Welcome to this week’s session of the Energy Security and Net Zero Select Committee. We are delighted to be joined by representatives of the National Energy System Operator. We will be taking evidence from you as part of our work in scrutinising the work of the Department and its arm’s length bodies. Will you please introduce yourselves briefly?

Good afternoon. My name is Fintan Slye. I am the Chief Executive of the National Energy System Operator, or NESO. Kayte O’Neill: Good afternoon. Thanks very much for the invitation to sit with the Committee today. I am Kayte O’Neill, Chief Operating Officer at NESO.

Thank you very much indeed for joining us. You published your “Clean Power 2030” report just a few weeks ago. You were formally established only on 4 October, so you have been very busy. In the report you described clean power by 2030 as a “huge challenge”, requiring a “once in a generation shift in approach and in the pace of delivery”. You said that either of the two pathways tests the limits of feasibility: “Either of these requires a dramatic acceleration in progress compared to anything achieved historically and can only be achieved with a determined focus on pace and a huge collective effort across the industry”. How achievable is the Clean Power 2030 target?

Undoubtedly it is a challenging target to hit clean power by 2030 but we believe that it absolutely is achievable if we can make the acceleration that we talk about in the report. To talk a bit about why we believe that it is achievable, some of the big things in the report are the scale of network infrastructure that needs to be built. The plans for network infrastructure that are set out in the report are consistent with plans that the transmission operators have been working on for the past two years, which were set out in our “Beyond 2030” publication. We have worked with them to make sure that the dates that we have set out are achievable and on what would need to be done to make them achievable. The other very significant thing in the plan is the level of generation infrastructure that needs to be built, but all of the projects that are necessary to fulfil that are already in the connections queue and already have dates pre-2030. What we need to do, which we are happy to talk about today and we are in the process of doing, is reform that connections queue to make sure that we can bring forward the projects that are ready to go, are consistent with the plan and will deliver benefits to the economy and society. It is undoubtedly a hugely ambitious plan that we have set out here. We tried to set out the key things that would need to be true across markets, workforce and skills, supply chain, planning and consenting, and the reforms that are needed to make it achievable. We believe that if we can tackle all of those—and it is not just us; it is a big effort across Government, industry and the regulator—we can achieve clean power by 2030.

You suggest that there might be flexibilities at the margin for some technologies to substitute for others that are not delivering fast enough. How much room for manoeuvre do we really have? Kayte O’Neill: We set out two pathways to 2030 in the plan, as you will have seen. One of those pathways goes harder on renewables and on storage technology—some level of flexibility. The other pathway introduces newer low-carbon dispatchable technologies and a bit more nuclear. You will see that across those pathways some of those technologies will be interchangeable—not necessarily on a one-for-one basis; some technologies provide some outsize value. In our new dispatchable pathway we talked about the potential to introduce CCS and hydrogen projects. Those are fantastic projects in support of a clean power system, if you can get them off the ground for 2030. Equally, you can build more renewables. Those are some of the trade-offs that we describe in the plan.

Do you think that the NESO report is conclusive proof that Clean Power 2030 will bring down bills? If it is not, do you think that there is a possibility that bills will rise? Do you think that system costs will increase or decrease relative to where they are today?

The analysis that we did in the report was to look at what it would take to achieve clean power by 2030 and what were some of the system costs associated with doing that. We set out the analysis and assumptions underpinning all of that in a very transparent way. We compared that with what the cost would be if the transition was not made. We can see that those costs do not go up under a transition to clean power and there is the opportunity for policy intervention or policy choices to be made that would reduce bills. However, what we did not set out to do—it is not our role—was to determine what bills are for consumers. That is a matter for policy. In addition to looking at absolute level of costs in the system, we also looked at the range of volatility, what would happen if there were spikes in prices and so on. The transition to clean power removes, to some extent, the exposure of consumers to volatile international fossil fuel prices.

We had the Minister giving evidence to us last week on our retrofitting homes inquiry. She made a comment on the need to recognise the importance of affordability. She called it a consumer imperative. Do you think that what you are doing is consistent with what Ministers are saying about the importance of keeping bills down?

Absolutely it is important that bills are kept down. NESO was established under the Energy Act and has clear duties around affordability in addition to security of supply and sustainability. We look at that issue and believe that it is important that bills for consumers are kept to a minimum. We are acutely conscious that we are coming off a period of high energy bills as a result of Russia’s illegal invasion of Ukraine and the energy crisis and are therefore trying to make sure that as we go forward we are conscious of the effect of energy prices on people’s household income.

The scale of infrastructure investment between now and 2030 is colossal. Even with that scale of investment, are you confident that consumer bills can be kept down?

Yes, we are. We set out the analysis that underpins that in a robust way. It is important to note in that that you have two things happening. One is a very significant investment programme. That is investment in Great Britain and we need to make sure that we capture the supply chain value for that in terms of jobs and economic value. In addition to the capital investment that is going in, you have a very significant reduction in the operating costs of the system and in particular in the amount of fossil fuel that is needed year to year. There are those two effects that to some extent offset each other. Yes, it is a significant capital investment—it is an investment in Great Britain and in Great Britain’s energy system—and it significantly reduces the operating costs year to year of our energy system. Specifically, it reduces the amount of gas that we need to buy and burn in the power stations.

So lower use of gas is key to getting bills down. Thank you for that.

How will you ensure that the sprint to 2030 does not distract us from developing key infrastructure and technology needed for 2050? Kayte O’Neill: That is a great point and one that we have consistently made ourselves. This is not just about delivering for 2030. We are very focused on what will be needed on the system through the 2030s and beyond to get us to net zero. It is worth saying that when we think about what is required and what we have set out in the Clean Power 2030 plan, it is a moment in time. We already, as part of NESO’s new roles, have a set of obligations that will help us to strategically plan the system way beyond 2030. You might have heard of the strategic spatial energy plan, sometimes referred to as SSEP—sorry to throw the acronym in there. That is NESO’s opportunity on behalf of GB to think about the energy system out to 2040, 2045 and beyond. That is consistent with the role that we have had in planning future energy scenarios, even as the Electricity System Operator, so it features very heavily in our thinking as a strategic planner. It also features very heavily in how we think about things like connections reform. We need to make some material changes to our processes by which folks will engage with the energy system. Connections reform is about ensuring that we can get the right projects that we need for GB growth and for the economy on to the system, that we can connect new demand and maximise the value of that. But again, it is not just a 2030 argument. The other thing is that NESO for the longer term is looking out at how we ensure that we are set up for net zero. One of my roles is ensuring that the lights stay on 24/7/365. We spend a lot of time thinking about ongoing security of supply and resilience of the system—not just what will it take to operate the system today but what will it take to operate the system out in the future.

You touched on SSEP. What is the timescale for that and what kind of consultation will you be engaging in? Kayte O’Neill: Consultation is at the heart of our approach to all of our strategic planning. Last week, or at the beginning of this week, we launched our first consultation on the SSEP. That is a consultation on the methodology that we will use to do this strategic planning. That consultation will run over Christmas and we will publish final methodologies early next year. Over the course of 2025 we will be out developing early versions of that plan. That theme of consultation will serve us right the way throughout 2025, whether that is formally through the governance that we have put in place, which brings multiple stakeholders together nationally, regionally and locally, or by getting out into communities and ensuring that they are on board as we develop those strategic plans. We expect the final version of the SSEP to be delivered in 2026.

You have spoken about carbon capture being important but underdeveloped. What decisions do you need to see from Government to develop that at pace?

We are already starting to see some of those. There was an announcement about Teesside recently. We are seeing the Government push forward with development in the clusters and we are seeing private developers bring forward individual projects in those clusters. Part of doing the work on the Clean Power 2030 advice was to engage to make sure that across all of those developers what we were proposing was realistic and could be delivered by them. We believe that it can. We are seeing those discussions with the clusters progress, and that needs to move forward to get the CCS infrastructure: the infrastructure for the transport and storage of carbon, along with the individual developers building the power stations with the carbon capture technology on them. We need all of those bits to come together.

Thanks very much. We will come back to that point a bit later.

I want to turn specifically to the role of nuclear in both of the pathways. Given its importance as a source of firm power generation for both options, can you talk us through why the deployment targets differ between the two and your thinking behind that? Kayte O’Neill: We agree with you that nuclear is a very important part of the mix. We engaged extensively with stakeholders to get a good sense of what was an appropriate forecast for nuclear as part of the plan. In discussion with Government, the regulator and the nuclear companies themselves, we tried to get an understanding of what we think is most likely to be on the system and what it would take for that to change. In both of the pathways, you see Sizewell and one of the units at Hinkley on the system. We assume some life extension of existing AGRs and we recognise that there is room for movement around that and whatever nuclear can provide in 2030 would be a welcome part of the system mix for sure.

Why does it differ between the two models and what are some of the trade-offs? It would be useful to understand the thinking on the target dispatch number.

The reason is that at the time we were doing the CP30 advice, EDF was still in the process of working through life extensions on their fleet and what that looked like in 2030. There was some uncertainty over where that would land, so we wanted to reflect that because it was not certain and we did not want to nail it down to a specific number, given that they were still in that process.

Has that changed now?

I was going to ask that. Do the extensions that have been announced take you to the number in the new dispatch pathway?

Yes, they do. Back to the earlier discussion on beyond 2030, those life extensions are typically extending some of those plans out to 2030, and therefore we would need to look beyond that as well. But yes, the life extensions are consistent with the plan here and more consistent with the dispatch pathway than the other one.

Have you been able to extend into any commentary beyond the 2030 goal? Life extension of existing plants, if there is no fleet replacement, just pushes the problem further out on long-term sustainability. They cannot be extended forever. Have you looked beyond 2030 at the stacking of extensions without a sufficient pipeline for deployment of new plants?

The issue of life extensions of nuclear plants is a difficult one for EDF and the nuclear safety regulator to work through. We have not looked at what it would look like to stack them. However, as we look beyond 2030 we will see the second unit at Hinkley come on. We know that the Government programme around small modular reactors is now starting to accelerate, with the request for proposals and stuff, and we would hope to see that come out as well. There is a clear ambition for nuclear to be a significant part of the mix as we go into the 2030s. To the earlier discussion, we do not see 2030 as an end in itself. 2030 is the stepping stone into that.

To be super clear on the extension of existing plants, some of the plants are only being extended for an additional year, but you say that the announced extensions take you to the target dispatch number that is in the new dispatch pathway.

I believe so, yes.

Looking at what you said about the new dispatch pathway, I think you indicated, or predicted, that gas would still be used 47% of the time. Have I got that right?

4.7%, maybe.

Okay. I will happily be corrected.

Or hours, is it?

Do you want to check and come back to us?

Sorry, the hours in which gas is used. Gas will still represent just under 5% of the overall energy mix. There may be some hours in which it is used for a small amount. Apologies for the—

No, not at all. So overall, 4.7% of the time. What is it for the other pathway? I could not find that. Kayte O’Neill: In percentage terms it is similarly 5%, but the number of hours for which it runs might be different.

Something that was put to me is that you have estimated a very high gas price and CO2 price and you are predicting continued uncertainty. Why have you gone for only one level? Why have you not put two or three different price levels in for comparison?

The gas price and the carbon price that we picked are consistent with the assumptions that we made when we did our future energy scenarios work, which is an annual publication that we make. It is consulted with over 3,000 stakeholders and we have been doing it for more than 10 years, so it is like our bible for the evolution of the energy system.

When you say “we”, you have only been around for 11 weeks or something.

You are quite right, Chair, apologies. Our predecessor organisation, the Electricity System Operator, has been publishing this. It is a heavily researched piece of work that we do in a very open and transparent way. There is consultation and engagement with over 3,000 stakeholders to develop it. We started our clean power advice and our clean power analysis with those core assumptions transferred from that as a good base of what we believe the price to be. We are conscious that of course the analysis is only as good as the assumptions that you make and the inputs that you put into any model. As part of that, therefore, we flexed some of the core assumptions, including gas price, carbon price and capital costs. In the cost analysis that we did in the main report and in the appendices, we published sensitivities about how it would change the overall costs, with a high and a low range, for the counterfactual and for the two dispatch pathways, because we knew that there was a range that was possible.

The report say 47%, not 4.7%.

Sorry, yes. There are two things that I have confused the Committee on. One is the amount of energy over the course of a year produced from unabated gas-fired generation. In both pathways that is less than 5%. Apologies, I thought that was the 4.7%. However, in the report we also state the percentage of hours in the year where there is some gas generation running, which is the 47%.

So it would still be used in 47% of periods.

At some level. Apologies, that was completely my fault.

Is that the same for both pathways?

No, it is less in the further flex and renewables pathway. It is 15%.

That is helpful. Thank you very much.

Thank you for coming. I have a more general question. The energy transition is not just transitioning away from CO2 or fossil carbons; the whole energy future looks different. We used to have big, centralised generators and now it is all decentralised and little. When you are talking about dispatchable energy, how should one think about this? How do you plan for it and model it, because it is very uncertain? Is there a particular model that you use? Do you look at the weather, for example, and weather patterns? How should one imagine that in order to understand how much dispatchable you need and how much what people call baseload, or is baseload an outdated concept anyway?

That is an excellent question. Let me try to answer it. We use the term “dispatchable” to mean large power stations on the system where we in the control room can tell them what to do and they will move and do it. That is a gas-fired plant, for example. It is dispatchable in that the engineer in the control room can tell that gas-fired power station to run at 750 MW or 850 MW. That is how we used the term “dispatchable” in this. However, you also have the terms “distributed generation” and “large-scale generation”. That typically refers to where on the system it is connected. The distributed generation is smaller. It is connected down in the distribution system and it tends to be autonomous. That means it runs based on its own schedule—perhaps it is tied to an industrial plant—or it runs with the weather, for example if it is a wind farm. On the modelling that we do, we model every hour of the year over an entire year against a set of weather patterns. We look at what is a typical weather year, what portfolio of generation we have and what demand shape we have, and we have a detailed analytical model that runs and solves for every single hour of the year and works out, “In this hour there is so much wind, there is so much solar; therefore, that is how much they give. This is how much I need to get from my nuclear fleet, this is how much will come from gas-fired generation.” The other part of it, which is increasingly a part of our energy mix and part of the energy story, is the demand-side participation in the energy system. In this report—it is one of the things that NESO is strong on doing—we tried to make this not about just assuming what the level of demand is and then matching generation with it. We are seeing if there is flexibility in that demand. Are there things that industrial customers could do to provide that flexibility and therefore get cheaper energy on their side, and the system benefits because it is more flexible as well? All of those things go into an analytic model that models all those out and produces it by year. Then we stress test that against abnormal weather patterns. That does a standard year, but we need to account for what is called the Dunkelflaute effect, which is where you have many days—potentially two weeks—of really still weather. Basically, in the middle of winter, with high pressure sitting over the top of Great Britain, you are going to have really cold days and really still winds, and it is winter so you do not get much out of your solar fleet. If that continues for seven, eight, nine or 10 days, are we absolutely confident that we can keep the lights on? One of the absolutes in both of those pathways and in any analysis that we do is that they meet the security of supply. Did that—

Yes, sort of. It was an outside question, but I wanted to understand.

I am a bit of a geeky engineer at heart, so I am happy to dive into that offline.

I am sure we will come back to some of these things as we go.

I do not believe that the two are inconsistent at all. We have worked through what market frameworks are needed and there is general agreement that the current framework is not suitable for a net zero world and, therefore, it needs to change and evolve. Our assessment of the options that are out there—and in particular at the moment the discussion is on zonal pricing versus national pricing—is that including a locational element like zonal pricing will deliver very significant benefits to consumers. DESNZ and Ofgem have done studies on it and the consumer benefits are tens of billions of pounds in both studies. However, we do need to recognise, of course, that that is a significant change to how the market works. To do that at a time when we are also looking for private capital to make very significant investments, as you say, in renewable technologies, carbon capture and storage or whatever, we need to make sure that the Government ultimately provide a clear pathway on how the market develops. It is not just a question of the wholesale pricing mechanism, that zonal versus national question. You also need to work out how all of the investment support mechanisms work with that—how will contracts for differences work with that, how will the cap-and-floor regime for interconnectors work with that, how will the capacity market work with that?—such that, even though there is a change in the wholesale pricing mechanism, investors have the confidence that they know and understand how that will happen and they can model it, and that, when they model that change with the change in the investment support mechanisms, it is a reasonable risk/return investment for them to make. There are models around the world where zonal pricing and nodal pricing have been used and developed and where renewables investments and generation investments thrive and flourish. This absolutely can be done, but it is really important that it is done in a very measured and sensible way, because—to the very point that you make—a huge amount of capital needs to be committed. It is private capital that is doing the heavy lifting on this Clean Power 2030 plan. We need to make sure that if we are asking investment committees in publicly traded companies to make that commitment, they can make it against a set of market arrangements that they clearly understand and can make sense of, model and trust. That is about the totality of it. The magic will be to change the wholesale mechanism, and the investment support mechanisms that exist around it at the same time, and provide clarity over that transition path. These things take time. Even if a decision was made now to go with zonal, it would likely be four or five years before that happened. What does that transition look like for investments in that period and what is the grandfathering for people who have already made investment decisions around today’s model? We do not want to inadvertently disturb the investment promise that exists in GB. It is a great place to invest because we have investor certainty. It is a difficult issue and I do not believe that our Clean Power 2030 advice is incompatible with a move to zonal pricing, but I believe that you have to manage that transition to zonal pricing, if that is the decision, in a very measured and clear way that brings investors with us.

We have been talking to you about the two pathways. You have already talked about the Government’s announcement on CCS and there is the hydrogen for power announcement as well. Hasn’t that decision effectively been made, or do you still think that there is a choice to be made between the two? Which of the pathways do you recommend or do you think is likely, if my assumption is wrong? Kayte O’Neill: As we set the pathways out in the report, it was never the intention that you had to pick one or the other of them. In fact, what we were hoping to convey is that to some extent there is flexibility or optionality between the pathways, given the scale of the challenge to get to 2030, so that if we make progress on CCS and hydrogen, fantastic, and if we do not, we can build more renewables. That was an important part of us laying out routes to 2030. I do not expect that the Government will pick one pathway or another per se.

That is very helpful. Let me go back to something that Fintan said about not disturbing existing investment. To what extent do investors need certainty one way or the other? Are you confident that having that balance between the two pathways is absolutely fine for giving confidence and not undermining investment confidence?

I think that you can manage the two. Investors are looking at the specifics of the project that they are looking at. In CCS they will look at the overall policy position within the overall energy mix, not just in 2030 but out beyond that, and at the specifics of the arrangements that are being put in place. In the case of CCS it will be in one of the clusters that they are looking at: what are the specifics of the investment proposal or the support proposal that is being put in place for that? We never saw this plan and the pathways as saying, “Select one or the other and then fill up those generation mixes to exactly that.” The purpose of the pathways was to explore where there was optionality or trade-offs. The reality is that when you look at the two pathways, the vast majority is the same across them. In both of them offshore wind does the heavy lifting. There are some differences but the pathways are very similar in the core part of what they are.

That is helpful. Thank you.

Let us come to the difficult issue of planning and consent. That takes a long time and there are delays in the system. Have you had any thoughts on how the planning system could be sped up while not riding roughshod over communities and community consent? Kayte O’Neill: We talked in our report about planning being one of the critical keys that you need to unlock. When we talk to the transition owners, we have seen historically that it can take something like 14 years to get new transmission infrastructure built in this country. You might recall that last year or earlier this year the Electricity Networks Commissioner, Nick Winser, published a report for Government setting out what it would take to accelerate some of that investment. Again, planning was key there. As we understand it, it can be two years or more sitting waiting for planning decisions on a large transmission infrastructure investment. I know that the transmission owners are talking extensively with Government about what it would take to get that down to a reasonable level. From NESO’s point of view, through some of the work that we have done recently out in East Anglia talking to communities who ultimately may host some of this infrastructure, we have the very strong sense of the need to bring communities with you as you talk about planning and consenting in their footprint. That is exactly the challenge that you are describing, not just to achieve clean power—it is not about just hitting 2030—but to be able to unlock this investment in GB. It is important that we can get stuff built but we need to get stuff built in a way that engages communities very early on in the process and brings communities with you through that journey.

We say that all the time. We have said it for a long time. Do you have any ideas how to do that or have you made any proposals to the Government on what they need to do to speed up the planning process? We have a consultation now from the Government. It seems to be one of the biggest blocks to a lot of progress towards net zero. Kayte O’Neill: From our point of view, the biggest tool is having the strategic plans set out and well consulted on throughout the process and then ultimately signed off by Government. We talked earlier about the strategic spatial energy plan. That is the national plan that will look out to 2040 and beyond and give a sense of the entirety of the energy system—where we think about building and connecting new, large-scale infrastructure, whether that is new renewable generation or the network to move power around the country—and throughout that process we will be engaging communities, society and the public more broadly, but particularly the communities that will be hosting it, on the need for that infrastructure. It is a very consultative process that will run over two years. Once that plan is established I hope that it will be a key to reduce planning timelines, because you will not be going back over the need every single time you open up a conversation on the next transmission line or the next bit of generation.

Fintan Slye, when you were at EirGrid there were concerns raised about electricity costs, infrastructure installation, insistence on pylons and the ruling out of underground connections. All of these sound very familiar right now to what is going on in the UK. What are you doing differently this time and what are the lessons that you have learned from your previous experiences on those points and many more about delays and missed renewables targets and so on?

That is an excellent question and points out the fact that there are challenges right around the world in building energy infrastructure. It is not easy to do anywhere. In my time in Ireland when I was with EirGrid, we were looking at a considerable expansion of the electricity transmission grid. I definitely took some learnings away from that, which hopefully I am bringing to the conversation here and bring to how we engage here. One of them is that you need to engage early with communities. Having the conversation once many of the decisions have been taken, and having a consultation about whether a pylon goes in one field or another field, is not the conversation that communities want to have. Communities want to have an earlier conversation about the need for infrastructure at all, what options were considered and what were the trade-offs. That involves conversations about the options for undergrounding things, the options for overhead and the pros and cons of those things. The development here of the SSEP and the regional energy strategic plans is very helpful in that regard. The other piece that we found was a lesson in Ireland was about making sure that there is a form of benefit for communities. It is not a silver bullet, it is not a panacea, it is not paying people off in any way; it is recognising that you are building infrastructure that benefits the country, society and the economy, but it impacts directly on a small subset of people in a community. Acknowledging that in some way through a community benefit scheme—and there are many ways to structure those—is an important part of bringing these projects forward. There are a number of learnings. Hopefully, through my experience in Ireland and elsewhere, we are bringing those to bear on the infrastructure challenges that we see here. As you say, many of the issues are similar, and they are similar in other countries. When we talk to our colleagues and friends in Europe, in other European TSOs, they are seeing the same things on delays with transmission builds and long connection queues to the system. We are seeing all of this.

I would be very interested in some examples of things that have worked at a community level. Perhaps you could write to us about those. Torcuil Crichton I suspect has some further questions.

Hello, Fintan and Kayte. Thanks for sharing your expertise and your evidence. To pick up on the point that Wera was making, isn’t one of the best ways to engage communities to give them a direct share in the profit flowing through the pylons? Isn’t one of the lessons from Ireland and Denmark and Germany that the larger the community share of these projects, the more they are accepted?

That is one of the options. It works better for renewable or generation facilities where there is a profit stream coming out of it. I know that some developers here talk about doing that and there are some ways that you can potentially do that at a community level, which is potentially really powerful. Those community energy schemes potentially provide a way to unlock the deployment of some of the renewable resource that we need. It is harder to structure it in that way for transmission because that profit share thing is not quite—the experience in Ireland was a proposal that had two elements to it. For linear infrastructure, a line or whatever, you created a fund and it was basically a pounds-per-kilometre fund. One of the key things was that it was not the company that decided how that money was spent in the community; it was an established group of trustees within that community who could themselves decide for their community what matters and where it should go. That is one element. The other element was a payment directly to homeowners who were within a certain distance of a transmission line. For generation facilities there tended to be different approaches by different developers. It did help. Again, it is not a silver bullet. I have talked to colleagues around Europe, and different schemes work in different ways in different jurisdictions. It is about finding the right one that fits for the particular communities here.

Can I ask about connection reform? First, when we define connection reform, it is basically the rationing of access to the distribution network—is that really what it is? Kayte O’Neill: I would describe connections reform in two parts. One is ensuring that we have the right processes in place to be able to bring connections that are ready and are needed or strategically aligned with what GB needs and get them on to the system. That is part one of connections reform. The other part of connections reform, as we have talked a bit about, is ensuring that the network exists to be able to move that power around the country to where demand is. It is not about restricting access. I will say, though, that the queue as it currently stands is massively oversubscribed. Our system today is about a 50 GW system and there are 750 GW of connection applications currently in the queue. So I would not describe it as restricting access; I would describe it as ensuring that we can connect what is needed and what is ready.

But instead of allowing the price mechanism, for example, to be used to prioritise applications for connections, you as a regulator are basically imposing your decisions. That is why I use the expression “rationing”. Essentially, you are taking the decisions as to who can get to the top of the queue, and you are doing it not on the basis of price but on the basis of other factors, many of which may not be disclosed. Kayte O’Neill: It is really important—and it is the case today and will be the case going forward—that connections processes, rules and codes are completely transparent, and that there is nothing going on behind the scenes about decisions we are taking about what connects and what does not connect to the grid. Historically we have had purely a first come, first served process. The next person in the queue to apply is the next person that gets connected. Currently that queue is so long and there is so much in the queue that some of the offers for connection are out in the back end of the 2030s. That is just because of the sheer volume of projects that came before the last project on a first come, first served basis. Going forward, the relative position of projects in the queue is retained. We are not throwing the whole queue up in the air. However, we are removing from the queue projects that are speculative, have no intention ever of connecting and are simply getting in the way of other good projects that are sitting behind them in the queue.

Yesterday you made a fresh announcement that revised some earlier proposals. What do you think the impact is of that and why did you make those revisions? Kayte O’Neill: The decisions that we set out yesterday were a positive set of decisions very much grounded in the feedback that we have had from stakeholders through the extensive consultation that we have done on these reforms. These reforms are maybe one-in-10-year type reforms and it is important that we consulted and heard from developers what they need to ensure certainty and confidence in the processes. The biggest change that we announced yesterday was on ensuring that projects that are already proven to be good projects—they are well-developed, people have investment money in them and they have applied for and been granted planning permission—can be assured entry into the queue. That was the big change that we made yesterday, to say: “If you have been granted planning permission, your place in the queue is assured.”

There are other elements of that as well. There is concern being expressed that a lot of projects will still not get past the starting line and past your regulations. For example, your report says that 90% of solar projects should be allocated to the distribution network. Why 90% and not 100%? Kayte O’Neill: Projects get allocated on to the system where they are appropriately sized to be located. Local solar, community solar, solar developments that are of a size appropriate to connect to the distribution network, should connect to the distribution network, reserving space on the transmission network for the bigger projects that need to connect at that level.

Shouldn’t we just be making a bigger distribution network so that it covers the country in the same way as the gas grid does?

Perhaps I can make a point of clarification. It is not that 90% will be allocated to the distribution network and the other 10% will go away. The other 10% is connecting to the transmission network. That is based on the size and scale of the queue that we have seen to date. Solar projects are typically of a size and scale that will connect to the distribution network. There are some big projects—what we would call “utility-scale solar”—that would connect to the transmission network.

Like the one that was swept away by Storm Darragh in Anglesey? That was connected to the main distribution network.

I do not know the specifics of that one.

You didn’t see the pictures? It is a complete scene of carnage. Was it 19 acres of wind farm completely destroyed? Anyway, I am sure that the Chinese manufacturers will benefit from being able to renew all that. Can I ask you about how precisely you will determine which projects are strategically aligned? Who will decide that? Will somebody in your office decide it or will there be criteria so that people know in advance? Kayte O’Neill: Strategic alignment will be alignment, in the first instance, to the Government’s clean power action plan, so aligned to how much that plan says we need of any given technology in any given location. Over time, strategic alignment will be alignment to future plans. The SSEP then will pick up and—

So the man in Whitehall knows best. That is really what we are talking about, isn’t it? Kayte O’Neill: No, what is important is that we connect to the grid the level of infrastructure that is needed to meet clean power and to bring economic benefit and growth to GB. There is a limit to how much generation connection we need on the system, whether it is through the clean power plan or through future strategic plans. It is important that we send that signal of how much of a given technology is needed and that demand is uncapped so that we can bring as much demand on to the system as possible.

Can I ask one more question?

We are going to move on, so this is your last one.

On the timescale, I am told that originally you said that you might not be able to indicate which projects were needed until the end of 2025 or early 2026. Is that still the situation or have you been able to advance that timetable? That length of wait is very bad for investors.

Through things such as the announcements we made yesterday we have been able to give greater certainty to the projects that definitely will be able to connect that they will be in the queue. Projects that have planning permission know that they will be in the queue and they can continue through their development process. That is clear. That is one of the big benefits of the announcement made yesterday. More broadly, we need to follow due process and ensure that we follow the codes and the rules and that as we make these changes—these reforms to the processes—we do it in the proper way. That means there are timelines set out in codes that we must follow. Those timelines will see us take the majority of 2025. It will be clear to projects that are ready, that meet the readiness criteria, which are very transparently set out, that have the planning permission that they need and that are in line with the level of connection that will be set out in the clean power plan that they should have a place in the queue.

To confirm absolutely something you just said about projects with planning consent, can you confirm that any project with planning consent by May 2025 will be shielded from the impact of your grid connections reforms?

That is right. If the planning application was submitted before 20 December, which is when we will submit our final, fully formed proposal to Ofgem, and if that planning permission is granted by May, the project will be in the queue.

On something else I think you said, can you confirm absolutely that no real projects will be removed following the revisions yesterday?

Projects that are ready, which means that they can demonstrate that they have met the milestones that are set out in the readiness criteria, have planning permission and are aligned with need, will have a place at what we call gate 2 in the queue. They will have a firm connection offer in a firm location for a firm level of power. Other projects—those, for example, that may not meet the readiness criteria and may not be at gate 2, but may sit at gate 1, so they are still waiting and can come forward as and when they are ready to do so—will not be removed from the queue if they are good projects.

A project could be at gate 1 and be removed.

A project could be at gate 1 and if it does not meet its milestones, if it cannot demonstrate that it is intending to connect to the system, it would ultimately be removed.

Going back to something that Chris Chope said, you have said already that offshore wind is challenging and you have two different targets for the two different pathways, so why are you limiting solar?

We are proposing a trebling of solar in the CP30 plan. That feels like a significant increase in the level of solar to be connected to the system. It does not feel like a limitation.

But Solar Energy UK are saying that generation by 2030 could be 59.6 GW. Your target is 47.4 GW. That is 15% to 20% lower.

For all the technologies that are set out in the plan, as we went around and engaged with a vast multitude of stakeholders we received different perspectives on the level of what is possible and what might come forward. We are confident that the 47 GW that we have set out in the plan is a meaningful increase. We want that solar generation on the system. It is an important part of the system. It is the level that we came to based on our analysis, our modelling, and extensive engagement with stakeholders.

Do you accept that solar is one of the two cheapest forms of generation along with onshore wind?

Yes, and it is a very important technology for us.

Let me follow on from what Chris was saying and turn back to community energy and community energy generation. My new best friends, Jürgen Maier and Michael Shanks, have both said that they want to see 8 GW of power coming from community generation, yet your connection plans do not mention community energy at all.

Our plans have significant amounts of onshore wind and solar, as we have just discussed, and typically those are the types of projects that would become community energy projects. When we think about those generation assets, we think about them as a generation type, and community energy is an ownership structure rather than any assessment of the generation. We want onshore wind and we want solar. We feel very strongly, and as NESO I hope we are demonstrating that we feel very strongly, about the importance of bringing communities with us as we go on this energy transition. We think community energy projects are a great way of doing that; we just do not call them out as community energy projects here. Consistent with all other technology types, we articulate how much of any given technology we think is needed.

Why not? If you are winnowing out the zombie projects but keeping your queue—your gateways 1 and 2—if you do not designate community energy and you do not give community energy projects a derogation to get connected quicker, they will not get connected at all, because they do not have the professional back-up of the legal teams or the technical teams that corporations have and they are competing with corporations to get on the grid.

Yes, absolutely. It is really important that as we develop these connection reforms and implement them, they are absolutely fair and they do not in any way either disincentivise or favour any particular technology type or particular project. It is an important part of the rules of those processes. That said, we are working hard to make sure that we do not inadvertently disincentivise community energy projects. With that in mind we have spent a lot of time engaging with developers who are developing those projects and organisations who represent those sorts of projects to ensure that we hear their voices and play that into the consultation feedback that we get and then respond to it accordingly.

But if you categorise them as a technological solution rather than an ownership model you are disadvantaging them. Chris talked about the man from Whitehall deciding. Do you need a signal from Jürgen and from Shanks that they want community energy projects to have a derogation to skip the queue, for lack of better words—to be given priority? I can tell you that without supporting communities through community energy projects, getting support for the other stuff will be very difficult.

Certainly to the extent that we were sent that signal by Government, then of course that is a signal that we would follow. The team at DESNZ has worked closely with us as well in developing these reform proposals. We spend a lot of time, as I say, talking about communities. We also spend a lot of time talking about demand projects and how we ensure that we do not get in the way of those getting connected to the grid. The conversations are happening. Under the current framework, as I described, we do not favour particular technologies or ownership models, but I absolutely hear the point about the importance of communities in this regard.

Thank you. Finally, how will you ensure that all these regional energy strategic planners engage with communities? Do you need to signal on that too or do you have a system to do that?

Community engagement is at the very heart of the regional energy strategic planners, this new role that NESO will fulfil. We do not need any further signal than the mandate that has been set out for us in establishing that role. These teams will sit out in the regions. We will stand up new offices and new teams and we will recruit those teams from the local area where possible. We will recruit folks who understand local authorities, the communities that they are operating in and the dynamics of that particular region, and can help us translate that into regional ambitions, regional plans and plans that ultimately can come together to align with the national plan. It is absolutely at the heart of how we are setting ourselves up.

Taking a step back to the discussion that Chris was taking us through the questions on, which goes back to the changes you announced yesterday around connections reforms, I want to understand a bit more about the relationship between capping the number of projects that can hold connections for a year with the need for CfDs to be competitive and how you have weighed up those tensions.

Maybe say a little bit more about where you see the tension, because I am not sure that there is a—maybe I misunderstood the question, sorry.

The idea that to have really competitive contracts for difference auctions you need a wide number of businesses bidding into those auctions. Through the capping of potential projects within a year, the risk is that you may end up reducing the competition that takes place that you are able to pick from through a CfD auction. You may not think that is a risk.

Projects are only eligible to enter a CfD auction if they hold a connection date in the delivery year for that auction, so that is limiting the potential number of bidders.

It should not do, and we will take that away and make sure that there is not an unintended consequence. There is no intention here to try to make CfD auctions less competitive or to remove that competitive tension. I do not think there is but we will take that away. It is a very valid question, so thank you.

I appreciate that.

I want to go back to solar briefly. One of the concerns raised is what is happening in Lincolnshire and Nottinghamshire in zone 9. We are told that there are 4 GW of solar farms that could still lose their grid connections. What is the logic of replacing active projects with phantom projects that do not exist? In addition, in your plan you identify fossil fuel projects that do not exist and just to add to the mix there is 1.5 GW of solar identified for London. It is difficult to see where that will go. There seem to be some inconsistencies here and some gaps in the logic.

I cannot comment on the specific projects that you raise, but the approach that we have taken essentially, as I said, is that it is important that we retain the value of the existing queue, the order in which projects have already applied to the existing queue, and we use that order to determine the volume of any given technology by region by understanding what was already in the queue in that area. Good projects should not be getting stopped by phantom projects, to use your language, Chair. The very reforms that we have created are absolutely intended to ensure that those phantom projects, or zombie projects as you might have heard us refer to them previously, cannot stay in the queue because they cannot demonstrate that they fulfil the requirements to either be in the queue in the first place or stay in the queue if they are not progressing. We should see that progress of projects coming forward. You will remember that I talked about massive oversubscription and lots of the projects in the queue that we think are speculative. These reforms will see them exit, and as they exit good projects that are sitting behind them that are ready and would like to come forward will be able to move forward and have earlier connection dates.

Okay. We may come back to you in writing.

Turning to the question of demand flexibility, the Government have a current target of 75% of homes and 69% of small businesses having smart meters by the end of 2025. Do you think that is enough for demand flexibility to grow by four to five times current levels, which you say we need by 2030?

The smart meter roll-out is certainly a complex one. From our point of view, “as many homes as soon as possible” is the way I would describe it. With smart metering we will have access to data that will help us to understand what it will take to unlock that level of demand-side flexibility. The industry will be able to respond to that and create, innovate, develop new tools and services by which consumers can absolutely engage, bring that demand flexibility to the fore, provide value to the system and be rewarded for it accordingly. You need smart metering for that. You need half-hourly metering as well. From our perspective, we want both of those things as quickly as possible.

If you are looking for that sort of innovation in the consumer retail market, what regulatory changes do you think you will need? You talk about customers needing to be rewarded. What regulatory changes would you need for that to happen so they can be passed to consumers in the form of lower electricity bills?

We need the suppliers to have the confidence that the regulations and the market structures are in place for them to be able to invest in developing those products and services confidently and that they can then onboard customers to them. For our part, there is certainly something that we can do to help unlock demand flexibility as well. It is not all on suppliers. You might know that over the last couple of winters we ran a service called the demand flexibility service. I do not know whether any of you heard about it, but we had 2.6 million customers, consumers and businesses sign up to the demand flexibility service. They are sending us the signal that they want to participate. There is an appetite to provide those services. We were able to construct something that was attractive. We were able to get the suppliers on board to work with us to offer that service to their customers and from a system operability perspective we saw great value from it. So it is not just us and it is not just the suppliers, but there is certainly a lot to do to unlock the levels of demand flex that we talk about in our report.

Could you be a bit more specific about what the regulatory changes are? What are you asking Government to change about the regulations to make this happen? You sort of talked around what might be possible and how it is possible to construct something, but not what the changes are.

I will start by saying that I am not an expert on regulation for the retail industry, but I think one of the critical things is finding a pathway to be able to introduce effective time-of-use tariffs, and that requires the meters to be installed and half-hourly settlement on metering. Quick access to those things will be critical to being able to design and implement those tariffs. I am sure the retail suppliers will have a much more comprehensive list of regulatory changes they would like to see.

Finally, “Future Energy Scenarios 2024” identifies several key actions needed to realise the potential of vehicle-to-grid technology. Given that 2030 is only five years away, which of those are the highest priority?

Certainly vehicle-to-grid is one of the best sources of flexibility that we saw and you can see that in the clean power advice. It is the biggest chunk in the graph when you look at vehicle-to-grid flexibility. You need the deployment of the fleet of EVs and the charging infrastructure, but you also need the digital infrastructure such that they can communicate—that piece around making it easy for domestic customers to hook up, get an EV tariff with an EV supplier, and all of that information interchange. We have an initiative called digital system integration—DSI—which is about trying to develop a digital spine through the energy industry that will allow that exchange of information to be much easier and much more transparent. On vehicle-to-grid, we have seen great take-up for the fleet that is there in smart charging and we have talked to some of the suppliers. I was with one of them only yesterday talking about the brilliant algorithms that they have that will do that. That is one part of the flexibility, but building that out to be truly vehicle-to-grid and the two-way communication requires a step change in people’s attitude to what that means for their vehicle and their car—what it will do for their battery—but also in the technology to get the power through. You need the smart meters, and you need the infrastructure in there as well. We have seen a lot of progress on the smart charging stuff, which is great, but the step change will be to get the real vehicle-to-grid going.

Can we talk a bit about industrial electrification? In “Future Energy Scenarios 2024”, in the organisation’s previous guise, you called for a review of the electricity and gas retail price difference to encourage industry to electrify. Are you of the view that you should go a step further and call for a review, and say that you think the policy costs for electricity should go to general taxation? Do you have a view on that question?

No, not specifically on that question, but certainly the question of how policy costs are divided between the two does need to be looked at. We are talking to the industrial representative groups about what it would take to electrify—not only that, but how, as they do that, they can provide more flexibility back to the system. I had a great conversation with someone only the other day about how we can think more about demand flexibility from the perspective of the demand customer whose main business is not energy or providing energy. It may be a supermarket selling stuff off the shelves, but it has huge levels of demand, so how do we get that demand flexibility in place? I do not think we have a firm issue on the policy question of moving costs into taxation.

Your example there is a good one to pick up on because, for example, Denmark now has a limited network access tariff that offers large energy users with flexible demand substantial discounts. Is that the kind of thing that you would like to see us use here with industrial users?

I do not know the specifics of the tariff you are talking about in Denmark but certainly that type of thing is potentially very interesting. I think that one of the things we potentially have to get better at is finding ways that the flexibility of the tariff structures can work not just for the electricity system in providing the benefits to make the system’s overall costs lower, but for the individual industry or whatever. I will go back to my example of the supermarket. They have loads of chillers that they can turn off but only for short periods and only if they keep the temperature in the chiller within a certain band. They are absolutely intolerant to going outside of that band because they have loads of health and safety regulations, absolutely appropriately, around that. The tariff structure that might work for them may be different from the tariff structure that works for a new AI data centre, for example. Being flexible in how we think about that is important.

Finally, what role do you expect thermal batteries to play and what is the trade-off with other forms of technology for industrial users?

Batteries in general, or are you thinking about thermal batteries for heat storage? Josh MacAlister: Heat storage.

I think that potentially they do have a role. I am not sure that they have hit commercial scale on the electricity system. They may have a very interesting role, though, when you think about heat networks and then you think about how that integrates with the electricity system. Having something that bridges that in a flexible way could potentially be very useful. At the moment we are seeing lithium ion winning the race on batteries on the electricity system. There is a lot of innovation and investment going into other battery technologies—flow-based batteries and so on. I am sure some of them will come forward and compete with lithium ion batteries, but heat storage and heat batteries are probably at the moment the most obvious use in that link to district heat systems and how they might be deployed in a way that is sympathetic to the electricity system.

Last week we asked questions of the Minister about the future role of hydrogen. “Future Energy Scenarios 2024” envisaged a range of possible uses of hydrogen by 2050. When do you think we need to make choices and prioritise between those different possible uses?

I think that hydrogen will definitely play a role in the energy system. I do not think, though, there is one decision around hydrogen; there is a multiplicity of decisions. You talk about the range of uses that it can have. The one that has got the most airtime and discussion is the role of hydrogen in domestic heat. How you decarbonise domestic heat in Great Britain is one of the trickier issues in the transition to net zero. How you do that and what role, if any, hydrogen plays in that is a decision that will need to be made in the next number of years by Government as they think about the future role of gas, the gas networks and the hydrogen system. As I say, hydrogen will play a role. There is certainly a role in decarbonising the hard-to-abate sectors and potentially some of the heavy transport sectors as well. You can see hydrogen playing a role there. It could also play a role in the electricity system specifically around storage, to the extent that you use hydrogen as a storage vector, potentially created using electrolysis at times of excess electricity generation. You could potentially store it in some of the salt caverns or disused oil and gas fields and then re-pump it out and into CCGTs. That is one other use—as storage in electricity—and the other one I talked about is around heat. You asked about decision times. There are ongoing discussions and negotiations around hydrogen in the clusters that are going on at the moment and I think those will continue. I do not think there is a decision about at what point we go all in on hydrogen. Sorry, just on hydrogen for heat, there is heating people’s homes, and that is really difficult, but there are also heat networks. You could potentially see hydrogen playing a role in running the heat networks and being the source of fuel for those on a district heating basis.

You have run through the different options, but would you not agree that at some point you have to take a strategic overview of those options? There will be a finite amount of green hydrogen that we can produce, so don’t we need at some point to make a choice and say, “We are prioritising the use of hydrogen for this, this and this”? If you just make decisions as you go on each possible use, doesn’t that leave you possibly not having taken that strategic overview?

I agree and I think there are maybe two bits to it. In a lot of those cases, it is still at the point of investing to prove the technology. Take the electricity storage example I gave you: the round-trip economics on that at the moment are pretty horrible in terms of the losses as you convert between different energy vectors, although investment and commercialisation, not just here in GB but around the world, should drive down those costs. We saw it with other technologies, great examples being offshore wind and batteries. The strategic overlay piece comes through in the strategic spatial energy plan, because that provides the opportunity to step back and look at what are the big-ticket things that GB needs as we develop the energy system out to, as Kayte said, 2040, 2045 and 2050. That is the place where you would explore the electrolyser capacity we need, and the uses of that hydrogen. Is it going into storage? How much of it is going into the international market for sale or whatever? The SSEP provides a strategic overlay that allows you to assess the different options at a high level.

You have possibly partly answered my next question, but what decisions do we need from Government now to build up the capacity for green hydrogen production to meet our net zero targets?

In my head there are three things. One is continuing to explore hydrogen in the clusters—that work that is already under way that should ultimately lead to commercialisation and driving down cost. That is under way and I do not know that there is a big decision needed. The second is the electrolyser piece. I think that needs the whole-system assessment, because it interlinks between how you think about network, different generation resources and security of supply. You need that SSEP assessment, which will feed into Government through to the end of next year. At the end of 2026 we will have pathways or options under SSEP developed, which should enable that discussion. The final piece in terms of a decision by Government is the role of hydrogen for heat. That is probably a distinct policy decision that is needed over the next number of years.

I have two further questions with hopefully fairly quick answers. Do we need to limit our future use of blue hydrogen given that that would mean continued exposure to international gas prices, and the risk of methane leakage?

You want to see a transition from blue to green. The use of blue hydrogen enables you to build the supply chains around it while the deployment of green hydrogen is in a nascent state, but you would see the level of green hydrogen production rising and the level of blue hydrogen—

You would not set a limit at this point and say, “This is what the limit should be at this point in time”?

I do not think so. I do not think that we have the analysis that would say that.

Do you agree with the Climate Change Committee that from 2025 the Government should prohibit new buildings from connecting to the gas grid?

That is a policy question for Government. I do not think we have a particular view on what that should be.

Thank you very much. We will be voting soon, so we will try to get through the remaining questions before that. What decisions do you need from the Government, and when, to assume your full responsibilities for planning hydrogen transport and storage?

It is a continuing, ongoing conversation, and we have been working closely with the Government on the appropriate time for us to pick up that role. That is a little way down the road—I think 2026. We are trying to work through exactly what that role looks like and, therefore, what we would need from the Government along the way to help us pick up that role and have the full capability and be clear on what that role is going forward. Sitting here right now, I do not have a view on exactly what decisions and what timeline, but the Government engaged extensively with us on the value of having NESO undertake this role, and what we can learn from where we have strategic planning roles in other vectors and set ourselves up appropriately for that.

You have called for more clarity on how hydrogen pipelines will be built and gas networks repurposed. What are the most urgent questions?

As we think about developing a hydrogen network, there is a trade-off. There is a gas network there and that can transport gas and they have done tests and most of it can also transport hydrogen. The question is how you manage that transition while we still rely on the gas network for providing gas to power stations, to people’s homes to heat them, and to industry. To the extent that you repurpose some of that gas grid and carve it out of the main transmission system, the NTS, and designate it as a hydrogen pipeline, you have taken something out of the gas grid. We have an ongoing discussion with National Gas Transmission and the gas networks about how you do that. You do not want to overbuild and build another pipeline if you are actually taking one out, but you cannot just assume that you can remove a pipeline from the gas network and designate it as hydrogen if that would have an undue impact on security of supply. It is an ongoing discussion and analysis that we are doing in conjunction with National Gas and the gas businesses. That will come through in things like the gas network needs analysis report and National Gas will come back with options for that as well.

What are the immediate next steps to increase hydrogen storage capacity, given that salt caverns can take 12 years to develop, or is this going to be another ongoing discussion?

I think it comes back to the earlier conversation about having a strategic view of how much storage of hydrogen we need. That needs the SSEP to do that assessment. We see hydrogen playing a role in the electricity system and in the energy system as a whole, but we need to do that strategic assessment overall before you could say whether it is a storage facility on the size and scale of Rough or something significantly smaller, like one of the ones that are there today.

Thank you very much for your answers about hydrogen. Let me return to something we have been asking a lot about because we have investors and developers who are extremely concerned. Kayte O’Neill, I think you said that projects with planning at gate 2 would be secure, but in your report it is only land and grid that are relevant for gate 2. Have you changed that now to include planning?

Yes. We consulted on the methodologies that we had proposed for connections reform, and we received a huge amount of feedback through that consultation process. The open letter that we published yesterday sets out how we have taken that feedback on board and are making some revisions to our proposals. That change, locking in projects with planning permission, was a change that we announced in that letter yesterday.

They have to have planning permission.

Indeed.

Right. Thank you for clearing that up.

I have received a letter from somebody called Bill Rees, whom I do not know but he is the managing director of Enso Energy. He says: “The ‘Clean Power 2030’ report does not take account of the benefits of co-located sites, with each technology considered separately. Co-location optimises grid use and thereby reduces costs for consumers, networks and investors. Ignoring this could double the expense and scarce grid infrastructure required to achieve the clean power target.” Can you outline the reasons for co-location not being recognised in the “Clean Power 2030” report, please?

We have not ignored co-location, but to ensure that we are clear on what technologies are needed where, and then that we can get those technologies connected to the grid, we had to take a view about how to think about any hybrid connection—connections where there are two technologies co-located—and we took the decision to consider whichever was the primary generating source as the main source of that technology. It is not that we did not think about it, but we had to have a way to—

But was that a wise decision bearing in mind the point that he makes, that the consequence of doing that is that it may well add to the cost of transmission?

We do support and enable co-located facilities. A great example is batteries at wind farm sites. Several of the current offshore wind farm developers are looking at co-locating significant scale batteries alongside that in a hybrid approach. We are very much in favour of that and, as Kayte said, you still need the transmission capacity there. To the extent that that can be leveraged for more effect, then that is great. The other part is back to the earlier conversation about connections and the queue. We need to be fair, open and transparent with people around how they progress through the queue. We are not throwing out the existing queue, so it is the projects that are in there. To the extent there are developers in there who have applications that leverage co-location, that is absolutely great. There are great examples where we are working with developers on co-located projects, with some really terrific examples of batteries connecting near wind farms.

I will come back to one more question to which I do not think I had an answer: where is this 1.5 GW of solar in London going to be? No one can think of a site where it could be. It is a lot of rooftops.

It is a lot of rooftops. I cannot point to the precise location. NESO are not doing any of this work by ourselves. All this work is being done with the local network companies, so with UKPN in London. To the extent that London cannot accommodate that level of solar, the way the rules work is that that can shift between adjacent regions. You would build more of another technology in London and move some of that capacity to the adjacent region, so it is not completely binary or completely fixed. We have built some flexibility into the process.

Yes. I think that might pose more questions than it answers to developers who are worried about what is indicated in the regions around the country. We may well write to you about that. Similarly, if there are things that you would like to write to us about following this session, please do. With that, thank you, Kayte O’Neill and Fintan Slye, for your evidence this afternoon.