question. The first is that when you move from a fossil fuel system to a renewable system, there will be a natural increase in the level of efficient constraint costs. I will explain what I mean in a second, but that is because you have much more variability in the supply sources. So there is reason to believe that the efficient level of constraints goes up. The efficient level of constraint is the level at which it is cheaper to tolerate the constraint than to build new network. This is the point that Fintan was making. That is why we never want to drive them down to zero. We want to continue to expand the network until that point that the marginal network build is more expensive than just managing or tolerating the constraint, so just paying the wind farms to switch off. We will find out what that level is, but that level in a renewable system will almost certainly be higher than the average that we had during the fossil fuel years.

We accept, I think, collectively that constraint costs are too high, which is why we are building the network at the pace we are. When it came back to the debates on RIIO, it is that funding that we need to get the system systemically to a different place.

As you have acknowledged, it is important not to forget that constraint costs are the largest part of balancing costs by far. But even if constraint costs were zero, which they never would be, there will still be a balancing cost because the fundamental role of the system operator is to balance the system and ensure, from a physics point of view, that it continues to work, so that cost will always be there. That is why all the things that Fintan that we are concentrating are so important, in terms of how we run the system and ensuring that we use the best technology. We have taken just over £1.2 billion-worth out of balancing costs in the last few years with that type of activity, so we should not lose focus on that either.

It is too early to say. I think we will know more next year when we see the spending plans of the distribution network companies, and we will be able to give you a much more precise estimate then.

But in terms of the spread now, distribution costs are higher on the bill now.

They are. They are a bigger part of the bill already than transmission, but transmission is rising very sharply. It has gone up from £50 to about £83 per year. Distribution at the moment is much more than that.

I thought you had questions on the transmission network, Mike.

With the transmission network use of system charges that we publish, NESO acts as an administrator in that scheme. We strategically plan the system and identify the network that is needed, and then each of the network companies, through the RIIO controls we have already talked about, work with Ofgem to determine exactly what they are going to build and how much that is going to cost, and we then recover that on their behalf through those charges. We are given that information through the networks. It is set by the price controls, so there is little variability around it, but that does not negate anything that we have already talked about around there being opportunities on top of that in terms of innovation and things, which means there is always opportunity to use that network that is there in different ways as new technology is developed.

It is fair to say that everything in the energy system was designed for how the world looked at the time of privatisation at the end of the 1980s—so the market frameworks, the network—and we are moving into a world where policy objectives are necessarily different. We have talked a lot about market frameworks and how they need to be reformed to be fit for purpose. Investment is needed in the network as well. It is worth saying that even if we were not shifting to a more renewable generation mix, there would still need to be significant investment in the network because the gas CCGT fleet is coming to the end of life, as we have discussed extensively, and it is very front of mind in terms of the last few days that where our gas is coming from is changing. Whatever supply mix we are in in the energy system, we would be at a point of investment now anyway.

Everyone who operates in the energy system who is licensed is obliged to operate in an economic and efficient manner. There are lots of things that we have covered off today, like strategic plans and the market reforms, that all have the objective of lowering bills at the end of the day.

No, I think they are the same.

We all have the objective of operating in the most efficient way we can, but all those programmes that we have mentioned have a primary objective of lowering bills, which is best value.

Is that objective being met, I think, is the question.

We are in a state of transition at the minute and implementing those things. We are layering in some shorter-term tactical things as well to make sure we are delivering the best value we can at this point in time.

It is not our role to recommend, as such. We provide advice to the Government, but the advice that we provide is from a system operator perspective. They will be getting input from lots of other parties as well, and then the Government take decisions based on all those things together. We work closely with the Government and with Ofgem, and across the three organisations we can take those whole-system views, and the Government ultimately can make balanced decisions.

When NESO was set up, there was this function where the Government can request formal advice around it. I do not believe that there are any of those pieces of formal advice that they have not taken on the recommendations that we have had. We engage with them across a broad range of stuff. I think the formal advice is a subset of that, but, no, I think we absolutely feel heard. I can’t think of anything.

We are working through reformed national pricing, and the whole idea of that will be to join charging with the balancing and system costs that Fintan outlined and strategic planning. That is all coming. There is nothing in there that I think we have formally recommended that DESNZ has formally said no to. That is just a piece of work that is in train. We have already expressed enthusiasm for the Chancellor’s intervention in the spring statement. Beyond that, it is probably a matter for Ministers.

By design, combined with strategic planning, that is intended to do that—and balancing costs as well.

Not really. The generators pay about £1 billion out of that £8 billion of transmission charges and all of that money has gone into investment in the networks over the last 10 years. The reality is that that network investment itself has not been sufficient. I think the biggest lesson from the last 10 years is that we needed to have a strategic plan that co-ordinated generation and network much earlier and then upgraded the network much sooner. In terms of the increases that we are seeing coming through now in transmission charges, of which the generators will pay about an eighth, most will be paid by households and businesses. That is paying for this big uptick in investment.

I want to talk about some connections reform and constraint costs in a bit more detail. If grid connections are not facilitated in a timely manner, what impact will there be on consumer bills? Can you put figures on it over the next few years?

Is it worth talking about the connections programme first, and then perhaps we will come back to the impact on customers and what it might mean?

Connections reform programming is a huge and complex once-in-a-generation change in how we think about who and how projects connect to the system. We found ourselves with a generation connection queue designed on a first-come, first-served basis with about 850 GW in it—just to give you a sense of scale, peak demand is about 50-ish GW, so it was a massively oversubscribed queue. Through a period of industry reform—it is a detailed open-code governance process in the industry to develop mechanisms to change that over a number of years—

This is very interesting, Fintan, but if they are not done in a timely manner—I do not know what your definition of a timely manner is, and I would be very happy for you to give me a series of dates—what does that really mean for consumer costs?

I do not think you can draw a one-for-one line with consumer costs, because the impact on consumer costs depends on how that generation project decides to bid its project in and participate in the market. Undoubtedly, we have identified now the projects that should connect, so the ones that are strategically aligned to Government policy and the ones that are ready to go. We curated that connections queue at the start of December and told all the projects in it where they stood with respect to that. Therefore, the focus now is to get the formal connection offer out to each of those projects. So each project now knows, “I am going to get a connection offer to connect,” or, “I am Gate 1,” which is that you are not strategically aligned or you are not ready to go. If you are going to get a connection project offer, you now know the window in which we will provide you with that connection offer. The teams across us and all the network companies are now doing the detailed engineering and design, based on this new, different queue, to work out technically what needs to be built to connect this project and when it can connect. That then gets packaged up into a legal connection offer. That process is under way. There is a timeline that is now published and established, and all the generators know it, so they will know when they can get a connection offer. We have started to issue those connection offers out the door.

Jonathan, do you feel confident and comfortable in that? Do you feel like you can go to consumers and say, “It is all right, the plan is working. We think we now have a plan. We got rid of all of those projects that were just hanging around. We are doing it on a first-delivery, ready-to-go project basis. This is going to make a material difference to you”?

I think it will make a material difference. It is fundamental to delivering 2030, which as we described right at the start, is the way in which we avoid the volatility that we have described today. Strategically, it is incredibly important. Yes, we are confident in delivery. It has been a difficult process. We have had to adjust our timetables, but we understood that when we went into this. The key thing for all of us is to make sure the co-ordination between NESO and the transmission companies—and the distribution companies, in particular now—is done in a way that gets these offers out, gives developers certainty and allows us to make sure that this is keeping 2030 on track. We are confident we have that, but these are complex, unique contracts that we are changing, so it is a process we are working very hard with the companies on to deliver.

From an outside perspective, it does feel like it is taking a long time for us to see meaningful impacts on those connections. Reforms to the queue were suggested three or four years ago. Why does it take so long?

It understandable that there is a frustration out there about how long it is taken, but this is a massive change to the industry and to the contracts that all those 850 GW of projects held. They all held individual contracts, and those are all now in the process of being changed. The process to do that is set out in industry codes that have very strictly defined governance processes that you need to walk through. Part of the reason it took time was making sure that it was done comprehensively and properly, such that it did not become subject to judicial review, for example, because the reform was not done properly. It undoubtedly took a significant amount of time to walk through all that industry change process and get to a formal proposal from the industry code panel. That ultimately went to Ofgem, who then ran a consultation and approved a methodology. We are at the point now that we just have a methodology and agreement about how we are going to reform the codes. That was spring last year, and then, through last year, was the start of the implementation of that, and that introduced new requirements. For example, with this ready-to-go criteria, we had to get from each of those projects their land rights—“What form of land rights do you have over where you are going to site this? Do you have a lease?”

None of this is a surprise though, is it? I really do not understand why it takes so long and processes are established for a sense of processes’ sake.

It is very important to acknowledge what we were trying to balance with Ofgem and Government. Speed is of the essence, as you are saying; it was a huge problem to have shovel-ready projects being held up by not-real projects in front of them. But we were balancing that with maintaining the message that we are open for business here. As Fintan was saying, this is one of the most significant contracts that those projects hold, and if we were, just overnight, to rip them up and change the rules, it would have had a huge impact on investor certainty. Following due process and making sure everyone had—

Did they manage to hang on until all those other projects were chucked off the list? If you are worried about investor certainty, did they all hang around? Are they all still here? Are they all still planning to invest?

It is worth looking at the different technologies. In offshore wind, we saw lots of bids in AR7. Yes, they are there. Yes, we are getting them connected. You then get to smaller-scale onshore wind and solar, and we think we have roughly what we expect for 2030. Then, in the battery market, we have a huge number of people trying to build batteries, which we absolutely need as part of our system. We need to be honest that this has taken longer than we hoped, but we are going through a set of quite fundamental changes. We are meeting regularly, working very hard together, to make sure that when we get those offers out, they are consistent with our ambition to change the system, they are fair and we are legally robust. That does take time.

Can I ask a couple of questions on data centres? Is there going to be a big impact on consumer network costs if we get lots of data centres being connected, as the Government are interested in doing? Are there any considerations about private wire agreements around offshore wind to try to bring down curtailment costs, and therefore bills, if heavy-demand assets like data centres are brought on to the system?

A lot depends upon the specifics of these data centres—where they are located, how they connect to the grid and how they source their generation. If you look around the world, we have examples—Ireland is one, and there are states in the US—where if you have an unplanned, uncontrolled increase in demand from data centres, it pushes up the electricity prices for everybody. We think that if you have a more managed system, and a way of ensuring that data centres are, in a sense, contributing to generation, as well as taking up network capacity, and providing a bit of flexibility into the power system, there is a way of connecting what I think the country needs without it having a significantly negative effect on consumers. I think, Fintan, you and the team have been doing a lot of thinking in this area.

I completely agree with what you said. The thing to point out as well though is that there is a huge number of speculative projects out there in the demand-side queue for connection to the system. I think data centres are close to 100 GW in that space. That is orders of magnitude more than the Government have indicated they might want to get and could possibly connect in the system. All the planning we have done—things like FES and the clean power transition—assume some level of data centres within it. As Akshay said, if you think about data centres, and think, first, about locating them in the right place on the system, they can be helpful; if you put them in the wrong place, they can cause problems, be that costs or constraint costs. The second thing is making sure they have a level of flexibility associated with them when they commission. We have seen some great examples in the US, where they have introduced rules and regulations requiring levels of flexibility that make a meaningful difference to their impact on the system. Overall, in terms of the AI growth ambition and the associated buildout of data centres, it looks to us like there is a way to manage that, but you have to actively manage it. We see things like AI growth zones as a good initiative that is helpful in that regard.

We have been increasingly talking about battery storage through the session. One of the pieces of feedback we have had about the connections reform process is that those developers at Gate 2 who had a battery as part of their proposal have had to remove the battery element. I heard you saying that you have plenty of battery on the system, but what consideration is being given to the impact on the economic viability of projects when they have had to remove their batteries, and indeed the technical constraints of doing so?

I do not know the specifics of the projects, Chair, but I think I know of the nub of the issue. The first thing to say is that significantly more batteries are going to get connection offers as part of Gate 2 than was indicated in the Government’s Clean Power 2030 Action Plan. That is because an awful lot of them had progressed and got planning consent and land access rights at the—

So as far as you are concerned, we will have more battery capacity than we need.

It does look that way, yes. I think we certainly will. Where you have hybrid projects—projects that have two technologies associated with them—some of those projects were originally just one technology, and then added the second technology a number of years later. Maybe they were originally a solar park, and they applied just as a solar park, and then a few years later, while they are still in the connection queue, they said, “We now want to make this a hybrid project. We want to add a battery to the site, so it will now have a solar park and a battery.” The way that gets treated as part of the connections reform process is that because they were applied for at two different times, they get treated as two different projects. Therefore, some developers, who were progressing a hybrid project because they had added the battery, now find that they will get a connection offer that connects the two bits sequentially rather than at the same time. That is the way the methodology works, and it was an attempt at fairness; otherwise, the battery that was added later would skip over all the other batteries in the queue. That is a feature of the reform and the way it is working.

Thank you for explaining that.

I want to talk about standing charge reform, and specifically low standing charge tariffs, which I understand to mean you pay a low or zero daily charge, but your kilowatt-hour price is higher, so each unit of energy costs more. When will suppliers be offering low standing charge tariffs?

What we have announced is that there will be a large-scale pilot from four suppliers from April, where they will be offering at least £150 off the existing standing charge.

Thank you. Obviously a different tariff needs to be an informed choice by consumers. There are risks and benefits. What will you do to ensure that consumers are fully informed and can make good decisions on what tariff to choose?

Part of the reason we are doing this as a big pilot, but as a pilot, is that we want to work very closely with suppliers on how they communicate and how they make it clear to customers what is in their interests. Also, if a customer discovers that they are on the wrong tariff, a big question is, what options are open to them, how do they know that and what should the role of the supplier be? We are testing all of that as part of this large-scale pilot.

Will you be modelling at what point tariffs flip over into being better or worse for a consumer, so levels of energy consumption at which it makes sense to have a low standing charge tariff, and levels above which it does not make sense? Will there be any modelling and illustration for customers?

That is what we would expect the suppliers to do when they are describing the tariffs to customers. We have rules already around supplier transparency. However, I think there is a big question. The reason we are treading lightly with this is that there is a big question about how customers will understand it, how they will respond and what they will do if they are able to discover they are on the wrong tariff. We have been quite surprised, as we have progressed some of these options, by the concerns that consumer groups have raised with us. We want to do this with suppliers and with consumer groups before we expand it across the market.

Finally, we previously made recommendations on exemptions to the gas standing charge and on a special summer regime for those on prepayment meters. Will you be implementing them?

Do you want to talk about the gas standing charge, Akshay?

We are doing a review at the moment on the standing charges that relate to people who are reducing their use of gas because they are electrifying their home. I can be totally clear that if you disconnect from the gas network, you do not have to pay standing charges. That is very clear. However, a lot of people do not disconnect, because when they ask for a quote, the process, first of all, seems very complicated. You have to navigate who you should ask for a quote from, what timescales they serve you and so on. Then, we are hearing that the quotes you get can sometimes be £2,500 or £3,000. We want to investigate that and say, “Is that a reasonable quote for somebody who needs to disconnect?” Secondly, there is a strangeness in the rules, in that if you stay on the gas network but do not draw any gas for a period, under the health and safety rules the gas company has to come and essentially seal off the gas network coming into your home. That cost, which is essentially disconnection, is then socialised to all other consumers; the disconnecting customer does not pay that. Again, we wanted to ask whether that is a sensible set of rules. Should the people who are disconnecting pay for the costs of disconnection, or should those be socialised across everybody else? We have been doing a call for input on that. We will be coming out with some policy proposals in the next couple of months.

On the first part of that—this is slightly separate from the safety issue—is there not a way of doing virtual disconnection? Why do they have to be physically disconnected from the gas system if you can see that they are not using any gas?

It is a safety issue in the main.

What is that safety issue? Because there is gas coming into a house and being used or not being used all the time anyway. What is different about it never being used?

I think the worry is that it could leak out if there is absolutely no check on it. I think the health and safety rules just require, if there is a long period of disuse, that the gas network has to go in and seal it off.

Because there will be no monitoring of gas-using appliances, it might deteriorate?

Yes.

I want to pick up on some issues about modernisation of NESO systems, but also particularly around cyber-security as well. IBM has found that energy is one of the most highly targeted sectors in the UK for cyber-attack. We had the European Union Institute for Security Studies note that some Chinese hackers have shown they are preparing for attacks on critical infrastructure. Indeed, some of the discussion over the last couple of days has been about how susceptible the UK energy network is to cyber and other types of attack from Iran. Can I ask you to be as specific as you possibly can be—I know it is difficult—about how secure you feel the UK energy system is, and in particular about what conversations you have had with DESNZ about improving that?

We are joint cyber-competent authority with the Department. Frankly, the industry, like every industry at the moment, is on a journey to continue to improve cyber-security. We have a very detailed framework. We do not share details, for reasons I hope you understand. A bit like with some of the other issues here, we can never guarantee that there will not be a cyber-incident, but we have made significant progress over the last few years in increasing security. I do not know if you want to add to that, Akshay.

I am keen to understand how often you run tests of that. Is that externally monitored? I do understand the difficulty of giving away how you protect, but could you give as much detail as you can to provide reassurance?

Mandatory testing is coming in from this summer onwards, and even before that we have been doing a lot of work with the National Cyber Security Centre, DESNZ and the industry to upgrade their defences against cyber-attacks and, as importantly, their resilience to restore services if a cyber-attack gets through. A huge amount of progress has been made over the last few years on both counts. We are very encouraged that the industry is taking the testing, the war gaming and the preparations very seriously. We will continue to work with them to stay on that path.

Do you have any conversations with other Government Departments about what has happened in Ukraine, and how that energy network has been protected from cyber-attack—obviously, it is under near-constant cyber and physical attack—as well as about other countries where there have been suspected cyber-attacks?

Through our cyber teams, we try to learn all those lessons. Through NCSC, we make sure that we make the best of the best practice experience out there.

Would you say that you are very confident that the UK network is as secure from cyber-attack as it can be?

Yes, but with the caveat that this is a very fast-moving sector and of course these risks change over time and change quickly.

Jonathan, Ofgem has said that targeted cyber-resilience requirements will be needed for the most significant operators. What determination have you made about who fits under the “most significant operator” category? Is it just the big six, or are you looking more widely?

We look at critical national infrastructure.

On the national infrastructure, the NIS regulations, which govern our role, essentially specify a set of operators of essential services. Even within those, we do prioritise those that could have the biggest impact on the system if there was a failure.

On costs, Ofgem has said that calculations show the average cost of a cyber-attack to utilities is about £210,000, with cyber ranking among the top risks across utilities. Who meets those costs, or who would meet those costs in the instance of a cyber-attack?

In the first instance, it would be the companies themselves, so I think this is a big commercial driver for a lot of these licensees.

We have seen similar cyber-attacks in the UK where the Government had to step in—I am sure you are aware of what I am referring to. At what point would you have conversations with utilities and with the Government to determine who meets a large cost? Would that be Ofgem’s role? I guess that is the question.

In a sense, what we are preoccupied with with cyber-security of the system and of the companies in the system is, first and foremost, around customer protection, security of supply and making sure that the companies can still operate. If there was an attack, and if there was an economic impact of that attack, that is something that we would have to agree with DESNZ and with the companies involved.

It would depend on the case specifics.

A more general question to Fintan and Claire: Energy UK has suggested that a small investment in modernising NESO systems would deliver billions of pounds in efficiencies, although, to be honest, it was not able to provide details. However, when it comes to NESO systems, what modernisation can be conducted, and how much of a saving can be realised?

We have touched on this a couple of times, but we have already been investing in our systems, from both a cyber-security point of view and a capability and capacity point of view. The system is fundamentally changing. Our world 10 years ago would have been dealing with a very few players, and we could always pick up the phone to them if we needed to. The world in the future is going be lots more players and a complete digital world. So we are in the transition to full digitisation of our services, which will enable digitisation across the networks. We have already been on that journey. One of the most tangible things to bring out is the updates we are doing into our control room systems, where we keep the lights on. Modernisation of the services there has enabled us to increase the utilisation of batteries in the system by 290%.

Can I ask you about operating costs? Most people would think that it is extraordinary that an electricity company that does not collect what it is owed from its customers should receive some sort of compensation allowance from the regulator. Why do you permit that? Why do not you require energy companies to fund any failure to collect what is owed to them out of their profits?

The allowances we make are within the price cap, so in a sense, when a company issues a fixed rate, it includes all of its costs and makes its own calculation. But within the price cap, what we have to do and what the legislation requires us to do, is to identify reasonable and efficient costs and to make sure that those are fairly reflected. In any business, particularly in energy, there is always going to be a cost of debt that ultimately is not paid. For us, in a sense, it is a calculation of what we think a reasonable company should be incurring in costs and then reflecting that back with a regulated margin for the price. In other markets you do not have a regulated price, therefore you do not have this kind of calculation being made by the regulator, but they still exist in the price that is charged.

You make this extra allowance. If they are recovering the costs from their consumer—if the consumers are paying their bills—that is good, and the more efficient companies collecting the money will make perhaps larger profits, or not such large losses. However, the idea that all this should be pooled and be another burden on every other customer, when we are trying to reduce the costs of bills, the headline costs of electricity, why are we burdening those bills with this? Is there not another way of doing it, in the way that I have described? If you go to Sainsbury’s and you hear that there is a lot of shrinkage and you see that the security guards allow people to walk out with large amounts of meat that they haven’t paid for without challenging them, you may think twice about whether you are going to go back to Sainsbury’s because that is included in its prices. You are doing something similar. You are adding to the inefficiency that comes out of the companies that are not collecting the money. Another example would be if you are collecting council tax as a local authority. Local authorities are not given an allowance for people who have arrears of council tax. If you removed this particular item from the bills, it would save everybody a significant amount.

What we do, through the price cap calculation, is give every company the average cost in the market. That does not change their incentives at all. Those who collect more will do better and, exactly as you say, will make greater profits or fewer losses as a result. However, in any business, including councils and supermarkets, there is always an allowance made in accounts for people who do not pay and that is part of the ongoing cost of the business, and the legislation requires that we reflect that.

Your policy on this has contributed to an exponential increase in the debts—the unpaid bills. Remind me of how many billions of pounds are now owed by customers on their electricity bills.

It is about £4.5 billion.

£4.5 billion. If you require those companies to recover what is owed to them without giving them a subsidy, surely we would be able to reduce the extraordinarily high sum of money owing. It is related, of course, to us having these extraordinarily high electricity costs, which the Government have promised to bring down, but have failed to deliver on.

I think we should be clear that we are concerned about the level of debt in the market. The reason we want to launch the debt relief scheme is that we want to make sure that we can bring down that stock of debt. Also, for the customers who are in debt, this is an extremely difficult position. We also want to make sure that companies have the tools in place to be able to recover the funding. I think where we differ is that we think that the companies do have an economic incentive to recover money, because ultimately the amount they get in the price cap is fixed, the amount they recover is variable, depending on their behaviour. I am happy to follow up with more detail on that. I agree that there is an issue; I think we have a different approach to trying to resolve it.

Have I misunderstood it, then? If you receive an electricity bill, and it is subject to the price cap, are you saying that the company is not allowed to put on to the bill the costs of unpaid arrears?

What we calculate for everybody is the average cost across the market. You have company A that is good at recovering funding; it will do better than that allowance and it will be able to make more money, so it has an incentive still to do so. Company B, which is doing worse in collecting that revenue, will do worse than that and will face a loss or lower profits. So the incentives on the companies are the same but, yes, we do make an allowance for bad debt, because that is a cost that companies incur.

They have all been doing very badly, haven’t they? You are giving them these incentives, but over the years the amount of debt has gone up to, as you say, £4.5 billion.

We have to recognise that that is partly because the prices have been so high, and much higher than they have been historically. We agree that there is more to do here, but we do not think that removing the debt allowance is the way to tackle it.

You do not think this is indulging a sort of “can’t pay, won’t pay” culture, which is what we had when people did not like paying the community charge? Local authorities have enormous powers to take people to court, to confiscate their goods and so on if they do not pay the council tax. Why shouldn’t electricity companies be using similar powers, which are available, to recover the unpaid debt instead of passing that burden to the responsible, good payers?

There are three things that we think we need to do to bring down debt. First, when you look into the detail of how debt occurs and when it becomes unmanageable for companies and for customers, accurate billing is critical. Interacting with customers early when they get into payment difficulties is also critical. Secondly, we do accept that there is more work for us to do with the industry on how collection is made. A few years ago we had extreme trouble around the forced installation of prepayment meters, and we have worked hard with the industry to move that to a different place. Thirdly, we do think, that given there is a stock of debt, which has grown for customers since the crisis, there is a need to bring in schemes like our debt relief scheme to bring customers back into a conversation with the companies about how they get into a better place, but also to reduce that debt.

You will remember, Sir Christopher, we made recommendations on how to clear the debt, which was to get the network companies to pay for it, which Ofgem did not accept.

Exactly.

Yes. As I said, we accept half of it.

If the Government said that the electricity companies should be given the responsibility for collecting their own debts and that there should not be a levy that everybody else would have to pay, what would be the consequence?

Electricity companies do have the responsibility for collecting their debts, but every company in every sector, including in energy, will always have a residual bad debt. That is what we reflect through the price cap. If we took that away, the economics of the company simply would not stack up and you would find that we were back in the world we were in 2022, with companies not being able to fund themselves and therefore going insolvent.

You describe these things as bad debts. If they were bad debts, they could be written off. In elementary accounting, if you have a bad debt, an irrecoverable debt, you write it off. What we are talking about though, with a lot of this £4.5 billion, is recoverable debt.

Yes, quite. What is reflected on bills is the accounting estimate of that bad debt. It is not all of the debts that get socialised; it is just the debt that cannot be recovered.

Thank you. That moves us neatly on to the remaining questions, from Wera, first on profits and allowances, and then on paying for non-commodity costs and the Ofgem energy system cost review.

How much profit are energy companies allowed to make before they push their costs on to consumer bills? They are making quite a lot of profits that we do not really see. We have heard that there might be as much as £500 per household in profits across the energy system. Could Ofgem be more transparent on where these profits are being made and which parts of the bill they are impacting?

We are very clear about the profits for the companies that we regulate. As I mentioned, the retailers have a regulated margin. We monitor that very closely, and they have been at or below that in the last few years. We also think about the returns that network companies make, and Akshay would be happy to talk about that.

Do you recognise the figure of £500 per household bill?

I think the Unite report adds up some areas of the industry that we regulate and have information on and some areas where we do not have information. Gas producers, for instance, almost certainly have made a lot of profit, particularly through the crisis period, which is why the Government introduced the windfall tax on them, but they are not regulated. We do not regulate the oil and gas sector, so we simply do not have any information on oil production profits. We have good information on energy retail profits. That is about £42 within the price cap per year. We also have pretty good information on the network companies that we regulate. Network charges in the price cap are about £400 in all, and about a third of that would be operating profits. Something like £130 would be operating profit. The one thing I would say in relation to the Unite report, which came up with that £500 figure, is that it can be incredibly misleading to add up the profit numbers across such disparate industries. The reason for that is that any capital-intensive industry, like energy generation or energy networks, will always have a high operating profit margin, because they have to pay interest on the debt and pay back the equity capital that is going into their business, whereas a non-capital-intensive sector, like energy retail, will typically have quite low operating profit margins. That is why we do not measure profitability in networks, for instance, by operating profit margin. We look at the return on the capital that is employed, and that is very tightly regulated by Ofgem.

What did you say? How much profit did the networks make between 2021 and 2025?

You quoted a £500 figure from the price cap. I think that is £500 out of a price cap of, say, £1,700. That was the Unite figure that you quoted, I think. I was saying that we recognise £42 of that is the retail profit.

We have different evidence from different people, and some people were saying, “How do I recognise that?” It seems to me not very clear at all. Since it does impact consumer bills very much, first of all, shouldn’t there be much more transparency? How much profit is made by the generator or by the networks? How much is it? Why is it so complicated to give the consumer or the bill payer a very accurate figure of what profit is being made?

We regularly publish the profit numbers for the companies that we regulate, for the retailers as well as the network companies. We do not price-regulate the power generation sector. We used to collect segmental accounts. We used to require those in the sector to send us segmental accounts for their UK businesses, in order to look at revenues and profitability, but in an effort to try to reduce the administrative and regulatory burden that we are putting on the sector, we agreed to stop collecting that information. We do not regulate the oil and gas production sector at all, so we simply do not have any information on that.

Should we?

I think the point is that it is an international market. If we should, a body bigger than Ofgem would need to do it. This is about international trade, not that I am trying to limit Ofgem’s capability.

Was that a bid for additional resources?

There is an Ofgem review out, Chair, so I will add that to it.

But again, are you confident, from everything that we have heard, that there will not, in future, be excess energy sector profits?

I think we have to recognise, and this comes back to what I said in the opening statement, that as we rely on global markets—remember that our electricity market is linked to Europe, as well as our gas market—prices are going to be set outside the control of Ofgem and outside the control of the UK Government. Those prices, I believe, will continue to be volatile while we are in the sort of geopolitical situation we have been in.

We are particularly talking about the network charges—the network and profits. I want to know more about the network cost and the profits that the network—

Fine. On the gas, the answer is no, but on networks—

On the networks, we are very transparent. Of the £1,700 price cap, £400 is the network charge, and about a third of that £400 is interest and dividends, the cost of capital and the returns to investors. So about £130 out of the £400 would be the operating profit element. I am very keen to stress, Ms Hobhouse, that if you compare that figure, for instance, to the retail figure of £42, you might say, “Why are the networks making a bigger operating profit than the energy retailers?” The reason for that is that the networks are capital-intensive businesses, so they have to pay much bigger interest on their debt and returns to their shareholders, as compared to the energy retailers.

Should that be itemised on your bill particularly to explain that to customers? Rising energy bills are obviously a big political thing. Should that not be explained better and what particular part of the charge is profit?

One thing we are doing right now, which the Chair referred to, is a cost allocation and recovery review. One important strand of that piece of work is transparency in how costs are communicated to customers. You do have a point. We are all bill payers in this room. If we all look at our energy bill, the energy sector is fiendishly complicated to get your head around. We want to take a bit of time to think through what kind of presentation and communication will be most useful for customers, particularly domestic customers. If you get a bill with a lot of itemisation of detail, that in itself can be quite confusing and quite overwhelming.

Some people might be interested.

What we do, though, on every price cap is publish a breakdown of the price cap and the categories within it. They are broad categories, so that includes retail and the regulated retail profit, for example, as well as what is paid on networks, what is paid on policy and so on.

Forgive me if I did not quite hear it, but the consultation you were talking about is coming soon and at pace. Is that correct? Will you consult on policy options on energy systems cost allocation and recovery?

Perhaps I will kick off, and then Akshay may want to come in. We are planning to publish a policy consultation, a further consultation, building on the call for input that we issued last year. In a sense, the way we are charging for this system is changing automatically. The cost base is changing. I come back to some of the earlier questions. It is true that as you transition away from gas, you are moving away from commodity costs, which are variable, and moving to a larger set of fixed costs, so network costs. Indeed, in a sense, once renewables are built, in effect they are fixed costs that we are applying to the system. What we are trying to do with the cost allocation review is to find the best way to allocate that. We are looking at two dimensions. First, by allocating costs in a particular way, can you make the system more efficient? My colleague was talking about time of day, for example, and that will make a difference. The second question—and this is why we are doing this closely with Government—is how you allocate those costs fairly and reasonably, accepting, as we know, that the energy system itself and energy use is not very progressive and some of these costs will have a bigger impact on lower incomes. What we would like to do next is begin to test some of our emerging hypotheses and then have a clearer direction about the way in which we might make this change. That will come into a longer-term answer to some of the questions we have had around standing charges. We are expecting to be able to come out soon and talk about that.

To what extent can Ofgem mandate how the burden of cost is shuffled around, while still allowing retailers flexibility and discretion in recovering costs?

What this review is principally looking at is how we manage the costs that come into a retailer. Quite often, particularly in a volatile market, retailers reflect those costs in the bills that they charge. In a sense, we are looking at the network charging formulae that the system operator administers on our behalf and how that goes into retailers. However, we find that when we make changes to the underlying cost base, that usually is passed on through the retailers, because that is the best way they manage their risks. Akshay, I don’t know if you want to add anything.

At this stage, we are not proposing to mandate tariffs for the retailer. I think our concern, as Jonathan says, is to make sure we send efficient signals to the retailers for efficient use of the network and efficient use of the generation in the system, and that we distribute the costs across households in a fairer way. We had an unprecedented response: 30,000 people responded to our consultation on standing charges and said they did not think that the existing way of distributing those costs, which is to have all households pay an equal share, an equal payment, was fair. So we are going to think about alternative ways that you could distribute these costs. For instance, they could be according to capacity, the peak of the demand, how much current you draw every year from the grid. It could be by reference to the volume of use, how much consumption you have every year. Indeed, it could be to some extent related to the ability to pay, and that is where we are going to need to work very closely with the Government.

Indeed. We always talk about digital literacy. Some people are interested and say, “All right, I will put my washing machine on now,” or even have a remote signal to put it on when energy costs are low, but not everybody is that way inclined, and particularly more vulnerable households are not going to do that. The guys who are digitally literate are usually the better-off people anyway, but how can those other people be protected from falling down on that particular balance of the argument?

I cannot give you a very precise answer, but I think our basic idea is that at least in the beginning, it is a good thing to give people the choice. If people can voluntarily offer flexibility and be rewarded for that, that is how we start to create a mass interest in this field. As long as we send the right kind of incentives for the retailers, the supply companies, to try to automate that as much as possible, we can take the hassle out of this for households. We do not think that energy should be so complicated. If you have to get your head around lots of technical rules, most people will not take it up, so it has to be automatic and simple. At least in the starting period it should be largely voluntary, so that you do not impose it on everybody, and do not penalise people that cannot offer flexibility, but do reward the people who can.

I have been talking to some onshore wind developers, and a point they have made to me is that they have to work out where the best wind is, but they also have to take into account constraints—areas of outstanding natural beauty, and not clashing with aviation, in particular. What is NESO’s approach? What evaluation do you make of where developers should build and where it is viable for them to build?

At a granular level, we don’t say, “This field, but not that field.” One of the key new roles that we are taking on is around the regional energy strategic planning role. That involves working in each of the regions—we have broken Scotland, Wales and England into 11 regions—with the key stakeholders in those regions. We work with the distribution network company, the gas distribution company, local authorities and energy developers in that network to make sure we are developing an energy plan for that region that is consistent with overall national policy objectives, but also with the ambition of that region and the individual players within it. That provides the opportunity to convene the right people and to identify where there are opportunities for, for example, onshore wind. In the move towards Clean Power 2030, and indeed the future evolution of that towards strategic spatial energy planning, we—by “we” I mean GB plc—are getting more definitive around where we want to see different technologies develop. If you look at the Government’s Clean Power 2030 Action Plan, it set out for each major technology type—for example, for onshore wind—and for each part of Great Britain how much onshore wind capacity needed to be developed. We think that, through the strategic spatial energy plan, we will continue to refine that type of advice to Government. That will help individual developers take a view as to, “Okay, this is a region where there is a huge opportunity for onshore wind.” Those evaluations will take into account conditions on the ground, what is coming out of those regional energy plans, deliverability—so community acceptability of infrastructure—natural resources and constraints through the environment. Through both the regional planning and the strategic spatial energy planning, I think individual developers will be getting more advice and guidance on where the system sees different technologies develop over the medium term.

Will that guidance pick up challenges around geographical location? You have touched on this, but I just want to pin you down a little bit. Will the SSEP pick up the needs of aviation and the challenge of where a wind farm can be in relation to radar, for example?

It should pick up all the major environmental or planning constraints that define areas of significant natural beauty or places where you just cannot build something, including where there are restrictions for defence reasons or radar reasons. So, yes. That is a significant evolution in how we do strategic planning from what is done today.

Coming back to an earlier point about constraint costs and batteries, I am trying to get my head around how one could think about it. You said that there is a balance between, “ Is it worth building out the network? That costs so much money,” and, “We would rather occasionally pay off the generators for not running their wind turbines.” What would it look like if a battery system was attached to, say, a big wind farm, which could take off the pressure when the wires get too hot? What would be the cost calculations or benefits if there was energy storage directly attached? For example, when you have a planning application for a very large solar farm plus battery storage—which I hear now is being delayed, which looks a little bit silly, because it might be a benefit to the system—how should one look at battery storage in that context?

In general, battery storage is hugely beneficial to the system. It is an incredibly flexible asset. It can absorb power when needed and it can inject it back into the system. Also, its cost trajectory is coming down, and batteries today are significantly cheaper than they were a number of years ago. Therefore, developers are doing exactly what you say. The number of hybrid projects that are out there is increasing, as developers see, “I have an onshore wind farm. If I connect a battery storage facility to it, that thing is more valuable. I can offer more firm power. I can sell differently.” That is happening. From a system operator’s point of view, we also see that there are locations where having batteries on the system allows us to manage constraints more actively and cheaply.

You could retrofit batteries, if you wished, where you have a lot of constraint costs. Often, you have to turn a wind turbine off. Graeme is no longer in the room, but he was talking about the anger that people feel about wind turbines being there but not operating. Could you not retrofit, rather than building out the network, which might be very expensive? Could you not retrofit battery storage there?

If it would solve the constraint problem, you could. The issue tends to be that once the battery is full, it is full, and then the constraint manifests itself in any event. When you look at the sheer scale of electrons and power that needs to be moved from offshore North sea down to south-east England, batteries are not the solution, in that you need the wires to move the power. There are circumstances where batteries can be helpful in minimising constraints, and we do look at actively deploying them in that way, but the mass deployment of them to offset large-scale network infrastructure is not going to work in that circumstance.

Thank you very much for your evidence this afternoon. That is the end of our session. There are a few things to follow up in writing, which I am sure you will, as you always do.