Welcome to this afternoon’s session of the Energy Security and Net Zero Select Committee. This is the opening session of the second half of the Committee’s inquiry on the cost of energy. The sessions during the first half of the inquiry focused on supporting consumers with their energy bills. The second half of the inquiry will look at how we tackle the causes of high energy costs. Today we will focus on wholesale electricity market reform, the role of gas and market incentives. Welcome to our first panel; could you introduce yourselves please, starting on this side?

Hello. My name is Tom Edwards. I am a Principal Modeller at Cornwall Insight.

I am Susie Elks and I am a Senior Policy Adviser at E3G, and I lead the work on the UK electricity policy.

I am Michael Grubb, Professor of Energy and Climate Change at UCL.

Thank you all very much for joining us. Before handing over to my colleagues I will start with some questions about the interplay between the generating mix and wholesale electricity market regulation and their impact on bills, including by comparison between Great Britain and our neighbours. Perhaps starting with Michael Grubb: why are electricity prices so variable between the UK and our European neighbours?

There are several factors. First and foremost, the UK electricity market is more directly exposed to the cost of gas than most of the countries in Europe, which have a slightly broader mix of sources at the margin. Therefore, although the UK is now more than half of non-fossil generation, according to the estimates it is still gas that sets the price anywhere between 90% and 98% of the time. That is a key factor. Historically we have spread some of the other costs of the system, including enhanced investment—arguably to make up for previous inadequacy in transmission and policy costs—equally across business and consumers. Finally, gas prices in the UK tend to be somewhat higher than on the continent. Britain obviously is an island. There are perhaps elements of we have less liquid energy markets also because of the smaller scale of the system.

Thank you. Susie Elks, for over a decade the UK has had the most expensive electricity prices in Europe certainly. Is that due to fuel costs, regulatory costs or is it simply inefficiency in our energy sector?

I do not think we can just point to one thing here. I think it is a death by a thousand cuts across the system. One thing I would like to point to as well—which is not to say that our bills are not high in the UK, but it is just to put them into context—is that if you compare our bills with Europe purely in euros we do have some of the most expensive in Europe. I think the UK and Germany come in as the two most expensive. If you look in terms of purchase power, so as a household how much it can buy with its income, we are not quite as high. We are still very high, but we may become more like the top 10. That is important because, if you look in terms of euros, we will need to lower electricity bills by about £270 per household to hit the European average. If you look at purchase power we need to lower electricity bills by £50 to hit the European average. That is not to say that bills are not too high; it is just to say that we need to look in that context that bills are currently high across Europe. They are high in the UK, but this is a problem across Europe. In terms of why UK bills are particularly high, I would like to point to a few points in addition to what Michael looked at. One is the cost of energy debt on bills at the moment. UK households have £4.4 billion-worth of energy debt. That means for a household that is not in energy debt its bills are also increased because of this. In the next price cap control, so Q1 of 2026, £150 of a household’s bill that is not in energy debt is because of suppliers managing the cost of energy debt. That is as substantial as some of the factors of a bill that get a lot of attention. It is one of those things that is hard to compare across Europe but that is a very substantial one that we need to look at. There are also questions around the amount of levies and taxes that we put on our bills in the UK. About 15% of an electricity bill is currently money that either the Treasury makes on bills or extra costs that it has levied on top of bills. In some other countries they have the exact opposite where electricity bills are subsidised rather than levying extra costs on them. Those are two points that I would like to highlight as particularly big factors at the moment.

Thank you. What did you make of the Committee’s recommendation to use the profits made under the RIIO-2 system to cover that consumer debt?

I really liked that recommendation. I am not sure exactly how we try to recover those costs. I think traditionally if networks have over-made money in a price control it will often be about trying to lower the costs in the next price control to try to claw that back rather than specifically trying to go after the money. I would be interested in how that could work but I think that kind of ambitious, transformative proposal is what is needed. Baringa has projected it is going to go to £6 billion at the end of next year. This is not something that is going to go away. This needs big political will to sort it, so I was very glad to see that proposal.

Do you think Ofgem’s approach is going to deliver to its objectives in reducing debt?

I think it has the levers to be able to make sure that debt does not grow further. That is a very difficult area, though, because it is basically about making it harder for people into energy debt, which has wider issues. If you are a household that is struggling, the rules that Ofgem could introduce are not going to be pleasant. It does hold those levers and there is a question there of balance. In terms of removing the £4 billion of energy debt that now exists, I don’t think that Ofgem has the levers to sort that. It can take those costs, and it can spread them over the existing consumer base. That is what it has just done. It has taken £500 million off the energy debt but that is part of why, for a normal household, £150 of its bill is now the cost of energy debt. The levers to sort it do sit with Treasury and the Government rather than with Ofgem.

Tom Edwards, can the increasing share of renewables significantly bring down bills without radical reform to the regulation of the wholesale electricity market?

Because the marginal cost of renewables is low, or close to zero, when they are running we would expect that, under the current wholesale market design of marginal pricing, the more renewables we are running the lower the wholesale price would come out. However, that does not account for things such as the CfD. The contracts for difference mechanism is a two-way CfD that insulates those generators against the price, so if the price falls, the cost to the consumer increases to offset that reduction. While we think that wholesale prices will fall, we do think the CfD will offset some of that reduction and, therefore, there is a lag in how falling wholesale prices will feed through to consumer bills because the marginal effect on generators will be somewhat offset by the CfD. However, the CfD is like taking an insurance product out. You are buying a long-term power purchase agreement with the Government that effectively guarantees the price of energy on both sides. It is a good deal for the consumers because the alternative would be to build a new gas-fired power station, which would be very expensive and would be at a much higher price than the CfDs may have been expecting to get in AR7. Therefore, while consumers are not going to be able to purchase power at, say, £0 MWh when those wind farms are running, they will be getting it at a price that is lower than what it would otherwise be if we were building new gas-fired power stations.

Thank you. You have prompted some of the areas of discussion that my colleagues are going to ask about in the next hour, so I will resist the temptation to ask further questions, and I will move on to Lizzi Collinge.

We have talked about marginal pricing, and people talk about the price of electricity being pegged to gas. I think most of my constituents do not understand what that means. I will hand it to Susie but someone else might want to chip in. Can you very quickly and simply explain what marginal pricing is or what being pegged to gas means?

This is effectively that, when someone is generating electricity in the UK and they are selling it, they want to get the highest price that they can so they will look around the markets and try to sell it for the highest price. The highest price is a gas power station generating electricity. They are selling their electricity at that price, which is set by the price of gas. We have had massive gas price spikes and their prices have increased so you have this higher price that the gas power stations are selling. Everybody else who is selling their electricity tries to sell it up to that price and they do because, if you are buying it, if someone is selling it here you would take it, or if someone is selling it there you will still take it. It is still cheaper basically than the gas power station or it is the same as. That effectively is marginal pricing. That is how the markets work. It is very hard to stop that from happening. The only way to stop it from happening is—exactly as Tom was saying—through long-term contracts where you say to someone, “We are going to give you a long-term contract that will be lower than that price you are getting at the moment. However, it means that if prices fall dramatically in the future you have already locked in that price”. That is what contracts for difference do. They are decoupling this gas and electricity price. They are breaking the marginal pricing format that we have now, but it is just that it takes a while to build those assets on those new contracts.

I will direct this to Michael Grubb. Does this system of marginal pricing make it easier or harder to lower bills—which I think we all agree is a good thing—and if generators are getting the same price regardless of what it costs to generate does that make sense? Are there different ways of doing it?

It is worth stepping back and just clarifying two things about this first. One is the term “marginal pricing”. To be specific, that is short-run marginal pricing on all the electricity that is sold through the wholesale market. Some of that is then recouped through the CfD mechanism, which is an indirect mechanism of adding or subtracting the revenues relative to the agreed price of those contracts. The second point is we do have a system in which a relatively small sliver of electricity and energy demand more broadly determines the price in more than half of our energy system. In other words, LNG trade broadly sets the price of gas in Europe including the UK, and that in turn mostly sets the price of traded electricity subject to the points that Susie Elks made. The answer to your question is: well, it depends on what happens to gas prices relative to renewables prices. If they go up, everything is going to be much more expensive. If they go way down, everything will get quite a bit cheaper. The fundamental answer is it is going to be volatile. It is going to be volatile depending on the state of gas demand and net demand on LNG, which drives the international energy price. Whether that is cheaper or more expensive depends almost entirely on your time horizon, and the fluctuations in the gas market. In general, most people would say that the gas price is expected to go down, maybe significantly, but also to Tom’s point, the weighted average cost of the CfDs is also going down at present. We are having some of the cheapest CfDs coming on stream at the moment. Those two factors will tend to bring wholesale prices down over the next couple of years.

We are talking about the design of the wholesale market. Are there any comments on what changes you might like to see and, if so, could these changes impact quickly on the market or is it long term as we were talking about before? Are there any other comments you would like to make?

One thing is to be clear that renewables have already lowered the cost of the wholesale market. There was a study that suggested that the wholesale market price is about £75 per MWh at the moment, and it would be up at £100 if we had not built renewables. Therefore, they have already lowered the wholesale price and continuing to roll them out particularly on CfDs is going to continue to do that but, like we said, that is your structural long-term solution. In terms of short-term fixes, there are other things you can do. I would look at the windfall tax that we have on renewables assets and nuclear assets. Those are currently picking up very high profits because of this marginal pricing system. That windfall tax is in place and is called the electricity generator levy. I have some numbers on how much it was projected to generate. I think it was projected to generate £14 billion in five years when it was introduced. That is about £2.8 billion per year but I have not seen any studies since on how effective that has been. When you introduce a windfall tax, people often then change their operations to try to avoid it, so we need to have the Government review that and look at how effective it is being. This is one of these things that I am saying about where the Treasury is generating a lot of money off bills at the moment. That is £2.8 billion per year that it generates because prices are high, but that is not cycling back around at the moment to support the consumers who are struggling. I would also look at removing the carbon price support from the wholesale market. We have the UK ETS at the moment, so it is the carbon price on gas power stations and that is a very common thing to do internationally. The price from carbon is about £34 per tonne. In the UK we have the carbon price support that sits on top of that. It is about £18 per tonne so it is significant. Its role was about making sure that coal power stations ran less than gas power stations. We have now taken coal power stations off the system and, because it adds to the marginal price and it therefore adds to these windfall profits of other generators, the amount of money it generates for Treasury is less than the amount of money it adds to bills. A recent study suggested that for every £1 it is generating for Treasury it is adding £3 to bills. It would be much more effective to remove it, particularly if we are going to join the UK ETS with the EU ETS, which we are looking to do, let’s say, within the next year or two. If we have a higher carbon price than Europe, it will mean that our efficient gas power stations run less than the inefficient gas power stations in Europe. Therefore, not only will it be adding to bills for households, but it will also be making carbon emissions higher across Europe. It is very hard to get an estimate of how much this is adding to bills, but my estimate is about £10 to £20 per household, so it is not insignificant. I will leave it there for now.

I want to add a couple of things on that and link to your previous question. First, the reason renewables have reduced the wholesale price is a factor of two things. One is the direct impact of CfDs but also, as I have said, the cost of gas is dependent upon the amount of LNG imported and, therefore, the less gas you use the lower the international gas price will be. Europe overall, including the UK, is the major LNG importer at the moment. Its demand is very influential on the international gas price. We need to understand this as two different systems interacting. Gas affects the economics of renewables and renewables affect the economics of gas. The other thing is that I mentioned marginal cost pricing and people use the term in general, but they are referring generally to very short-run marginal costs, the cost of running stuff, not the cost of building it. If we are trying to build a low carbon system a lot of that, most of that, will be assets that cost very little to run. It is very hard to make the economics of that work if the entire system is driven by a very short-run spot price. Therefore, yes, I think we need to look at deeper structural changes that would allow consumers better access to predominantly renewables at the cost of investment, not at the cost of whatever is determining the margin in the system at least for a sizeable part of their bills.

On the point about how quickly we could do things in the short term, it is worth noting that the electricity system and the gas system is very complex in terms of the number of contracts that are in place. Most big, non-domestic customers will be on a three-plus year contract. We would have to unwind all of that and that would take time to sort out. Then the price cap itself has a formula that looks at the price over two years. Without changing the price cap it would be difficult for any sort of changes in the wholesale price to filter through quickly into people’s bills.

Apologies for being late. Professor Grubb, I am interested in your idea about consumers having access for the cost of investment on bills. What would that look like?

You could argue that there are elements of it in the CfD system at the moment because they return the difference between the strike price and the wholesale price. However, in part, that is not visible to consumers. Consumers cannot in any way access that or see that directly because it all goes through the wholesale market and is captured in the wholesale price, which is topped up through payments to or from suppliers. A different structure would be required, at least in part, which would give a much greater role for long-term contracts that were directly available and accessible to consumers, potentially underwritten by the Government. To some extent, CfDs do that for the generators. However, you cannot contract directly in the same way with a pool of renewable energy at the cost of constructing it at the moment. I think that is a market reform that is worth looking at fairly closely. It would raise a lot of questions. We have published on some of the challenges, particularly around variability and how you handle that. The solution may be that you have some consumers having a large part of their bills related to the investment cost of renewables, but a part of their own consumption added to reflect the cost, if there were enough or more renewables.

Is that not what we effectively have with the network costs chunk plus your use on top of that?

No, we are a long way from that.

Forgive me, Professor, I know I do not know very much about this in comparison to you, but when I look at my energy bill and when we have been talking about network costs and policy costs and people’s usage, that is how it feels. It feels like I am paying that amount of money. If I spend any time thinking about it at all, and most people do not, I am paying that amount of money for the system to work and I am paying that amount of money because that is the amount of energy I use. What would be different about what you are talking about from that? The difference between network costs and the amount of money I spend for—

I was not referring to network costs primarily.

Okay. When you are talking about the investment cost—and it is the chunk of money that is on your bill to reflect the cost of investment—how different would that be from basically a big chunk of money to make the system work? It would still feel like a big chunk of money that you spend.

There will always be a chunk of money associated with the networks, and it makes sense to be transparent about how much that is, because that is driven by geography including the location of where generation goes. I am referring to the cost of large-scale generation particularly of renewables where, in effect, you have the price of the investment in the renewables. We have an issue about the renewables obligation investments—which I will touch on in a second if I may—and the cost of CfDs. My point is that none of those pools of renewables are clear on your bills or enable people to say, “I want to contract with those”. Many people had green tariffs, and they were shocked when they discovered that what they were really paying largely was the price of gas. That is what I am talking about, something that connects more directly with the investment cost of the renewables. Overall that would be a major change. I think the issue we should focus more attention on at the moment is that within 16 months we have 5 GW of renewables finishing their contracts under the renewables obligation. At the moment the approach to this is maybe 10% may be offered CfDs for effectively tearing down the old equipment and building new—it is called repowering—and the other 90% will sink or swim in the wholesale market and some of those may close, which would not be a great use of past investments.

Do you have a proposal for what we should do as an alternative to that outcome?

I will be a really annoying academic and say that it is at the centre of some of the research we are doing. However, it includes these kinds of options about reflecting longer-term costs in a visible stream of electricity made available, possibly to particular groups of consumers such as industrial consumers would be one option.

I am just going to ask one more question because I know I am being annoying, sorry. In that circumstance is there a risk that if you are paying for the cost of investment and not the amount of energy that you use that the bill disincentivises energy efficiency?

Arguably, cheaper energy disincentivises energy efficiency. There are good reasons to have separate energy efficiency policies. The key question is around flexibility of responses. None of the transition we are talking about with a lot more renewables will make good economic sense unless we have more flexible demand, which can make good economic use of periods when there is a lot of renewables. You do not want to entirely lose that incentive, so this is not saying we should replace the wholesale market by something fundamentally different but, yes, I think that we should be looking at wider market structures that are more suited to renewables costs.

If I could start with Tom, please. Michael Grubb said that if gas prices go way down, bills will get quite a lot cheaper. Although what we are seeing at the moment is wholesale gas prices are lower and less volatile than they were earlier, but consumers are not seeing a significant reduction in the price cap. Why is that?

When I checked earlier this morning gas prices are at about 69.5p per therm, which is down. That is for the winter 2026 contract. This is important because the price cap looks at a basket of longer-term prices to determine what the cost of wholesale energy is, so this means that effectively you are forcing the suppliers to hedge that price. They have to buy those contracts to match what partly exists in their licence condition, and partly so that they are not exposed to the risk of having different costs to the price cap. That means that the cost of the gas the consumer faces is on this 24-month lag, which means that you do not get the immediate benefit of the spot price changing when the wholesale cost of gas—so for example a year ago that same contract was worth 88p per therm. Two years ago it was worth 93p per therm. We are still in the tail end of that gas price spike, but we have seen wholesale bills come down. Even though they are about £1,700 a year under the current price cap, they were over £4,000 in January 2023. Therefore, we have seen a reduction but part of the reason that that lag exists is to make sure that you are buying gas in a responsible manner so that you have a hedge against future prices and, therefore, there is this lag in how the wholesale price feeds through into the customer bill.

I think one of you said that the wholesale gas price is very dependent on the LNG price. Presumably, it does make a significant difference to the cost of energy in Great Britain whether the gas comes from LNG, pipeline imports, domestic offshore or shale, or does it not because LNG is going to drive the price regardless?

Because Europe is the marginal gas market at the moment and GB, or arguably Ireland or GB, are the marginal market within Europe, that means that we have to compete on the global stage for that gas molecule. If you are loading an LNG cargo in Houston you have a choice about where to send it. You can send it to a European market. You can send it to an Asian market, but you will send it to the person who is going to pay you the most. Therefore, we have to compete with China or Japan if we want to buy that gas here and our long-term strategy for gas security has been to build the import infrastructure. We have twice the amount of capacity than we do our peak demand for gas, whereas other, say, European countries have chosen to go down the route of building storage and filling up in the summer and use that gas over the winter. We will buy it at spot, and we are the swing importer.

If we were to build storage instead, the LNG price would still matter but we would have more control over when we were buying it.

Yes. We would have more control because we would be able to store more gas at lower prices in the summer. There is then the issue that we would be competing with Europe for that gas so maybe the price of gas would go up in summer because we are able to store more of it, but it is a different strategy. There is not enough in the GB gas market, the difference between the summer and the winter gas price is not enough to justify investing in a storage project on its own. You would need some form of support, so Centrica is asking for money to refurbish Rough which was our oldest, largest gas storage site but they cannot make it work without some form of support.

If you were to, for example, have new pipelines and significantly increase the proportion of pipeline imports or you were looking at domestic offshore or shale supplies or any of those things it would not make any difference to this question. Would the LNG price still be the driver?

If you were a developer of a gas field and you wanted to sell the gas you could basically hedge your bet by rediverting—say, for example, the price in Asia went up you could redivert an LNG cargo over to there and deliver it from your pipeline here. Effectively the price would remain the same because you sold it somewhere else and less of that gas arrived from somewhere else and you could still sell it here. The price would probably decline but probably not as much. We would not be declining to the short-run marginal cost of production of the gas.

It feels to me that whatever the situation is, changing the mix might have a very small effect because we are one small part of the market on worldwide gas price, but LNG is always going to be the driver of the price.

Yes. We compete in a global gas market and that was our long-term strategy to do so.

Okay. Thank you. If I could turn to Michael Grubb then. You have already talked about some of the ways we could change—if gas is going to stay in our generating mix for some time, which is the assumption, You have already talked about some of the ways its economics might be regulated so that bills can come down. Do you have any other points you would make on that? You answered that in a previous question partly.

If I understand the question right, there are some proposals for direct regulation of gas prices. Maybe one proposal is shifting on to a regulated asset base. I struggle to see how that would work, certainly for as long as you had any competitive wholesale market. We may hear more in the next session but clearly you cannot take gas out of the system. We are totally dependent on gas to keep the lights on for the majority of time, which is why gas effectively sets the wholesale price.

We cannot just immediately turn it off?

Yes. Broadly the history of price controls within competitive markets is not a very happy history because Governments tended to try to get the price as low as possible and then people will not invest or you are asking companies to run at a loss, which they will not. You must address all those kinds of problems in a competitive market context. I would add one area that I think deserves attention. I say that with some hesitation as it is in my own area, but there is a vast trading infrastructure behind the operation of the UK’s energy markets, both electricity and gas. Last time I looked there were 450 different trading companies making money simply out of trading the products and the intermediaries. It hit the headlines that one of those, Vitol, made £12 billion a year just from energy trading activities. The classic economic argument is that trading adds to the liquidity and efficient operation of the market. I have to say I am a little sceptical but have not seen a detailed study of the balance of benefits and costs from having such a vast trading operation behind our energy system.

If I can add to that. There was a study that was done that suggested that—like you said—if you have good energy trading that is adding value and, let’s say, bad energy trading that just adds costs, they thought that that bad energy trading was £174 per household at the moment. If you could improve energy trading that is the amount of money you would get off a bill.

How would you do that?

Now I have to say that is a huge number, so I am very happy to be sceptical on that. They did have some proposals on that, and we are looking at doing some further work on it. Even if you think that number is wrong you can halve it and you still have a number that is massive. Looking into energy trading does feel like something that needs further work.

How do you identify bad energy trading in this context?

I think what they looked at was: where did they feel that the energy trading was adding liquidity and was fair traded costs versus when was it simply adding to profit.

Is that something you can only identify after the fact?

This was a retrospective study, to be fair, and how you resolve it moving forward I cannot claim to be an energy trading expert, but I think it is an area that deserves a further look at.

Michael, you were sceptical I think about the prospect of a strategic reserve for gas and its ability to bring down the costs. Have I understood that?

There are two different terms here. One has been a study that I think you will hear about in the next session about gas in a regulated asset base. Some refer to that as a strategic reserve. To me a strategic reserve, by definition, is something that you pay to exist but not operate in the day-to-day market. Germany did it with lignite plants. For security they said, “We do not want those plants to completely close down, but they are dirty and they undermine incentives for renewables” and they moved them into a strategic reserve, paid to exist, not to operate. You cannot do that with gas. You could do it perhaps with some old gas plants that might be about to shut and you say, “We will pay you to continue to exist but not participate in the market” if they were undermining, for example, other more efficient generators but you cannot take gas out of the market into a strategic reserve. The lights would go out, or the prices would go infinite because everybody would be scrambling and you did not have enough energy. I think people are mixing up the terms. A regulated asset base is not the same thing as a strategic reserve in my language at all.

We will test that out with Adam Bell in an hour’s time. Tom, you were nodding. Anything to add?

Just noting that we had a strategic reserve in 2017, the supplemental balancing reserve, which was used for old coal plant when the margin got very tight, so it is something we have done before. I agree; what would the price of power be if all the gas plant went and then in our wholesale market we would have to create an entire trading arm for this central body that traded all the gas or create a new centralised market. It would probably not work.

I think the long-term picture for the electricity system is that we will need gas power stations in some form of strategic reserve. Their load factors, the amount they operate, is going to be getting very small with maybe them operating 5% of the year. The economics on that for them to stay open is difficult so giving them some kind of regulated rate of return is sensible. It is the long-term picture. In the short term I have not seen a work-up for that proposal that I am comfortable we could make it work. There is an alternative package of things, though, that does a similar thing to a gas-regulated asset base without entirely reworking the wholesale market. One of the ways gas-regulated asset bases lower bills is by lowering the carbon price, so again I would say remove the carbon price support and you access that value. The other thing it does is looks at the profits of gas power stations and lowers those. There is evidence from Michael’s team that gas power stations made between £3 billion and £7 billion extra profit during the four years that we have had of the gas crisis. That is about £30 to £70 per household of extra profit on top of the fact that gas prices increased so they had to increase their bids. Ofgem needs to look at that. We need Ofgem to do an inquiry into what has been going on there to see if that is still taking place because, once these prices have gone up, often companies hold on to them, and it is unlikely that they come back down quickly. That is what the gas-regulated asset base is doing; it is lowering that, so attack that directly, and then the other thing is these windfall profits of people lower down in the stack. Again, go after that with a windfall tax and you have hit the three buckets of value of a gas-regulated asset base without having to do big reforms.

Just to come back to the question about supply from the North sea, for example, there are people who say if we can turn on the taps from the North sea this will bring our prices down, this will solve all our problems. Is there any way in which that can work?

Not that I am aware of. Tom is much more in the numbers of the analysis.

You made the point about the international market and wholesale supplies.

I think the North sea is not the cheapest basin of gas in the world so it is not necessarily true that we would reduce prices. We might get a better deal by doing a long-term deal with Qatar, for example, who probably are the cheapest gas basin in the world but then that is obviously not here. There are also issues around the shelf is declining. Even if we pumped everything that was in there, we would not return to a US shale boom-style take-off of gas supplies, and there is also the matter of the energy profits levy, which is an effective tax rate of 78%, which would probably disincentivise new development of the North sea. We might be better off asking Norway for more because they have some left.

Do they have a greater access to supply?

Yes. They have not deployed as much of their shelf as we have, so they have more left.

I would echo what Tom said, and it is worth being clear. First, just looking at the projections of North sea gas, with and without additional fields, you can just about see the difference, but it does not change the fundamental direction at all. North sea gas declines sharply. Second, it is quite a paradox to say to the companies, “Well, we do want you to continue investing and so on, but we do not want you to make as much money as you could if you sold on an international market. Please invest in a more expensive field for lower returns than you could get investing elsewhere”. That is not a very easy sell to the companies per se. I am not an expert in the area. The final thing—and I think I have seen the CBI hinting at this as well—is that clarity is very important for business and the consistency of policy messages. The oil majors and other would like to continue their existing business that they have resources to deploy, but many other companies have resources they want to deploy in the clean energy transition, and it might not help to send mixed messages about trying to ride all the horses at once. That you could discuss, debate and argue, but that is my sense from some of the industries that we talk to.

I am spoilt for choice of people who want to come in. Lizzi Collinge, you indicated.

I want to clarify something. Have I understood this correctly? You are saying that, in the long term—this is going back a couple of paragraphs, as it were—it may be wise to maintain the ability to burn gas even if we do not. Would this still be true if we had a much wider nuclear power base, including with the newer technologies that could go up and down to some extent? There are different paths that we can take, aren’t there? Tom was gesticulating.

If we look out to the future demand for electricity by 2050, we might be looking at double the amount of electricity demand we have now. One of the best ways of storing energy is methane and we can run both abated and unabated gas-fired power stations within a net zero system. That will allow us to use this incredible potential of methane. There are parts of it that will be economic to capture but there will still be points in time in which—perhaps at the end of a cold, windless week—we just need to turn on those gas-fired power stations that are sitting there probably under some form of RAB or in the capacity market. However, they do not get to run very often, and we will have the security of having those power stations there just in case we need them. That does come with a cost of having that gas system, but again it just points to the large energy potential of holding methane in comparison to storing it in water up a hill or in a lithium-ion battery, which are all important parts of our energy mix but in our modelling the cheapest or most optimal system includes some unabated gas still running in a 2050 scenario.

If it is abated, that does not make the same economic sense, does it?

If it is abated it would be cheaper for it to operate because it is not paying the UK ETS. It does then have to pay for that additional transmission and storage infrastructure, which still should come out a bit cheaper depending on what the structure of the CfD is, which is the current mechanism for supporting CCUS.

Susie was referring to the load factor, which is also known as the capacity factor, so it is the percentage of time in which that power station operates at full capacity. When you say 5% load factor, it means that 5% of the time, that power station is operating at its full capacity. We might only need it 5% of the time is what that means. As some nuclear advocates would argue, the new generation nuclear power stations are more flexible than the old ones. For example, the EPRs—which is what Hinkley and Sizewell are—can operate down to 60% capacity. Therefore, they are more flexible, depending on who you are arguing with about how good AGRs are.

Just before I come on to my questions, I have been listening intently. There is a lot of talk here about trading, hedging, bidding and how the energy price works. It does sound as though there are practices here that would make the Wolf of Wall Street blush. Is there enough regulation and control of this market, or are millionaires making millions out of the top end and consumers are paying the price down the bottom end? I will start with Michael Grubb.

You would need to be clear about your metrics. That millionaires can make millions out of markets does not mean they are doing anything illegal or necessarily even anything wrong. On the other hand I think it was Lord Adair Turner who referred to some of the activities of the City of London as being socially useless. Not a term that I think endeared him to some of his colleagues. Some of this is a genuinely political judgment, but we are creating markets in which a lot of people are making a lot of money out of trading activities that are not directly part of the transfer from production to consumers of energy. That is in a sense all I am saying. I am not expert enough to know about the measures that could be considered.

We have talked about the windfall tax, for example. We have implemented it, but all the energy companies will do is find a way round it and keep making their millions of pounds of profit. We will still see record debt in the UK. Are we not agile enough as a Government to deal with this market? Are they running rings around us?

That is a question I am not sure I am qualified to answer but I can point to some more stuff on energy profits, and I am glad you have raised this. There was another recent study that suggested that at the moment £500 of a household’s energy bill is energy sector profit. Again, you can be sceptical of those numbers. You can even halve them and that is looking high. Interestingly, what they did do was compare the profits of energy companies to the economy average and they found that they were substantially higher in many sectors of the energy system. I would like to come back again to gas power station profits. As I said when I said that about £3 billion, £7 billion extra profit made that is on top of what they were making before, so that is additional. All of this comes back to our ability to monitor the market and then to act on the back of that. We need to do that over the next few years. We also do need to think more fundamentally about reforms moving forwards so that this does not happen again. Something I am particularly interested in at the moment is lowering the cost of capital. The high cost of capital is part of the reason that things are so expensive at the moment. About 45% of a new offshore wind farm’s cost is the cost of capital, which is extortionate and it is a similar number for new network. If we could invest with Government funds at a lower cost of capital, we could be fundamentally lowering the cost of the system and then when there are high profits they would be shared back to taxpayers. I think those more fundamental long-term stakes in the energy sector could be a way to solve things.

I think you just described GB Energy there.

I described GB Energy with a lot more money.

Tom, I might as well give you one as well and then I will go on to my real questions. [Laughter.] Everyone else is up to it today. Tom, you are an expert—

I am wondering if we need to adjourn this session while the members sort out their questions.

It is a very quick one. Tom, in reading, you are an expert in market arrangements, regulation and policy. Do you think that Ofgem is an effective regulator in controlling the energy markets and controlling the cost to the consumer?

You are going to get me in trouble here. I sit on the Balancing and Settlement Code panel that oversees rules for electricity settlement and trading arrangements. We have noticed that there is a bit of a delay and a lag in Ofgem decisions, which can be a bit of a hindrance, but then Ofgem has a lot of things to juggle where it is looking at it. What I have experienced is that Ofgem is not necessarily as quick as it could be. There could be improvement in enforcement, monitoring and reaching decisions in a timely manner.

Michael, I will come back to the questions in front of me and I will talk about cross-border trading. We heard from Make UK, the Chemical Industries Association, and the Energy Intensive Users Group that rebalancing and a better relationship with Europe in terms of energy is the number one thing that would reduce their costs. Is that the same for domestic users of energy?

It is worth thinking about the economics of this. For internationally competitive industry it is price that matters. For households it is bills that matter. They are not identical, though obviously they are related but there are more tools you have around potentially managing household bills over the longer term. Internationally traded price is a concern, and there is no question that the post-Brexit trading arrangements basically have made life more expensive for the system than it would be if you had a more integrated trading market with Europe. I think the numbers are typically a few hundred million pounds a year of structural inefficiencies from how we trade with Europe at present.

Tom, this is obviously a priority for the UK. Is it a priority for the EU to get a better arrangement with the UK? We have heard evidence that in France cross-border trading is blamed for higher prices.

The converse is that we received the lower prices because they are exporting their power to us and we are getting their lower-priced power, which has basically equalised the price. We saw it in Norway as well. There is a big political upset in Norway about the new Norway-UK NSL cable between southern Norway and the north of England where their prices went up but ours went down because we were connected to them. Especially for Ireland it would be key for them to be more integrated with us. Ideally, they would like everyone to be back in the pan-European trading system, EUPHEMIA, and have the problems of the EU CBAM not affecting their imports. Because they are not connected to the rest of the EU, from 1 January 2026 they will have to pay additional taxes to transport power through GB into SEM, the single electricity market in Ireland. I do not necessarily know what their opinion of it is but, for us, it is important that we are more integrated because there are trading disparities between our carbon price and their carbon price because they are set differently in the smaller markets.

Do you think we are relying too much on ETS and having CBAM realignment? The evidence I have heard is that for Europe it is not a priority, and it would put their bills up so why would they want to agree to it? The UK seems very certain that we must have better UK-EU alignment, get CBAM-aligned and our bills come down but that is not going to benefit the EU so why would they want it?

A quick comment. First, I think the May heads of state summit had pretty strong language about linking the emissions trading systems. That is not the same and is arguably quite a lot easier than integrating into or direct trading with the European electricity market with all of the mutual EUPHEMIA, the way the system would sort out power flows. Given the scale of disparity I would be surprised if we did not reach a political agreement on, shall we say, harmonising carbon pricing. I am not holding my breath on terms of engagement with the European electricity market itself. You asked a question about the incentives. I think everyone needs to be clear. When one is looking at different regions with major different prices, you have the automatic paradox that the bigger the gap the more an economist will look at it and say, “Wow, if you link you will be much more efficient and you will achieve a price in the middle”, and the bigger the political obstacles, because everyone with low prices will say, “But if we link then our prices are going to go up and we do not like that and maybe our businesses will get paid but we, the consumers, will be paying more”. You are always going to have this disjuncture. What I would say from the EU perspective and here I think we must look at this in the bigger and strategic game, the North sea is an enormous energy resource. It has been for the last 50 years of fossil fuels; it will be for the next 50 years for renewables. Efficient use of that resource hinges upon close co-operation between the EU and the UK any way you look at it. Not just in trading but how you organise assets, which may be connected to wind farms and to different countries, and how even more you would agree the terms of investment. The UK owns probably about half of the seabeds of most interest for offshore wind so, yes, the EU has a strategic interest in trying to reach a good deal with the UK on terms of both trading and investment for offshore wind and its development.

Can I just note on that historical relationship that we are normally net importers of power from the EU but that is basically driven by the French enormous legacy of nuclear investment. Those plants are going to start retiring soon and by the mid-2030s they will have significantly declined to the point at which they are net exporters from us. We will be sending them power.

To add to that, the more renewables you have in the system the more you want to be interconnected to different countries. As Michael Grubb said, the North sea is a fundamentally important geographical feature for all of Europe. We have some of the best wind resources across all of Europe and we are going to be building the wind turbines to generate cheap electricity so we will be able to export that to Europe. We will not be able to use all the electricity we could generate there if we wanted to, so to balance the system for it to make sense we want to be able to export it and then import it from them at other times. This whole picture is going to change a lot over the next 20 years.

Thanks all for coming in. I have questions on renewable obligations and contracts for difference. First, I think I missed something at the very beginning. Susie, when you mentioned £2.8 billion coming into Treasury, where was that coming from?

I will get the numbers. That is from the electricity generator levy. When it was introduced it was projected to produce £14 billion in five years, which is equal to £2.8 billion per year.

That is going into Treasury, but it is not being put into consumer bills?

It is not specifically being put back to consumer bills.

That is interesting.

The recent Budget I believe, put £2.4 billion to take 75% of the renewables obligation off households, which has needed to be done for a very long time, but I just wanted to put that in context that that £2.4 billion is not necessarily a lovely handout. It is the Treasury that makes a lot of money off the bills at the moment, so it needs to think about how it cycles those costs.

You said 15% of a bill is levies.

It is 15% of an electricity bill. I think it is 8% of a gas bill.

The Budget gives £150 off bills by removing the renewables obligation, taking that off the bills and putting it into general taxation.

Yes, 75% off just for households. It has not been removed for businesses and industry and also removing ECO, which is the energy efficiency scheme, which gives households in fuel poverty energy efficiency measures.

There is this £2.8 billion that we could have put to that as well.

Yes. Shall I go through those numbers for how Treasury is generating the money? So 5% of a bill is VAT, and I am very happy for VAT to be on bills, to be honest, but as bills have increased the amount of money that is being generated off VAT has also increased. Then you have the money from the UK emissions trading scheme and the carbon price support, which I do not know off the top of my head but let’s say it is around the region of £3 billion a year, something like that. Then you have some more niche things such as seabed leasing costs, which the Crown Estate gets from offshore wind, so the Crown Estate sent the Treasury £1 billion last year. The majority of that was from seabed leasing costs. Then you have the windfall taxes that I have mentioned, so there is the one on the electricity generators and there is also the one on gas producers. Then you have the costs that Treasury levies on. You have the warm homes discount, which is social security spending. It is support for people who need support on their bills, but we do not pay that at the moment through general taxation. We levy that on everyone else’s bills. Then there are some other points, the remaining renewables obligation scheme, which you could argue was industrial strategy spending as much as environmental spending and you have some further levies that are coming on moving forward around hydrogen and CCS.

You have not added the £174 per household that comes from millionaires, electricity traders, profiteering, have you?

Not to the money that the Treasury gets.

Or the £500 per bill that is the energy sector’s profits from doing this?

Yes.

Some people are making a lot of money out of consumers.

Yes. I would assume that some of those numbers have probably got some overlap. I think the energy sector profits one included the energy trading number but, yes, there is a lot of money that is being taken off the top of it.

Michael, to go back to renewables obligations, you said that 16 GW of ROs is going to end quite soon and that 10% would move on to CfDs. Would it make sense to reform renewable obligations or turn it into something else or abolish it?

First, the renewables obligation system supports more than 30 GW of renewables overall. That is a lot and that is why it has been the dominant chunk of policy bills. About 5 GW—not including Drax because that is treated very specially—will be coming off its renewables support in April of 2027. That is 16 months away. Then there will be more every year ramping up until after a decade you have all 30 GW if everything else stays the same. It is not a very efficient system. There are proposals where you take all of them and put them on to some other construct, the principal suggestion being CfDs as we have them. I have this slight unease about how you set the price. With CfDs you have a competitive auction, and you say, “I will build this if I get this price”. For something that already exists it is a much more complicated decision. It is really, “Do I keep running in the market or given my next five years of renewables top-ups or will I accept something else?” An auction would basically mean that you need to pay them more in order to get them off the RO unless something else is attractive. I think we need to first solve the problem of what should happen to the 5 GW as they come off stream. I say about 10% because DESNZ will include full repowering of offshore wind assets if they are more than 25 years’ old in the CfD auction. We wait to see how many of those take that up, but it is not going to be more than 10% of the renewables that are coming off contract. The vast majority is basically being sold—well, all our models expect that you will continue operating because you have been built and you should be really cheap. It is much more complicated. We have published on this and, yes, some may do very well, but they face transmission charges, they face rising maintenance costs, and they face cannibalisation because they would be last in the queue of the whole merit order system, because everything else would be subsidised from CfDs. They would see even lower prices if gas prices came down, if we remove the carbon price support. It is not impossible those assets will simply say the whole thing is too uncertain, close down, and be displaced by some of the new renewables. That is why I think we have a problem that requires serious attention. It is an opportunity; this is the benefit of past investment: we do not have any coherent strategy yet on how we make the best use of those assets.

If we got rid of ROCs or got rid of the renewable obligations that would have a huge effect on domestic bills, would it not? As Michael says, there is no mechanism to replace it as yet is there?

Some people are talking about the renewables obligation payments. I do not think that can be done. These are contracts that the British Government made with companies and for the British Government to go back on those contracts and say, “We will not pay you what we said we would pay you” sets the precedent that every time the British Government are setting a contract with someone to provide services in schools or hospitals in defence, we might turn around in 10 years’ time and say, “We do not like that price anymore, we will lower it”.

So we are locked into that?

We are locked into that, yes. All you can do is look at moving them on to longer term contracts if there are questions around value for money there, because they will only accept that contract if they think they are making more money than they can make on the wholesale market, or you are lowering their risk in some way. Or you can go after it with windfall tax.

A cheeky last question. Tom, you mentioned the North sea; what would keep us going in the North sea for the next 20, 30 years if companies are facing 78% levies on their profits?

Transitioning over to doing renewables rather than oil and gas. There is the opportunity to do hydrogen offshore rather than oil and gas, but I imagine there is not much without a reduction to the levy.

I get the pleasure of being the last person to question, which means I get a slight chance to reflect on what has happened so far. I have some questions specifically around zonal pricing but, reflecting on the points made so far, to my mind an efficient market is one that is transparent, least complex as possible and one where the consumers buying it understand how the price is set and what they are getting. That definitely does not seem to be the case in energy in any sense. Who is currently benefitting from the complexity and the way the market is set up? You mentioned Treasury seem to have some benefits. We have had traders. We have had all sorts of different people. Which group benefits most from the market being as it is at the moment?

The suppliers are the counterparty to the generators in the wholesale market. They are savvy consumers. They do get the best deals, and they are out there trading. A consumer does not want to be buying electricity every half an hour or gas every day. I would not want to have my bill changing all the time. The suppliers are the intermediaries buying it and there is a competitive market out there of many suppliers now, not quite as many as there used to be, which shows that there was some efficiency to be made. The marginal pricing system—the pay-as-cleared system—that we have is good at dispatch and getting bilateral contracts. The point of the design and the way it is set up is to encourage parties to contract with each other, and it does that well. It is the suppliers who are the ones purchasing power and doing long-term deals. Very big consumers—like large automotive companies or data centres—are doing individual deals and either trading themselves or they are signing long-term power purchase agreements with generators directly. You even have chemical factories and things like that doing deals with small renewables that allow them to be exempt from the supplier arrangements and can get deals that avoid all of the levies. There are lots of savvy consumers out there and the intermediaries are the ones taking care of the complexity for us.

Does anyone else want to come in?

I have said it before, but the energy companies are making a lot of profit at the moment and that is across the board in most sectors. We have a system that requires competition for profits to be kept honest, and I think there are some serious questions about whether we actually have competition in different parts of the market or whether we have the appearance of competition. Those questions will only become more prevalent while we are in this energy transition. If we want low-cost renewables to lower bills and for that low-cost energy to flow through to consumers, we need to be reforming the systems to make sure that it gets there still being a low price.

I will move on to questions around zonal pricing. We obviously had the decision over the summer of the Government on zonal pricing, which was after some delay. What effect do you think that delay had on different parts of the system? How effective do you think the package of measures that the Government have put forward are likely to be? I will start with Susie for that one.

The delay to the zonal pricing decision was definitely a big issue. Retrospectively it is worth doing a proper review of the REMA programme, which was making those decisions, and particularly around how it considered the risk it was putting on generators while that review was underway. There was not much thought given to the grandfathering arrangements and the way that you would be protecting people while they were building with all that uncertainty. If zonal pricing had been introduced it would have dramatically changed the wholesale price and the revenue that assets would have, and they were having to build with no idea what world they were going to be in, in the future. That could have been avoided if they had made very clear decisions upfront about what the grandfathering arrangements would be for assets, and that would have created the political space for them to then make that decision without all this uncertainty holding over the market.

First, I think that decision was a tough one. I would not have wanted to be in Ed Miliband’s shoes. There was a lot at stake. I fully understand the reasons for the final decision and that the vast majority of the energy industry were vocally against it, with one or two notable exceptions. At the same time we held a major workshop at UCL with industry and others last month. To my mind, what came out of it was we have quite a few levers that we could still influence the location of new investment in assets, but it will be messier and it will involve substantially more central planning and dictation of “Use this instrument to say what goes where”. It is much harder to see solutions on efficient operation or the incentives for demand-side flexibility. That worries me because one thing about this transition is it will not work if we do not have a much more flexible system. In a sense I am glad that they took time because it was an important decision. I think it is not impossible we will regret or at least we still need to find a way of introducing more locational signals. The biggest insight or observation to me is REMA took four years and started out with a huge diagram of options. On almost every option it has ended up with as close to the status quo as you could possibly stay. Actual fundamental reform is very difficult in this energy system that we have created and that worries me because we are trying to build an energy system that is radically different and you would say, “Well, if that is where I want to be I would not start from here”. However, we do start from here and it is very difficult to change at scale.

You mentioned some of the signals that you could give on location price signals. What might some of them be?

A whole debate around TNUoS, transmission pricing. At the moment that is an annual charge. It is not a forward-looking charge. You could build in contract structure that said, “This is how much you would have to pay for transmission access over the lifetime of your asset”. Ofgem is considering that kind of reform, but it looks like it will take a long time. I do think there was quite a lot of protection for incumbents that had already been promised against zonal pricing. They were worried about value after the current contracts, from my understanding. I think there was a general sense of a major change is scary, it will drive up risk, create uncertainty, drive up the cost of capital. It was observed it could take several years to introduce, but I am also minded major changes do take several years so if you say you will not change it because it will take a long time you will never get there. By and large I think the locational challenge will remain with us. What have the Government-published on RNP is not yet remotely adequate as to how we get the most efficient use of assets and their location, or even the sighting but certainly the use of those assets.

For the other two panel members: do you think the seven years that the Government argued they would take to deliver zonal pricing was correct or do you think that was maybe a little bit of being scared?

Too small.

You think it was too small. What do you think would have been a more realistic number and do you think that was one of the major reasons they would have decided against it?

I do think that. I would put that at the low end because the regulatory change process in the electricity industry is slow for good reason, because it is a multiparty contract. Then if you look at examples around things like market-wide half-hourly settlement, which started in 2018, that is still ongoing and due to be sorted soon. Given the evidence of how well we have done performing large, industry-wide changes that would require change to every single participant’s system, and then reopening every contract in the electricity system, and creating whole new systems that require whole new legal frameworks—

It feels a bit like we have built a system that we do not like, we do not think works, it is not effective, but we do not know how to change it, and we are not entirely sure if we should.

Unfortunately, like you say, the electricity system is glacial when it comes to any changes and seven years is what the Government honestly thought that it would take. However, one of my colleagues has worked in the energy system since it was privatised, and he helped privatise the electricity system. He said it took less time for them to entirely design the wholesale market and then to do those fundamental changes at the start. He said those took about three years. So it is possible. We used to be able to do it. Why we have now got a system where it takes seven years, I am not sure.

Is that because there was a clear strategic direction that the markets were going to deliver, and over the intervening—how many years is it since we privatised the energy system?

It was privatised in 1991.

How many years?

Thirty-five years.

Thirty-five years. In the intervening 35 years we have built up a carbuncled system that is teetering like—I am going to mix my metaphors—something that is about to fall over if we say, “Actually we need to change that”. Each time, rather than change it or take it off we add something else and then wonder why it is teetering. Jenga.

When we wrote the rules for the market there were two generating companies and now there are—

I recognise that this is a different system and that, therefore, it needs a different set of regulations. However, the regulations that we have, have been built and accumulated over time on a set of principles that worked when we only had two generators. Now, when we have many generators—I will not be the person who suggests in this room that we would like to scrap it all and start again, but we would not start from here.

I think that Polly Billington and Graeme Downie have both summarised part of the dilemma depressingly well. We did do major reforms in 2013 and 2014 with the EMR, which by most measures have been very successful, and I think that is right. However, they were only reforms on the generation side of the system. They had no connection with consumers or bills or the visibility of what the implication was. It worked for 10 years because renewables were a small part of the system. We are heading for the next 10 years where they will be a dominant part of the system. I agree with you; I am not sure we have the structures that will make the best use of that by a long shot.

I know as an academic you would love it if we were to say to you, “Well, go away and do some research and find out what the solution is”.

I echo Susie’s earlier point that in building this system one of the factors that will determine the long-term costs is the cost of capital, the cost of investment. We have high interest rates in this country, which are driving up the cost of transition because we have inflation and the Bank of England has high interest rates to try to curb inflation. There has been a recent publication, among others, which points out in the energy sector the logic is completely the other way around. Energy costs are a driver of inflation and the more you can lower the cost of capital for energy investments in renewables and in grids the more you will curb the inflationary impact of energy prices. Either the Bank of England itself or GB Energy, with a lot more recapitalisation, should get that absolutely central in their strategic sights.

Thank you, that is very interesting. Wera Hobhouse.

Normally you would think a market was better able to cope with smaller and decentralised stuff, but I am not actually sure that is the case in the way we have designed it.

The key barrier to decentralised, flexible generation in the GB Energy market is around NESO’s ability—and, sorry, this is technical jargon—to balance the system. There are a lot of complaints from smaller parties that the way it is done is unfair, and about how qualifying into the system is difficult. I believe if you can solve those problems then NESO’s ability to dispatch things fairly is a significant part of the way towards building a better, decentralised, more flexible system.

I will say something positive from us. There is a lot of work being done on trying to build that distributed energy system. A major part of it will be the ability for distribution networks to be able to be dispatching assets on a local level and co-ordinating that with what is needed on a national level. That is an essential part of this future energy system, and it starts to send some locational signals in an interesting way, similarly to zonal pricing. It is something that has been thoroughly overlooked. Elexon has been tasked with being the market facilitator in that space, and it will be coming forward with a set of rules. The next RIIO price control and what we ask distribution networks to do in that space is an opportunity for us to level up in the way we are dealing with those assets at the moment. That work is undergoing; I think we need to see where it lands and action it.

Mike Reader, final question? No?

No, I have to go.

In that case, can I thank you all very much for your evidence. It was very informative.   Witnesses: Adam Bell, Ana Musat and Tom Glover.

Welcome back to this afternoon’s Energy Security and Net Zero Select Committee hearing on the cost of energy. Welcome to our second panel. Could you introduce yourselves, starting from this side, please?

I am Adam Bell, Director of Policy at Stonehaven.

I am Tom Glover. I am UK Country Chair, RWE.

Hi, I am Ana Muscat. I am Executive Director for Policy and Engagement at RenewableUK.

Thank you all very much for joining us. I should say that we may well be interrupted by votes in the next 10 or 15 minutes. If we are we will adjourn briefly and come back as soon as we can. I will start with the questions. Adam Bell, we will start with you. How significant are the measures outlined in the REMA summer update in tackling wholesale energy costs? Does the Government need to be more ambitious in informing the market?

The measures in the REMA summer update were quite high level and vague, and it is difficult to judge them, but you can see the shape of the vision they are trying to impart. There will be a big strategic plan, called the Strategic Special Energy Plan, and there will be some changes to the way that networks are charged; TNUoS charging, as you heard from the previous session. The way that these will interact, the SSEP will say, “There is number of spots in the grid in this space and there will be a cost associated with connecting there”. The idea being that even though there is lots of wind in Scotland you probably want people to build things in the south of England too, so you will get a TNUoS uplift embedded into your generator in that way. There are also some changes to the way the system is balanced, including various tweaks to the balancing mechanism, but for me the single biggest most interesting proposition within there is the idea that we change the way that the system is settled. Right now electricity is traded in half-hour periods, the Government are looking towards a shorter period, whether it be 15 minutes as on the continent, or five minutes. This is an important change because it will radically change the role of flexibility and the role of those shorter, smaller assets like batteries and demand-side response. They will have access to a much bigger bit of the market because they can respond faster than the other forms of generation. But whether it will lower bills is still very much up for debate.

Thank you very much. Ana, what do you make of the reformed TNUoS charges?

I think we are still due to see exactly what those reforms will look like. There is a package of work that will look at what the interim TNUoS charges will look like, and then longer term there will be another package of reform looking at what is the enduring charge and how does that evolve. I think it is absolutely necessary to start with that because right now we have TNUoS as a locational signal, but it is not very effective because you cannot predict those charges. No matter where you are in the country you might have those charges swinging quite dramatically from one year to the next, so it is not very effective for business planning. It is important that we build on that locational signal. What we would like to see is a TNUoS charge that is fixed at the point of investment, so when you start building your project, when you start investing and putting money towards your capex you know exactly what your business case looks like and you have certainty around TNUoS. There is a question—to Adam’s point—around the SSEP. There is also a question of how that TNUoS charge will interact with SSEP and how it will interact with the connections queue reform that we have seen announced earlier this week. I thought the connections reform package was pretty significant. Obviously it reduced the queue quite a lot and it gave a useful signal around where you could expect to connect your project, where might be a good area where you can hope to invest more and get new generation online. I think with all of these and with the larger direction of REMA there is still a question as to what the balance between the central planning is, market signals, and how they sit together. That is something that still needs to be fleshed out a bit more.

Thank you. Before I move on to the rest of the Committee, Adam, we were talking about your ideas about a strategic gas reserve earlier. Can you set them out for us?

Certainly. As you heard in the previous session, right now there are a number of generators in the market who are making a surprising amount of cash, and they are doing so because of the way that the price in the market is structured. Right now if you are selling into the market and you are on a long-term contract indexed against the wholesale price, or you are selling on the merchant basis, your price will be determined by the last generator switch on because the wholesale market is pay-as-clear. That is normally gas, and that is the cost of running a gas generator, plus the carbon price, plus a small margin. This is significantly higher than the revenue needs to actually make cash for a large number of assets, especially older ones that have paid off their debt. As a result, there is an important argument and I think it goes to the question that was raised earlier on about what this new market will look like, because right now we are still very much in a kind of 1990 style gas market. My proposition is that we remove gas from the system entirely. Right now if gas is making cash, if we want them to build more gas that would be great, but we do not necessarily want them to build that much more gas, we want to have a finite lifetime for our remaining gas plants. Therefore, we need to take them out of the market to prevent them having this impact on the rest of the generation fleet. We want to ensure that they are placed in a position where they are dispatched by the system operator, where they can get a return via the regulatory asset base similar to networks. Therefore, they can essentially stop having an uplift effect on the rest of the market and we can enable wind, batteries and a mix of new low carbon assets to discover prices without gas acting as a constant distortion.

Yes, and somebody will have to pay for them to sit, not being used for large parts of time. How much do you think that will cost and who will pay for it?

I expect it will cost us about the same amount as the capacitor market does today, which is our current mechanism for paying plants to sit there and stay idle.

Who will pay for it?

The consumer, as they do right now.

Will it bring down bills?

It will, principally because of the impact on the wholesale price. You are no longer setting a price for the wholesale price that everything else in the market enjoys. As you deploy more wind on the system gas is still setting the price for the bulk of the time. That means that a lot of that wind, especially the older wind plants, are getting a significant uplift. For example, if you built a plant under the renewables obligation in the early 2010s you would be looking at the forward price of about £50 per MWh, along with an RO certificate on top, which is normally about £45 to £50. In the current market you are making £70 per MWh, but in the meantime you have paid off your debt, so your cost of operation is essentially your cost of maintenance, which is about £20 per MWh, and you are being paid about £70 per MWh for your power and you add £45 for your renewable obligation certificate. We can shave some of that cost off by taking the upside in the market off and making the market significantly more, subject to the pricing that renewables will go through. There will be zero marginal cost; they will have to bid lower if they want a dispatch.

To what we heard on the last panel; is the answer to getting bills down to do something about this £500 profit per bill that is being made?

I think it is. Right now a lot of people have made a lot of cash from some of those earlier assets and if you are lowering bills now it is time to ask, how do you apply a haircut across those. If you do so by removing the renewables obligation—as has been previously discussed—you essentially tell the market, “You can never rely on any Government support scheme ever again”. But if you can find other ways of removing some of that cash and returning producer surplus to consumers, you should do so.

Is there any comparable market to ours where this has already been tried?

It would be quite novel. The closest parallel would be the CGB because you are handing a lot of plants over to a centralised dispatching body. So for part of the market we would be going back to the days of nationalisation.

So the past is another country?

Yes.

There is not another country or market that does this?

This is the first time in history that we are trying to get rid of an entire generation class while still needing to hand on the physicality of supply. This is a very novel problem, which does require novel solutions.

I understand that, but we are not the only ones experiencing this challenge. I am probing a little bit on understanding whether anything similar has been explored or is being explored, is being developed, in similar kinds of energy markets to ours.

The concept of a strategic reserve has been analysed throughout Europe for quite a while. Germany have looked at it quite a bit. No one has gone for it yet because the market has not been in a position where it completely made sense, so this would be a first.

Why are you confident that it will succeed?

Because this is something that we need to do if you want to decarbonise the system. If you want to allow gas to play in the markets in the long run, which the Government in their security of supply statement appear to indicate, then you will need to find a way of controlling when exactly it dispatches. Your alternative to this is using a very, very high carbon price to suppress its running hours. That cost should be passed back onto consumers, and that quite frankly would be a significant uptick to bills. This is a way of achieving the same effect without creating a significant dead weight cost to consumers.

Ana, what do you think about this?

I think it would be quite difficult to implement because it would effectively require central dispatch, which again would mean a different way of operating all the assets that are in the market. I take your point; we simply do not know because it has not been tried anywhere. There is also then a question of what sets the marginal price. If you take gas out of the wholesale market there will be other technologies that set that wholesale price, so we might not see those reductions that we are necessarily hoping for because you might have nuclear, hydrogen—whatever it is—setting the price. You would not necessarily have the price of renewables directly passed down to consumers.

No, but other energy costs would be cheaper over time and possibly more competitive with renewables to be able to set that price.

Yes, it depends. It is also a question of how you manage the market overall with the central dispatch, what the revenue streams for gas would look like and whether it is enough to keep those gas assets running. There is also a point around do we have enough gas to run on the system right now for the remaining years that we will need it. If you are building new gas assets obviously the price of CCGTs has gone up, so again there is a question around security of supply there; would we be able to get that investment with this model.

Is this too counter to the way we currently run our system for it to be a natural step in part of our transition?

It would be a pretty big departure from the status quo for sure.

Because of its centralising instincts?

Yes, the centralised dispatch model was also considered as part of REMA and then it was taken off the table around the summer. It has been considered as a pretty complex and significant departure from where we are now.

Thank you. Graeme Downie.

I want to ask some questions around renewables and network infrastructure siting and whether or not that will impact on consumer costs. As someone who has spent 10 plus years working in planning and communications in Scotland, largely on renewables projects, I have seen some good and some bad in terms of siting. We have seen the rising balance costs, which do suggest an imbalance between demand generation and network capacity. Have the Government, and Governments, been too focused—as I would possibly say happened in Scotland—on, “Just start generating”, “Just start upping the number and we will worry about the rest later”? Is that something that the UK Government risk doing as well?

One thing we have not done well is invest in the grid in tandem with new generation. This is something that everyone has made the regulator aware of for many, many years. We have a system, which is Connect and Manage, you build your project and you hope that the network will be there when your project starts generating, which has not been the case. But at the same time, generators were told that, “The network will be there, and we will allow that investment to happen—”

Yes, you see grid connections, so 10-plus years, grid connections and decisions made in good faith that then you have a lovely planning permission that actually is utterly worthless, and those figures are then counted.

Exactly.

How do we make sure that does not happen with the decisions being made now that we effectively actually join those things together and we avoid that decoupling?

There are probably two things; I think the regulator is now more aware of this need for anticipatory investment in the grid, so we have seen this week the outcome of the RIIO-3 regulatory process, which allows more investment ahead of need in network infrastructure. That is across both electricity transmission and gas, which is good because we do not want to pay when we already have all the generation, we have the backlog, and the curtailments on the system. That is positive, however, we need to recognise that we are dealing with years of underinvestment so it will take us a while to get to a point where curtailment costs are minimised significantly. The other point is also about connections and thinking about how we connect the projects that we need. NESO has made quite significant progress there because we were operating in a system that was assuming if you are first in the queue you will be first served. That did not necessarily lead to the best outcomes because you sometimes had projects that were not as needed being connected first, whereas bigger projects that would make more of a difference in terms of total system security were at the back of the queue, as you said, waiting 10 years plus. Now we have moved to a system that is first ready, first needed, first connected. The announcements that we have seen earlier this week have reduced that connections queue from over 700 GW that was in the queue, more than we would ever need, to 250 GW or so. It was quite a significant reduction. To the point made in the earlier point, I think it shows that we can do bold things, and we can make significant reforms. That has been quite significant, and I think it will help with some of those questions around curtailment, but we need to make sure that we do not back away from that investment in the grid. Part of the reason why we have underinvested is I think in the mid-2010s there was a lot of concern from the regulator around if we invest in the grid ahead of need this will add to bills. Yes, that is true, but arguably you have ended up adding more to bills by not having the network ready now.

Yes. Tom, I am quite interested in your perspective—obviously you worked on this for a number of years—who should be responsible for resolving those curtailment costs we have seen, and any other reflections more generally as well?

On curtailment I think Ana summarised it well. As a generator, when we committed to build these assets we were doing it under the Connect and Manage regime, which we were told when we did that investment we would have firm access to the system and so we invested on that basis. The regulator decided to do more of a connect and forget regime where it forgot to do the investment side of it on the network. Basically, what we were paying for in things like TNUoS—the Scottish generators have paid a lot of money for TNUoS, which was supposed to go towards building more wires, and those wires have not been built. Effectively they paid for firm access, so it is like paying for a road to your house, but you never got the road delivered, and now people are saying, “Well, now you cannot get out of your house, you have to pay again”. We have to reflect on the fact the generators were given a deal, if you like, at that point and the regulator at the time thought it was best for consumers not to do the network investment then, and we are paying the price now. It is too complicated to work out whether that was a good decision or not but that is effectively what we are doing now. That is number one in terms of past investments. In terms of future investments, we talked about this TNUoS reform and the most important thing that we do is when I invest I need a strong financial signal in my financial model that says, “Do you want to go here, here, or here?” That is the TNUoS signal. Now, it has not been reformed and updated since 2013. The industry has been pushing and pushing through modifications but there has not been progress forward, but what we need is that TNUoS signal to reflect the real cost of building the wires. It would be expensive in Scotland, and it would be cheaper in London, but that then allows a proper economic incentive to do that. It has a bit of an incentive now, it is £20 a kilowatt in Scotland and zero in London, so we have already got a disadvantage for going to Scotland. But the real cost could be £40, £50, £60, even £100 by some models, so you would have given that cost, that is number one. Then, as Ana said, the other thing the industry has been asking for is that it is fixed. The problem at the moment is it is changed every year for four years ahead, but I am building a 30-year asset, or I am doing a fixed price contract for 20 years so and I do want that fixed up front. If it is expensive to build that asset in that location because it will cost consumers to build a wire, you want to give me the signal now. I put it in the financial model and say, “That asset is not worth building”. That is how we resolve it. Picking up on Adam’s point, we have the balancing mechanism, and the balancing market not only does energy balancing, but it also does locational balance. The more assets that can participate in that, whether it is reducing the megawatt size—and a lot of the smaller generators are not party to that for various reasons that are complicated. I also agree with the settlement period. I called for that. If you look at the “Tom Glover settlement series” you will see I gave them a five-minute challenge about five years ago, so I fully agree a settlement period, so we get that optimisation better, which means it is more efficient. That is how we reduce constraint costs. But ultimately—and this is the bit we have to recognise—we need to build some wires. If you look at the NESO forecast there are two wires, the Tilbury Norwich line—although it would be very unpopular—and the Sea Link line, that will halve their constraint costs: £4 billion a year saving potentially for those two wires. So we have to build some wires, so that is one thing. The final bit is there is an efficient amount of constraint costs so we should not sit there and think they will disappear. It is a little bit like you do not build the main road to Cornwall for peak summer traffic because 95% of the year it will be empty. So we do not build the system for all the generation to be on at a time, that also does not make economic sense. There is an efficient amount of constraint costs. What we have now is an inefficient level, no doubt, but there is some level so we should not also have an ambition to get rid of them all or else we will have a completely gold-plated television system.

As someone who lived in Scotland when they were doing Beauly-Denny, I remember the utter water torture that was for absolutely everyone involved frankly. Lastly, because I am conscious of my time, moving on to offshore wind and probably to you as well, Tom. You have seen a bit of a contrast between, again Scotland and England where we have had complaints of high fees from the crown estate in England. Equally in Scotland we have seen very low income and, indeed, licences handed back. What exactly do you think the Crown Estate should be doing right or wrong? What has worked well in that system and what has not in order to try to make sure that the offshore licence system works properly?

Yes, it is extremely complicated. First of all, RWE is one of the big payers of option fees. Why did we decide that those options were worth paying, because it is £250,000 a year for our project so these are not insufficient monies? This is money that will go to the Treasury effectively. We do that because we thought the projects we were bidding for were going to be that much more competitive than the next projects, and that is because they had higher wind yield, they were in better locations, they were in a better sea base. We effectively looked at those projects and said they are that much better than the other projects. That is why we decided to do it. It was also at a time, to be honest, where the offshore wind industry was slightly more optimistic than it is today, so it may be that we overpaid slightly. I will not say too much more about that, but that is your optimistic view. So that is the reason why we paid it. You do not get that value in a Scottish site necessarily for two reasons, one, although you have a higher wind yield you have the higher transmission costs. One of the reasons why a Norfolk project is better, you have lower transmission costs, but also a number of those are floating, and at the moment floating is also a very expensive technology. There are logical reasons why that makes sense that there is a value difference for different lease areas. In terms of the Crown Estate, ultimately those option fees need to be recovered from somewhere, either from my shareholders or the customers, maybe a mix of both. Ultimately one of the problems is I have to bid that and a customer pays, so it is a little bit of a redistribution because that money that I pay goes to taxpayers, but it is ultimately paid by billpayers. There is regressive/progressive issue there.

People pay twice?

They are not paying twice. It is like a roundabout of money. I think that is something to think about; whether that is efficient or whether there is a better way of allocating leases.

Now, Polly Billington, and to recognise that the Minister is speaking; we will have a vote so we will keep an eye on it.

This is on CfDs, and we heard a little bit from the previous panel about once ROs run out and so forth, and how things will keep running. With the CfD now fixing prices for up to 20 years are we at risk of locking in higher costs for consumers through to 2045?

No. We have done a study with Aurora, a big, independent energy consultancy, who said basically for offshore wind, as long as you pay less than £94 a MWh the consumer benefits. Baringa has done a similar study, and it get to a similar figure. There are lots of studies referred to before that show how much offshore wind and onshore wind has benefited the consumer to over £100 billion. So from our perspective, yes, you look into a price, absolutely, and that is like an insurance policy that basically means you are paying £94 but you will not be paying for that energy 150 some years. Some years you might lose some years you are avoiding the ability to pay £70,000 but on average it is shown that where we are clearing those prices saves consumers money.

We also know with high capital costs and so forth, and with the auction coming up, there is a risk that we end up locking in high costs for new investment—

Obviously capital costs can go up or down. We are not seeing any indication in the market that capital costs are coming down. What we also see internally is that capital costs of other technology has gone up even more. So our internal analysis says the capital cost of gas has gone up more than renewables. In terms of your alterative options, as you know, everything at the moment is going up in cost.

Adam?

I fear I have to disagree with Tom on this one because we are at a very, very strange place and the Government face a very, very strange problem. Demand has been going down consistently for the last 20 years. To believe that buying new assets now saves you money you have to assume demand goes up radically. The problem—

It will go up radically because we will electrify the system and particularly increase the need for electrification of heat and EVs.

The thing is, we only do that if we can actually lower our costs. Today the Government published their latest update on heat pump deployment, which is essentially flatlining. The Chancellor has increased the tax on EVs, which the OBR says will reduce deployment by about 110,000—

These are the consequences of policy changes; if you change your policy, you electrify the heat and you electrify EVs you get electricity demand go up. The CCC, Mission Control, Clean Power 2030 Plan, everything accepts that fundamentally if we are going to decarbonise our system electricity demand will go up.

It only goes up if it comes down in price, otherwise you will be telling consumers, “You have to go out and buy a heat pump in order to afford to pay your bills—”

This goes back to my point about CfDs. Are we risking locking in high electricity costs which will create a disincentive for the decarbonisation that we are looking for?

This is exactly why I say yes. Our biggest risk now is that demand flatlines, and we buy CfDs at quite a high price and tell the market, “We think wholesale prices will be above £90 consistently for decades”.

Your solution for reducing this is to take gas out of the system?

It is to do with that, but it is also thinking about how much you are buying when you buy it. Right now the Government are thinking about how much it will spend on AR7 and what price it will buy these assets at. If you go much beyond £85, which is the current average wholesale price, it is difficult to explain to the market why you are buying more capacity now when it is most likely that demand will flatline. We have all seen 1.5 TWh of industrial demand come off the system this year. We risk more coming off unless we have a clear plan for lowering industrial costs.

Ana, I am sure you have some views on this.

Yes. First of all there is other technologies in the CfD, so I think with onshore wind we are still likely to see the lowest prices of generating out of all technologies, so I think it is definitely worth investing in that. On the point around demand, obviously we cannot ignore that. Looking at NESA reports, demand this year has increased by about 3%, so not significantly, but about 3% compared to the year before. As you say, if we are looking to electrify the whole system, EVs, heat, all of that, industrial processes, demand will definitely go up. We are also looking at getting investment in data centres, let’s see if that materialises. However, we do not want to be in a situation like the US where they have put a break on renewables and now they are seeing high power costs for industrial for data centres because there is not enough capacity. We need to be mindful of that. To Tom’s point, I think the capital cost of all technologies has gone up. It is easy to say, “Well, gas prices might be low no so let’s wait and see” but I do not think any of us can bank on gas prices staying low for the long term.

I will be a bit of gloomster here. Things will get worse. Things will get worse in the middle of a development. You could have a CfD price you have agreed and then suddenly, dare I say it, capital costs could go exponentially, so you end up with an uneconomic development. Should there be some kind of mechanism to recover money from developments if their costs then reduce the other way?

If the capital costs reduce?

Yes.

First of all, we need to make sure that the integrity of the contract that has been signed is intact. We have had a few cases of projects not going ahead where the developer has taken all the loss. I think that is the nature of the market system we are in and that is why you have incentives from all these different generators and global players to come and invest in the UK. I do not think it would necessarily be fair to say, “If it is going super well, let’s take some money back”.

You do not think that is fair?

No.

CfDs were created about 12, 13 years ago now. Are they the right mechanism for the next stage of the transition pathway to investing in more renewables and making the system work? First Adam and then Tom.

I think they have done an astonishing job. I want to emphasise that the CfD auction was one of the most impressive economic tools any UK Government have ever implemented. The problem is that it works as long as you are buying below the overall amount of power that you need. When there is a question around when to buy the last generator, the marginal generator, it starts to fall away and you risk overbuying. It is very reasonable for the Government to buy a significant quantity in AR7, potentially some more in AR8, but it is worth thinking after that, “How do you buy the marginal generator?” It cannot be from Government guessing how much demand will be because, quite frankly, Government have spent the last 10 years getting that number wrong. You have to expose private capital to the risk rather than the public.

I think Adam is looking at a fundamentally different power system than I operate in. I do not know if you know but gas provided 30% of the energy last year; that is the number for every home in the UK. So taking out the market is like taking Samsung out of the mobile phone market. Therefore, we are nowhere near buying the marginal CfD. I do not know where these numbers come from. The CfD is the gold standard. We have had failed auctions in Denmark, Germany, Netherlands, and what is their answer? They are all going to do CfDs in the next two years. So it is absolutely the gold standard, you can get your investment, you get it at the lowest cost of capital you possibly can, with international investors coming in and delivering these products and countries that have tried something different are all going back to the capacity market.

I will not ask the question I want to about CfDs and local energy. I will need to do that in writing because I am aware of where we need to make some more progress.

Thank you very much. It is good to get some different opinions on the panel. Long may that continue. Torcuil Crichton, if you can make a start and we will pause. I do not know how long she will speak for.

On CfDs and allocation round 7, the Secretary of State kind of increased the budget after the bids did not come in. Why does he not do it the other way? Why does he not set a low budget and then increase it if he has to?

The first budget that was announced was the lower budget. It will procure quite a small amount of capacity relative to what is eligible. Let’s remember that this year there have been quite a few changes made to the allocation framework to make more capacity eligible so that we could have more competitive tension. Currently, looking at offshore wind, we have over 20 GW that is eligible to compete this year. Whereas the budget that we have so far could procure around four or five, depending on what you assume. Frankly, we could have procured four or five without changing any of these rules and delaying the auction by six months, so I think it is worth increasing the budget because there are so many shovel ready projects.

We will reconvene when the three of us are back. The session is suspended. Sitting suspended for a Division in the House. On resuming—

We will move the questioning on to Claire Young, please.

Thank you, Chair. I will ask about corporate power purchase agreements. Obviously both PPAs and CfDs allow developers to mitigate revenue uncertainty by locking in long-term prices. If a CfD price is competitive why is it so rare to see developers pursuing PPAs instead?

The very simple answer is because PPAs and CfDs are in direct competition. Essentially, a PPA is another way of insulating you price risk by getting an agreement to take your power away. If you have a CfD you do not necessarily need to do that. You need to have an offtaker but that is not the same as a PPA, and you might be more willing to trade your power around to maximise your revenue.

Do you want to add anything to that, Tom?

Yes. First of all to say the PPA market is quite big, so RWE has sold quite a bit of our power under corporate PPAs to people like Lidl and Co-op and so on. The big issue is the difference between an investment signal and a marginal price signal. At the moment if you are an industrial you can buy your energy at the current spot price, which is not the investment price, it is the dispatch price, whereas as an offshore or onshore wind person I need to do the investment price. What there is, is about a £20 to £30, or maybe even £40 a MWh difference between what you need to invest and what you need to dispatch at. The more you put renewables on the system, the lower the marginal price. So if you are a corporate, your alternative to doing a PPA is to buy in the spot market, so you are buying below that. You are not asking people to invest. What we find is the PPAs we do are all off existing assets, ones that are not under a CfD, but we need a CfD to get to the investment price for our new assets and there is about a £30 to £40 a MWh difference.

Perhaps I could come to Ana for this one. Could establishing PPAs between constrained renewable generators and public sector facilities reduce curtailment and lock in affordable energy?

It is definitely something worth exploring. Something else that we have also been looking at across the renewables market is obviously, as Tom says, PPAs are quite common for technologies like onshore wind. I think for floating offshore wind there is probably a bit of a mismatch in terms of what the offtaker needs and what the capacity available is. But we are starting to see more of that. For example, there is an offshore wind project called Moray West that has come to market on a mixed route, so it is part CfD, part PPA, with Amazon. As we are looking to attract more datacentre investment, for example, Scotland could be a prime target for that because we have a lot of capacity there that is getting curtailed at the minute. Another area that we are looking at in RenewableUK is whether we could also establish a PPA between green hydrogen producers and renewable generators. Obviously a lot of green hydrogen projects are trying to come to market, and they are looking for generation. We have also been exploring whether it is an option to have those generators that do not make it into the CfD, their price is marginally high to get a CfD contract, but it is a price that a hydrogen producer would be willing to take. That sort of PPA could be a good option to still get viable projects on the market and also get those hydrogen projects over the line. We have also been exploring a little bit of that in terms of heat networks. So it is quite an interesting picture to look at across the demand and supply side.

Not necessarily public sector facilities? You do not see that as—

It is an option. I think it probably would need a bit of bundling of demand because in reality, if you are looking at big generators like offshore wind, it is probably more than, let’s say, a school would need. You would probably need to have some sort of intermediary making sure that the supply and demand are matched.

Do you think the Government could be doing more to enable the private sector’s use of PPAs? Potentially then you could free up more of the AR budget for less mature technologies.

I think in reality some technologies will go towards PPA more frequently than others. I have mentioned onshore wind. We have quite a few projects and generators in our membership that go down via the PPA route. It is a little bit harder for offshore wind and floating offshore wind because it takes a bit longer to get those projects to market. In principle some of the challenges that we have with PPAs—and the reason they do not happen more often—is that mismatch that I mentioned. It is also some of the credit risk, particularly if you are looking at energy intensive. Some of those industrials’ credit risk might not be brilliant but that could be something that the Government help with because they want to electrify. There is the opportunity to get this generation from renewables. What you would probably need there is someone underwriting that PPA, so an entity like the National Wealth Fund could be doing that.

Adam or Tom, did you have anything?

Maybe to emphasise, one of the problems, let’s say I’m building an offshore wind farm, which is 1,500 MW. The biggest datacentre at the moment in the UK is bang 100, so that is a practical issue. Then the other one about avoiding things like curtailment or system costs, that requires direct private wires and to do that in the UK is tricky from a regulatory perspective because as soon as you get above a certain level you need a transmission licence, you need to pay all the fees with the system. There is no easy way for me to put a private wire from a power station directly to a demand.

Is that something that is done elsewhere? I am wondering if we can learn any lessons.

I am sorry; I do not know.

Are there any other support mechanisms you are aware of in other major European power markets that we could be learning from?

I would not say there is direct support mechanisms, but other markets make it much cheaper to develop project. For example Spain undertakes a spatial search approach, looking at relevant habitats, which is quite helpful. Essentially what they do is create a map that says, “You can build your projects here”. I hope as part of the work that DEFRA is doing with the system operator on the spatial energy plan it will be able to start saying more specifically, “If you build this project here you do not have to do an environment impact assessment and you are more likely to get consent”. Anything that reduces the cost of building.

That could apply, regardless of whether you have PPAs or not. That is generally making it easier to develop renewables. Is there anything specifically to do with PPAs in terms of supporting more use of those in the private sector?

I think like Ana with the credit idea, our biggest issue is there is not that many companies in the UK market that have 10-year plus credit risk, which is why the CfD for 20 years with a AAA rated Government is so attractive, and particularly the industries that need it the most. It is the same on our hydrogen and carbon agreements; trying to find a good quality manufacturing industry that I could sign a contract with for 10 years that would have on the back of it hundreds of millions of investment. If I go to my credit committee it will say, “We do not think they are good for it”. You could do some kind of credit spreading mechanism. You could have the National Wealth Fund doing credit pooling or insurance pooling for us, or that kind of thing. Particularly if you are supporting industries that are strategic to the UK, something like that would work.

Tom, coming back to what you said about the difficulties of building sizeable private wire, what needs to change to make that easier to deliver and more attractive?

At the moment the fundamental thing is if I do a private wire—and apologies, I cannot remember the threshold—above a certain threshold I have to be a regulated transmission business in the UK. As a generator, due to EU unbundling rules, I cannot also be a transmission operator. It is just a legally not allowed thing. As soon as you are a transmission operator, you also have to charge all the different levies we have talked about in the electricity bill. Therefore, some of the advantages of the direct supply disappear. If you literally looked at the price from my power station to a big industrial next door, you could save tens and tens of millions of pounds going direct, but obviously I have to go via the system and pay all the levies. Whether it is a good idea or not, the problem is that if I save those levies, those levies need to be recovered off somebody else in the system. Is it a real saving or is it paying Peter to do Paul? The main reason is that it is regulatory. Is it a good idea or not? I am sure the transmission operator and the system operator would say they do not want lots of people having big chunks of generation and demand without their control.

As you say, you have to find the cost from somewhere else, whatever you do. Anybody else on how we overcome this regulatory challenge for private wire? No. What about for smaller private wires? We were talking to a developer yesterday who is very keen on smaller versions of this. How much potential is there for small-scale PPAs, Adam?

This is already happening to a degree. Right now there are a number of different routes to market. Ofgem is considering a modification of industry codes. That would let anyone connecting at the primary substation level count as a complex site, which would mean that as long as you were connected to a particular substation and your demand is connected to that substation as well, you could count as private wire. There is a problem with all this, though. It relates to what Tom said. Right now a lot of businesses are engaged in what is called ASC shaving, which essentially is when you install rooftop renewables or some other form of generation and apply to the system operator or the network to lower your maximum allowable supply. What that means, in essence, is because your transmission and network charges are sized against that allowable supply, you can lower your overall costs and shove them elsewhere. This means that right now the best game in town is, in fact, very small-scale private wire and fiddling around with numbers that relate to your regulatory impact on the network.

You are suggesting that that will catch up with us?

I suspect it will go one of two ways. Ofgem tried to prevent this in the mid-2010s through a targeted charging review by shoving some of those costs away on to the fixed charge. Now people have found a way of avoiding the fixed charge, the next game is just to defect from the network entirely.

Torcuil, I will come back to you for your remaining questions.

I will keep it brief because time is running short. Before you were interrupted, Ana, we were having this discussion on AR7 and CfDs. There is quite a lot of demand from industry, saying that the budget was not big enough for AR7. How does the Department balance that demand from industry, “If we are going to make this work, you need to give us more money?” and obviously it has to try to keep prices down and downward pressure on prices?

Again, to briefly recap what I was saying, we have had a delay of about six months to this auction to change the rules of eligibility so we could have more projects that could bid into this year. Currently, for offshore wind over 20 GW is eligible. You could buy about four or five right now. The thing is that no one in the industry is saying you need to buy all those 20 GW. The whole point is that it is an auction. You will have winners and losers, and I think that is well accepted. The point is that since we have had the auction delayed by about six months, every delay costs generators money. It is not just free waiting. Since we have delayed by about six months, we might as well make it worth our while and be a bit more ambitious in terms of procurement. There are other reasons for that, too. If you look at Clean Power 2030 targets, what you need is probably about 10 GW of new capacity to be procured this year and next. Again, if we are buying just four or five we are falling short of that. In addition, there is the industrial benefits because right now we have quite a lot of new capacity coming to market. There is potential to get investment in new factories. Part of the reason why prices are higher now than they were a while ago is because supply chains are constrained and there is demand from everywhere across Europe. We can capture some of that benefit by getting the investment in factories here in the UK.

Is the supply chain ready for that?

The supply chain is ready but the point that always comes back is we need to make sure that there is constant demand and that there is a visible pipeline. It would not be any good to say, “Let’s get 11 GW now”, for example, but then we do not get anything for the next five years. The auctions need to be fairly constant. They are yearly but we have seen delays and we have seen completely unsuccessful auctions. There are potential plans for investment, but we definitely need to see some of this pipeline materialising.

Tom, there are problems with it, but would you describe CfD as the gold standard internationally?

Yes, absolutely. The contract itself is the gold standard. Ana has raised the issue about long-term predictability of the pipelines. The problem you have at the moment is the budget and how much capacity you want every year changes, yet we are sitting there saying, “Why aren’t people investing in factories?” The honest answer is that, as a developer, I do not know now which projects I will get in February. I have tens of billions of capex that could or could not get a contract in February, that could contribute to UK growth. About 50% of the supply chain comes from the UK and most of our projects, so that is just sitting there ready to be grasped. I cannot tell those factories and those people whether they have deals or not. That is the same across our chain, but it is even worse than that. I cannot tell them whether they have it this year, I cannot tell them whether they have it next year or the year after. Then as a Government we say, “Why aren’t they investing in blade factories? Why aren’t they doing transformer factories?” I cannot tell them what my demand is for 10 years, so would you build a factory? That is the problem.

Is that why you put projects into the auction round that do not have planning consent already because you do not know what is going to—

We were actually against the idea of putting projects in that do not have planning because of that uncertainty. If they do not have planning, the likelihood that you have gone through the supply chain and really understood what is deliverable and what the cost is is quite low. To be honest, we benefited through that chain. We have put some projects in that do not have full planning permission. We did not want to but when everybody else plays the game, then you have to play the game. Our ones that have planning permission are much more advanced, so 80% or 90% of the supply chain is known. We can go to financial investment position really fast. For those ones that do not have planning, of course, the supply chain, as you imagine, have a lot of people approaching them and they focus on the ones they think are more likely to go ahead. There is a risk there, to be honest, but the main point is that if we want people to come here, they have to see gigawatts every year. Then they can go, “It is worth building the port”, “It is worth building the factory”. No one is going to build this stuff if just maybe Tom is going to turn up and give them a contract in February or maybe not. The contract itself is the gold standard. We could do a lot better on the forward project of capacity required.

The last panel talked about capital costs stalling us and you are telling us supply chain or uncertainty over contracts could stall us.

Yes. In terms of cost of offshore, capital cost has gone up, definitely. You have seen that just with general UK costs, cost of capital, gilts and so on. The perception of risk has also gone up. The perception of risk when you see what is happening in the regulatory sphere, that has gone up. There is also a supply chain increase in costs. We have had an increase in supply chain costs globally, whether that be steel or the fact you cannot get HVDC transformers. Effectively, no one is building new factories because they cannot see the supply. Therefore, when you are trying to get the same demand into more factories, the price goes up. A big offshore OEM cancelled its decision to build a factory in Poland because it was not seeing demand here. We are not seeing anybody expand their factories in the UK because they are not sure whether they are going to get those orders. That will then jack up supply costs and supply costs will start correcting when people start building more factories.

Adam, do you have any final thoughts on CfDs?

With my old official’s hat on, it is a question of balance of risk, essentially who takes the risk of investing in a factory that might not be needed. Right now if you are looking to build a factory in the UK, you are subject to political risk. You are subject to delays in contracting and delays in rounds, as Ana has mentioned. You have to take a bet, not necessarily on whether your technology is any good but whether you think the politicians have an appetite to buy X gigawatt more. Especially in a market in which you have various players saying they are not going to do any more offshore wind, it is a really hard sell to invest in the UK.

How much is all this uncertainty adding to consumer bills?

I think it is impossible to say. It can only put the price up but trying to estimate it is almost impossible.

We have talked today about the legacy system with gas and before that coal and then the move to renewables. A question that has been running through both panels in a sense is: how do we compare like with like in costs? Is there an accepted levelized cost of energy that we can point to? Tom, you are shaking.

No. The levelized cost of energy is quite misleading because those technologies provide different things, whether it is firm baseload with nuclear or flexible with gas. Renewable LCOE to LCOEs may be a little bit comparable but even then, because they are different profiles, it is not. The way you would do it is to do a full system model. When you look at the energy consultancies like Aurora, Baringa, LCP, what they effectively do is they run a full economic model and they basically add economically different levels of different kinds of generation to work out what the minimum total system cost is. It is complicated. The best thing you can do is look at their reports and then look at their assumptions and whether you agree with their assumptions. Then they run a system minimisation approach. However, LCOEs are quite a misleading statistic, to be honest.

It has been puzzling us all, I think, from time to time. Not being energy experts, why can we not go from exploration through to extraction and decommissioning in oil and gas, not dissimilar to nuclear, identifying, planning, installation and decommissioning in solar and wind? There are a lot of commonalities; the end product is for sure. Why can we not compare like with like?

Because you are essentially comparing different things. The difficulty is that you can go out and you can buy an oil and gas company and you will have an expectation of the return. You can go out and buy a nuclear plant, and you will know how much power it will output and, therefore, how much you can sell it for. Renewables by themselves do not satisfy the entire power demand curve and, therefore, they need something else. With the renewable system you are essentially not simply buying a chunk of renewables, you are buying renewables plus batteries plus LDES plus some other form of security mechanism. What you need to compare is essentially different ways of arranging all those different assets, which is incredibly hard and not something you can readily do in the market. It is something that you need to do if you are planning a system centrally, which the Government it appears intend to do. The challenge, of course, is if you get that wrong and you overbuy and you overbuild. Making sure you avoid that is the problem the Government face.

Okay. I still do not understand why we cannot have the answer to this question.

You could go out and buy a wind farm plus some solar plus a battery plus some form of molecular store, whether it be hydrogen or whatever. You can compare that to the cost of a gas plant. It would look more expensive, but you would not buy a single gas plant or a single configuration of different technologies; you would buy lots of them at once.

Quite frankly, if the consumer had that level of transparency they would have more than much of the rest of the industry. A lot of the costs around networks are quite opaque because of the way in which they are regulated and the choices that go into them are complicated and range over financing mechanisms that last about 40 years. You could come up with a single number that says, “This is how much the network has cost you” along with another number that says, “and this is how much we are spending in the next five years to build them out”, which would give you a certain amount of transparency. What it would not do is say what chunk of that cash is locked in for 40 years and what chunk is essentially profits/operational expenditure.

I agree.

Yes. For me, what we are all trying to get to is a cleaner, more affordable, more secure energy system and I am not sure providing more and more transparency to the customer and the household, are they really that bothered? What do they really want to see? They want to see a bill lower than last year. It is a bit like broadband. On your broadband bill you do not see what the network and the server and everything else costs. I am not trying to hide anything. I just do not think—what they want to see is a cheaper bill, right?

It is transparent. When Ofgem comes up with a price cap, it very clearly has a breakdown of all the different cost elements. That is its role to provide that transparency to the experts who can question whether that is the right idea. I suppose I am just challenging whether the average consumer really wants to see that level of detail.

Let me put this question another way. Do you accept the estimate we had in the last panel of the price cap at £1,700 is delivering profits of £500 to the energy system?

No. I am glad you gave me the opportunity. I was trying to do the maths for how a £500 profit can come from a £324 wholesale. As an ex-trader, even I would not be able to make that work. I do not know where that number comes from, to be honest. It is clearly nonsense because you cannot even find it in your bill. I would say that across my UK portfolio we are getting levels of returns that are not sustainable. There is no excess profitability in my portfolio. You can conclude my guys are doing a bad job, which I would argue they are not; they are a very professional company. They have a range of technologies. We are a pretty good estimate of the energy system because we have all the technologies, everything apart from nuclear. Unless nuclear is making all the money, and I do not think so, then there is no excess profitability in an average generation business. I do not recognise that number at all and thanks for asking the question.

Let’s see what the other panellists make of that figure.

I would agree. I do not believe for a second that £500 of your bill is in profit.

How much of it is then?

The problem is that we just do not know and we have no way of knowing. I agree that we should.

“We do not know but we know it is not £500” is not the most compelling piece of evidence ever.

Let me talk you through that in a little bit more detail. Throughout the market you have a visibility of what individual companies are making, so their earnings before income tax, debt and so on. You can see for individual generators how much they pay in the market and how much some of them are making in returns. You can see where certain companies are doing very well and there are companies in the power system that are doing very, very well. It is probably very important that you find ways of aggregating those much more systematically. Especially to your point on networks, a proper understanding of how much networks are making and their returns, because it is very specifically the role of the regulator to hold down that return versus the benefit to the public, will be very helpful. Those numbers are available but only intermittently. Providing them more consistently would be very helpful to the consumer.

I would agree with that point. I also do not recognise that number that was quoted in the earlier panel. To that point around transparency, yes, I would agree. It is probably not possible to give that level of transparency, but I think that we can explain a bit more what returns are made by some of these network companies. Yes, to Adam’s point, it is very tightly regulated. There are years and years of negotiations balancing what investment is needed with what is possible and what returns can be expected. Yes, we definitely should not assume that they are making huge profits because that is just not allowed by the regulator. To that point around transparency, what I have noticed when this investment in networks was announced is that a lot of the headlines were about this investment in the electricity grid adding to your bills, which is simply not accurate. I think that there is also a point there about how we communicate this to constituents, to bill payers. The media also plays a part in this because a lot of that investment is going to gas distribution and transmission and some of it is not necessarily linked to the fact that we are adding renewables into the system. We would need to make that investment anyway to modernise those networks. Some of those assets are out of date, so again they would need to be replaced. It is just one of those investments that is necessary and we are making it for future generations. If you are looking at the time when you make these investments and when constraint costs are peaking, it is quite unfortunate that they are all landing at the same time. One proposal that we have is whether those constraint costs could be amortised over a longer period of time because they are not going to be this high after the 2030s, for example, because we will have built that grid. Again, in the interests of protecting consumers there is a point around spreading those costs for a longer period of time rather than recouping them in one year because it is quite a lot that is getting added to bills at the same time.

I hope you all appreciate that for our constituents not knowing how much profit is being made and not understanding their bills leads to great suspicion about what is really going on.

On the lack of transparency, we all post accounts at Companies House, and we all pay UK corporate tax, so there is a lot of transparency. We all do our financial profitability to Ofgem at its request. I think that there is transparency there. We had to pay the EGL during covid when our prices did go higher. We made very significant EGL payments; therefore, we had to report what our earnings were. There is transparency, and I can be very transparent. My profitability across my UK portfolio is below where you would hope it to be for sustainable returns. There is good transparency in lots of detailed places, but that is the regulator’s job to ensure that it is monitoring that and that is what it does. It looks at all the trading activity we do. It looks at the way we do bids and offers, it investigates people, and sometimes it fines people.

We will put those points to the regulator, Tom, worry not.

Very briefly, we have heard in both sessions lots of mentions of short term, long term and medium term. What does that mean in your world? When we are talking about an inquiry into the cost of energy and how we get bills down, what is a realistic way to do that in the short term and what do you mean by short term? We have heard more optimism about longer term, whether it is post 2030 or anything else. I guess probably a cheekier question, given some of the evidence, is: would it be fairer to say that Government and ourselves should perhaps start talking about this investment increasing your bills by less rather than it bringing your bills down?

I think that there are a few things you can do in the short run. There are questions—

What do you mean by “short run”?

By short term I mean before 2030 and ideally within the next couple of years before the end of the Parliament. There are some questions around the long-term returns in the sector. Let’s be transparent about that and let’s also find ways of moving some costs away from the consumer. There is a reasonable argument to say that constraint costs are essentially a function of trading in the system and, therefore, are an externality. If you are making a trade that pushes up the cost of the system, you should probably pay for that. That would help take some cash off consumers’ bills. It is worth looking again at the extent to which we can force the networks to be cheaper by introducing more competition. That is something that the powers already exist to enable us to do, and the regulator for reasons that escape me has failed to implement that. I would also think you could probably take gas out of the market much more quickly than some of the other panel members may believe, but if you did that reasonably promptly you could help hold down wholesale prices.

I am probably not going to give you the answer you want. I think it is very difficult to—

A truthful answer is always the answer we want.

As a company, because we look at wholesale, we do not tend to forecast end bills, but it is very difficult to see. There is lots of reasons why they are going to go up. We have had a whole period of underinvestment in infrastructure and now you are building it. The problem you have is while you are building it, effectively the way the RAB works, the regulated asset base for the transmission and distribution companies, they start earning as soon as they start building, not as soon as it is ready. You get this double-whammy where you are paying for them to build it but while they are building it you are taking out lines, so you are also getting higher constraint costs, which was Ana’s point. For not building, you are getting those costs. That is where we are. That is in the short term. I think it is going to be very hard. You can do things like what the Government did, put some into taxation, but is it a real saving? It is ultimately the same UK households that are paying it in a different allocation. It is very difficult. On your point about the counterfactual, I think this is the point. Versus the counterfactual it can be cheaper, but consumers do not care about the counterfactual. They do not sit there and go, “Well, it would have been higher”. They just look at last year’s bill. After that it becomes quite difficult. It is things like trying to spread constraint costs. It is trying to offer long-term contracts instead of short-term contracts, but it is hard. Where you get to ultimately, which was I think a point made by Polly Billington before she left, you are putting all this money into infrastructure, but you are not really increasing demand. If I think about it in pound per MWh, you are increasing the pound because you are putting more assets in the ground, you are putting in more wires, but currently we are not seeing that MWh increase. We really need to encourage electrification because then what you are doing is you are also increasing the MWh so the pound per MWh will become more efficient. That is a medium-term objective because we are not deploying heat pumps—

What is medium term?

Five years plus.

Short term is 2030, medium term is 2030 to 2035, and long term is post-2035?

Yes.

There is not much to add to that. It is difficult to do stuff within a year or so because we are seeing those costs of building new infrastructure that get passed on to bills. To Tom’s point, we could probably rebalance some of that, so we do not pay as electricity consumers to build this new infrastructure. That is quite regressive. You also have the costs of gas anchoring those bill prices. It is a bit lower right now but there are always fluctuations. Even now, the bills have not gone to the levels that they were pre-gas crisis. Obviously, we have counterfactuals. There was a study from UCL that was released about a month ago showing that renewable build-out has saved consumers about £104 billion or so in the last 13 years, but I totally appreciate that the counterfactual does not necessarily help consumers. It is also something about how we message some of this. Having an electoral promise that we are going to lower bills by £300 by the end of the Parliament based on I am not exactly clear what is difficult. It is leading to short-term decisions that might not help us in the long term. Some people might say if we do not build the grid now that is going to lower bills, Well, yes, artificially, but we are going to be in the same situation that we are in now with high constraint costs and then we will have to build this infrastructure at some point in the future anyway.

That is really helpful. Thank you.

Thank you all very much for coming in and for bearing with us while we voted. That is the end of our session.