Energy and Climate Change Committee
Oral evidence: Security of Supply 2014-15, HC 509 Tuesday 24 November 2015
Ordered by the House of Commons to be published on 24 November 20135.
Members present: Mr Angus Brendan MacNeil (Chair), Rushanara Ali, Glyn Davies, James Heappey, Dr Daniel Poulter, Antoinette Sandbach, Tom Blenkinsop, Julian Sturdy
Witness: : Cordi O’Hara, Director, UK System Operator, National Grid, Duncan Burt, Head, Operate the System, National Grid, and Roisin Quinn, Head, Energy Strategy and Policy, National Grid, gave evidence.
Q1 Chair: Can I ask witnesses from the National Grid to state their names for the record, please, before we begin questioning?
Cordi O’Hara: Good morning. My name is Cordi O’Hara. I am director of the UK system operator in National Grid and I oversee the financial and operational performance of the system operator.
Roisin Quinn: My name is Roisin Quinn. I am head of UK energy strategy within the system operator business and my department is responsible for preparation of the future energy scenarios.
Duncan Burt: Good morning. My name is Duncan Burt. I am head of Operate the System for electricity transmission. My responsibility covers the real-time control rooms responsible for the real-time operation of the power system and for the associated support functions that go with that.
Q2 Chair: Thank you. First, your “Winter Outlook” predicts a derated capacity margin of 5.1%, which you describe as manageable, but there are widespread concerns that the lights could go out this winter. Can you begin by cutting through the jargon and telling us exactly what this 5.1% margin means in practice and if there are other figures in there as well surrounding that 5.1%?
Cordi O’Hara: Every year we do a lot of analysis and planning around the margins we expect to see on the system. That is an extensive engagement process with the industry to understand both the generation available and the expected demands on the system. We also then look at a wide range of credible scenarios that we might see on the system, such as the impact of adverse cold weather and of interconnector flows, and all sorts of things that we could expect and foresee on the system.
In terms of our role, we then procure balancing services in order to manage the real-time supply-demand matching, and that is done to a security standard that is set by Government. Within that analysis, we engage with Ofgem in the procurement of balancing services and we have taken quite a lot of action this winter to make sure we have the tools in place that we need. The outcome of all that analysis, planning and engagement with Ofgem has meant that we secured an extra 2.5 gigawatts of reserved products, both in the form of supplemental balancing reserve, which is a generation product, and demand-side balancing reserve, which is a contract with large energy consumers to shift their consumption upon our instruction and by their invitation through the contract. Through all of that analysis we are well within the planning standards and security standards set by Government. We have covered a wide range of credible scenarios that we could foresee on the system and so at 5.1% we are clear that margins are tight but manageable.
Q3 Chair: One of the things you said is all the things you can foresee, and the purpose of this morning will be for the team here and the Committee to probe that quite a bit further. You calculate a loss of load expectation of about 1.1 hours per year for the upcoming winter. Can you explain to us what that means?
Cordi O’Hara: Yes. Loss of load expectation is an international standard that is used by other European countries. It is a three hours loss of load expectation, which means that on average over the year there may be three hours where supply does not meet demand. From that, that does not mean there is necessarily going to be a blackout. It means that the system operator may need to take action with its balancing tools.
Q4 Chair: Given all that and given the outlook, were you surprised that you had to issue a NISM—a Notice of Insufficient System Margin—as early as 4 November this year?
Cordi O’Hara: Just to put NISMs in context, they are part of our toolkit. Over the last decade we have issued over 100 NISMs to the market. They are a notice to the market to make sure that, when our reserve cushion is a little bit lower than we would like, the market is aware and they are able to take action. This could mean that extra generation is brought forward and/or demand may be reduced at times of peak and, therefore, no further tools are required to be used by the system operator. In terms of 4 November, I would like Duncan to take you through a bit more of that in detail.
Duncan Burt: Yes, I can add a bit more context about 4 November if that is helpful. It is not unusual at certain key points of the year for us to see tightness in the market away from some of the high-demand peaks that we would see right in the middle of winter.
Q5 Chair: When was the last time a NISM was issued before 4 November?
Duncan Burt: I believe we have not issued a NISM since 2011. It is a good few years, but the market has been in a stronger supply position over the last few years. What we saw coming in to this November is a selection of power stations still on outage, so still undertaking maintenance work. That is quite usual. A lot of power stations take an outage or take maintenance work over the summer when demands are lower. Then, as we come towards the winter, they will return to service and begin generating again. At the end of October and early November we still have some plant on maintenance. As that then comes back, hopefully demand matches at the same time. What we saw on 4 November is the market remaining tight, with some plants still on maintenance but demand beginning to pick up. Then through the morning of the 4th we saw a significant amount of plant loss, with generation units coming off in the late morning. That then caused us to issue a notification of inadequate system margin.
As Cordi said, that does not mean that we immediately have a problem. It means that we do not have all of the safety cushion that we would like to have running into the teatime peak at 5.30 pm. That notification is about giving information to the market. After we issue that—
Q6 Antoinette Sandbach: Can I interrupt you on that? You issued your notification at 1.30 pm. There was a gas-fired power station—which I think is owned by Calon Energy—that started powering down at 3.00 pm. You offered an electricity price—well, the NISM prices you paid I think were £419 per megawatt hour, which is seven times what the market cost would have been—as high as £2,500, which was not taken up. Were you satisfied with the industry response to the NISM?
Duncan Burt: We would expect a number of things to happen. Information is key because, as you say, at the end of the day it is the market making plant available that is going to deliver that security of supply. After we issue a NISM we would expect plant that is running to become more reliable, to effectively make extra efforts to be reliable and to stay generating through the afternoon. We would expect any plant that is not available or was planning not to run to make itself available to us wherever possible. We would also expect to see an additional suppression in demand as people move their demand away from that peak period, either to help security of supply or because they know that prices are likely to be higher because the market is tight. Through that afternoon we saw good reliability, so we are very happy with the market response in terms of that. We did see additional generation make itself available. Now, for the specific actions of any particular generator, you would need to turn the question to them directly to ask what they were doing, but we were—
Q7 Antoinette Sandbach: Do you have any ability to speak to that generator, because there is an EU requirement to report if there are operational difficulties? Did you make contact with that generator?
Duncan Burt: We made contact with that generator through the afternoon, yes, to assure ourselves that they were available for the peak. We would expect any generator to run in line with its contracted position and in line with the technical parameters of that plant. With regard to our role on the day, as you can imagine the control engineers are very focused on ensuring that plant is available, understanding its technical parameters and then using it where we needed to use it. As you say—
Q8 Antoinette Sandbach: You will appreciate that there have been reports that that particular generator—I do not know whether or not that is true—received 25 times the market price effectively for reducing demand at 3.00 pm, only to increase it again to cover your NISM at 4.30 pm to 6.00 pm.
Cordi O’Hara: I think it is important to focus on the role of the system operator and what we are trying to do at those times of peak demand. It is clear to—
Q9 Antoinette Sandbach: No, I would like you to answer the question if possible. I would like you to focus on what steps you took in relation to that generator, given the cost to the UK consumer.
Duncan Burt: If I can walk through the dispatch for the afternoon, the control engineers will have seen the change in load position for that generator with it coming off. It is more unusual on a peak day like that, but it is not unusual for generators. Obviously, in line with their contracted position, they could be coming off any time, day or night, in line with the power that they have sold. The control engineers continued to hold that station on by accepting the offers available from it in the market in the balancing mechanism. Just shortly after 4 o’clock we were alerted to the fact that their price had increased significantly, up to £2,500 a megawatt hour, as reported in the FT and elsewhere. At that point obviously our overarching job is to maintain security of supply and to do that at the minimum cost we can for consumers. The engineers responded by looking at the other options that we had available that did not involve that plant and developed very quickly—within about 15 minutes—a strategy that meant we could cease our purchase of energy from that plant as soon as was feasible, just after we got over the peak. That is something we did. Then—
Q10 Antoinette Sandbach: Effectively, are you saying it is possible for these providers to game the system once you have issued a NISM?
Duncan Burt: In a tight market, whether there is a NISM or not, we would expect the market to feel that and for prices to rise, both in the forward market and then in the balancing mechanism. That is the short-term market that we use for the finessing of supply and demand balance that we do at short notice. It is important to be clear that we are not doing that in isolation. We are working very hard to minimise the costs of doing that and then Ofgem has an oversight role in terms of behaviour in that market and pricing in that market. We have a regular conversation with Ofgem about what we see in the market and how things are acting. Of course, we have given them a lot of information about 4 November. We have looked very carefully at that, not just because of pricing on that day, but because that is our first signal for this winter of a whole range of things, such as plant reliability over the peak, as to the level of demand suppression that we can expect on tight days. That will inform the actions we take over the rest of the winter. Yes, on things such as pricing behaviour and physical behaviour Ofgem has overarching oversight of the market in that regard.
Q11 Antoinette Sandbach: Looking ahead, how many NISMs do you expect to issue this winter and what consequence do you expect in terms of consumer bills?
Cordi O’Hara: We have looked historically at the range of NISMs we have seen; in equivalent margins that we have today and in the past we have seen a range between seven and 10. NISMs can come about through a range of conditions on the system, so we tend not to forecast how many. What we said in our “Winter Outlook” report is that we might expect to see some based on the year-on-year shift in tightness and what we have experienced in the past.
What we can say is that NISMs are a very useful part of our balancing toolkit and, historically, we have seen a very good response from the market when we issue that notice. It is important to issue that notice to the industry because that allows us to access additional tools in our toolkit. We are not allowed to use those tools until we have notified the market and given it an appropriate time to respond. We cannot point to a specific number of NISMs. We expect to see NISMs with a slighter tightening of the market year on year.
Q12 Julian Sturdy: Can I come in on this point, Chair? It has been suggested, though, that you are looking at maybe seven NISMs being issued this winter. Is that correct?
Cordi O’Hara: What Steve mentioned in his discussions was the historic number we have seen, which could be an indicator of what this year could be. In a similar margin winter as this year we experienced between seven and 10. I think what we have tried to do is provide some historical context, in like-for-like margin terms, with the amount of NISMs that we issued when we were roughly around 5%.
Q13 Julian Sturdy: You are expecting to see seven to 10 NISMs this year. That is what you are saying?
Cordi O’Hara: What we said is that we expect to issue NISMs this winter. If you look at history, you might see that they could be in the range of seven to 10. Our system is very different from the previous winter’s tightness. We have slightly different characteristics of generation on the system. We have more embedded generation in the distribution networks. It is very hard to be predictive. It could be caused by a number of weather events, which we are obviously monitoring and forecasting for, but it is very hard to be as pinpoint accurate as that. What we are trying to do is be helpful and say at periods of similar tightness on the system we have good experience of using NISMs and on a similar margin level we have issued between seven and 10.
Q14 Julian Sturdy: If we go over seven to 10 NISMs this year, what is the concern level? If we got to 20, would that be of concern to you?
Cordi O’Hara: For us NISMs are just the start of using our toolkit to help us balance the system minute by minute. It is the first step in making sure that we have the right amount of reserve cushion. This is a notice. This is actually saying—
Q15 Julian Sturdy: Sorry to interrupt, but you must have a level that would say that this is of concern. You must have a level where you say, “This is going to cause problems and also further cost to the consumer”?
Cordi O’Hara: The NISM is the start of a range of a series of activities. It does not mean the lights are going to go out. Issuing a NISM is the first step of trying to build up our reserves.
Q16 Julian Sturdy: I am not saying that it is. I accept that. But when you get a NISM—as we saw at the beginning of November—costs rise. There was a real peak rise in energy prices. If we are seeing more NISMs this winter, if we go beyond seven to 10, if we go to 20, then we are going to see those continued spikes. What would that ultimately cost the consumer?
Duncan Burt: What we will be watching closely is the underlying factors that lead us to issue a NISM as a first information bulletin in a range of tools we have. If I can give you a feel for some of the factors that might drive that: as we look at the winter and we look back over the last decade at similarly tight periods, the kind of factors that could drive us to issue more NISMs would be a higher level of plant unreliability. It would give us concern if we saw that, but that is something we are monitoring very closely. When we look over this winter and the last few winters we have not seen any appreciable change or, in particular, an increase in plant unreliability during tight days. We could see more NISMs if the weather was colder and, therefore, pushed demand up higher and made the system more regularly tight. For example, over the last few winters it has been more wet and windy; I think the Committee can probably recall that.
Chair: Tell me about it.
Duncan Burt: Exactly. If we see more of a wet and windy winter, then we would probably expect to issue fewer NISMs, all other things being equal. We will look very closely at those underlying factors. You are absolutely right that some of them would give us concern if they related to plant unreliability or, in particular, if we did not see a market response following a NISM, so if we were issuing NISMs and then we did not see an improvement in plant availability.
Julian Sturdy: Chair, a last very quick question.
Chair: A quick answer if we can, too.
Q17 Julian Sturdy: Coming back to something you said earlier, Mr Burt, when you were talked about plant coming offline for maintenance, it surprised me a bit to see that plant was offline at the beginning of November. I would have expected it to be offline during the summer. What is the period when you would expect that plant to be offline? Is it unusual for a power station to be offline at the beginning of November? Because I would have expected that to be the start of a period when energy usage will be rising and going up.
Duncan Burt: You are absolutely right to highlight it as a transition point. To get your eye on it the bulk of plant outages occur during the summer, so from April through to September. Because that can be quite a squashed area, you do see stations take outages on a particular unit through October and into November and it is not unusual. In fact, it is very regular for us to have a few generating units continuing to be on outage through to mid-November. That is linked to demand because, again, demand does not start to rise to full winter levels until the very end of November.
Q18 Julian Sturdy: We are not expecting any outages over the winter; none planned?
Duncan Burt: We will see a very low level of continued planned outages through the winter and some unplanned. The planned outages will relate to statutory outages that generating stations have to take for insurance or safety inspection. That could be pressure, if you are a coal or gas generator, in your pressure vessel, or it could be for nuclear safety if you are a nuclear operator.
Chair: Thanks very much. There is quite a lot of interest in this area among colleagues. I want to go to Dan, then to Glyn, then to Tom and then to James, so if you can be mindful, team, that there are a number who want to get in, so keep your questions short and snappy.
Dr Poulter: Hopefully, if we could keep the answers relatively short that would be kind as well. I have a few questions for you, so it would be quite helpful to get through those.
Chair: Thanks, Dan.
Q19 Dr Poulter: First of all, looking at the current reserve that you have, what is your current reserve both in terms of wattage and percentage and what was it, let’s say, 10 years ago? That should be quite easy.
Duncan Burt: Very quickly, in terms of numbers, we hold a basic reserve level of around 2,500 megawatts or 2.5 gigawatts to cover for generation reliability and demand forecast area. We hold another 1,000 megawatts or 1 gigawatt on top of that to give us automatic very short-term regulation to balance the frequencies. Then at timescales of longer than four hours we hold up to about another 1,250 megawatts or 1,500 megawatts or 1.5 gigawatts up to 24 hours out to cover for longer-term plant reliability. Over the last 10 years the 2.5 gigawatts and 1 gigawatt numbers have not really changed—they have remained very stable—but the longer-term reserve has come down significantly because we see much greater market response in those longer-term timescales.
Q20 Dr Poulter: What was the reserve 10 years ago or, say, five years ago?
Duncan Burt: The reserve that we hold—that 3.5 gigawatts—would have been about the same and that 1,250 would have been as high as 2,500, so double what it is today. That has come down. We have reduced that level because we have seen the market become much more effective at managing its own reliability position. If a generator develops a fault, they can put another one on. Also, demand has become more responsive in terms of moving if we see periods of tightness.
Q21 Dr Poulter: You are saying that the amount of reserve you hold has halved over the last 10 years?
Duncan Burt: Yes, the amount of longer-term contingency reserve. The amount of reserve we hold in real time is the same.
Q22 Dr Poulter: Yes, absolutely, and then you have this shorter-term reserve. You have 2.5 gigawatts of built-in reserve and you then have an extra reliance you can call upon. Is that, for example, through importing or effectively through interconnectors getting energy in from elsewhere, and also from asking some energy users to switch off or modify their energy usage?
Duncan Burt: Yes. To be quick—I am not being rude—we use information at all timescales to tell people how tight the market is. That is incredibly important. In periods of tightness we would expect people to improve their reliability, make additional stations available and also move demand away from the peak. We also have a range of tools available to us so that we can call on additional power flows through the interconnector, if they are available, in France or the Netherlands or Ireland. We have had additional balancing tools available to us for the last few years in terms of DSBR or SBR, which we can call on once we have issued a NISM.
Q23 Dr Poulter: Earlier on you talked about plant unreliability. What factors may cause plant unreliability for you? Would an older plant be less reliable, say, coming towards the end of its life than an energy plant that was earlier in its lifespan, for example?
Duncan Burt: Without drawing a new versus old, very much an old plant can also be very reliable because it is known to the team. They tend to have worked on it for a long time. They can be very familiar with the issues around it, a bit like a much loved car. Power generators are big, complicated bits of industrial equipment, so they do develop faults. For the Committee, it is worth bearing in mind that we probably typically see two to three power-generating units develop a fault and come offline every day in the run-up to the peak. That is why we hold reserve to cover for it. Typically, a fault can be an issue associated with the heat and the pressure system, which typically is called a tube leak where you get a leak in the steam system. You can have an electrical fault on the power generator itself or, if it is a coal unit for example, you could have a problem with the mechanical process to move the coal through the machine and into the boilers, so you have a problem with the mills or the thing grinding up the coal. It can be a whole range of mechanical or electrical issues.
Cordi O’Hara: If I can quickly add, in terms of our central planning, we look back historically over seven years and we look at the breakdown rates we see by generation type. We do a lot of analysis to understand historic patterns of breakdowns and we call those derating factors. Within our central assumptions we will expect that these are real assets with real issues that will be managed and maintained throughout the winter. There will be a level of ongoing maintenance or temporary faults that we should accommodate within our planning.
We have also done an international study on that with Arup to see around the world how those derating factors change by technology type and by age. Within all of our planning and analysis—and Ro can go into that in extensive detail—we will be looking at the historical breakdown rates, what we have seen, so that we are already accommodating that within our scenarios.
Q24 Dr Poulter: You used the analogy of a car. As we know, obviously a car gets older as any plant or industrial equipment gets older and, inherently, it becomes potentially less reliable. We have a lot of power stations that are coming towards the end of their lives fairly soon. First of all, in terms of reliability, but also, secondly, in terms of what is not a large reserve that you have today compared historically, how have you factored in the potential loss of those plants and the age of those plants into the energy model, because that is clearly key in terms of NISMs and capacity to keep the grid going?
Roisin Quinn: When we first look at the capacity of plants, when we are building up our future energy scenarios that underpin all of our analysis around security of supply, we will look at the potential build rates of new plant and also the closure rates of existing plants. We will also look at what information we have from the owners of those assets, what other information is available in the market. We will test that with a wide range of stakeholders to build up that picture of what the likely capacity is on the system and how that compares to varying demand levels. We will flex both the supply side and we will also flex the demand side to really understand that picture.
Then, when we are thinking about the reliability of specific assets—as Cordi mentioned, we have looked over seven years to consider what we know the plants will contribute to security of supply—we will focus in on peak periods so we understand what their expected contribution is. We have also then looked at some subsets of that data to understand whether there has been a trend. If we look at just three years’ data or two years’ data, how has that performance changed? In the shorter term, we will then look again at what information is made available by the market and what information we make available to the market to see how they respond.
What we have found so far in the assets is that it is too early to say if there has just been a sequence of one-off events that happened to take place at a similar time, or if we are at the start of a trend of changing performance. We keep that under review and continue to monitor and update that analysis, to make sure that we are using the best information in our own planning and that the best information is available to the market so that they can respond to that change as well.
Q25 Glyn Davies: There is one question and it is a response to what people ask me: we saw the press coverage and often we cannot understand quite why prices rise to such an extent in a period of shortage. I can understand the general principle, of course, but is there some kind of formula? The scale of price increases that were reported has horrified people. They are massive. Is that just power companies charging you whatever they want, or is it based on some kind of formula, or is it adjusted by something or other?
Cordi O’Hara: It is a free market and assets—generators—will create their own bidding strategies. It is important for the Committee to note that, where the market makes generation available, we are obliged to take it before using our emergency measures. We are incentivised to balance the system at the lowest possible cost for consumers within the rules with which we perform our duties. On that day, we would expect prices to rise to reflect a shortage and to incentivise any additional marginal generation to make itself available. On that day in particular we recognised the need to take part of that generator on to manage the peak, but we were very conscious with our incentives to keep those costs low to consumers so that we took it off as soon as we could.
Q26 Glyn Davies: If there is going to be a particular shortage, do you know when the prices are going to rise, or can the generators just decide among themselves what they are going to charge you?
Cordi O’Hara: Generators will price their assets into the market according to their own cost base and their own margin expectations.
Glyn Davies: Nice work if you can get it.
Cordi O’Hara: The market is overseen by Ofgem in terms of any perceived market abuse and that is their role versus ours, which is the physical balancing of the position on the day with our incentives to keep that cost as low as possible.
Glyn Davies: I want to move the questioning on to an area I want to ask about.
Chair: Sorry, I am going to pull James in on this point before we move on.
Q27 James Heappey: I want to stay on the cost, Mr Chair, if I may. The reporting of the cost of the NISM around 5 November was that it was at least £2.5 million. What was the actual amount?
Cordi O’Hara: We are still doing the calculations, but I believe it is broadly accurate.
Duncan Burt: Yes, that is broadly accurate. It depends—
James Heappey: Not significantly more?
Duncan Burt: No, exactly.
Q28 James Heappey: Your projections of seven over the course of the winter is that £17.5 million—the best of £20 million—is going to be spent this winter in meeting the cost of the NISMs. It has been suggested in some of your answers that NISMs are just the first in your toolbox, but they are actually quite expensive and that is only if we hit your expectation and do not exceed it. At what point do you start to be concerned about the cost of these NISMs over the course of a winter? What is your feedback loop and how do you ensure you do not spend £20 million unnecessarily?
Cordi O’Hara: I think we have to put each NISM in its own context. We have had a price over a half-hour period that we took on 4 November, but each NISM will have its own set of market circumstances and criteria. I do not think it would be fair to project the cost on that specific day as necessarily being predictive.
Q29 James Heappey: It could be higher, couldn’t it? It could be significantly higher?
Cordi O’Hara: It could be lower or higher. I think we have been as transparent as we can in terms of the additional tools that we have procured for this winter. As per the earlier discussion with Mr Poulter, we have bought an additional 2.5 gigawatts of supplemental balancing reserve this winter, which is where we hold generation in reserve to use as a last resort measure and also contracts with demand-side providers as well. We have been clear that those costs are incurred through an open tender for the services and volumes. They are overseen by our regulator, Ofgem, and the cost of those tools is equivalent this year to less than £1 per household.
Q30 James Heappey: You are a public company. You can understand how consumers would be very frustrated if you are expecting to cost the taxpayer £17.5 million over the course of a winter by declaring these NISMs, when it is foreseeable we could have ensured that the capacity was available if we had managed things better.
Cordi O’Hara: In terms of the NISM and our use of the tools, it is important to note that, within our procedures, we have to issue a NISM before we can access our tools. The NISM should then generate a market response, which will have a cost, but it is by no means that this last cost is predictive of the future cost. There is a cost of securing supply to the security standard, which has been set by Government, and it is important that we make cost-conscious choices for the consumers in the procurement of those services. That is why all of our analysis and recommendations are overseen by the regulator and then, within our own incentives regime, we are incentivised to minimise those costs every day we balance the system.
Q31 James Heappey: That is the final thing I wanted to be clear on. Is there an amount that you spend on NISMs in the winter at which point Ofgem comes knocking on your door saying, “That is too much”?
Cordi O’Hara: There is a constant market insight and feedback loop to Ofgem. They will want to be sure that we are operating within our roles and responsibilities. There are very strict methodologies on how we use our tools and we have to demonstrate appropriate use of those tools every time we take action. There is an iterative feedback loop and, if we do not use those tools effectively, we will not be funded for the use of those tools.
Q32 Tom Blenkinsop: Just very briefly, between February and November last year, manufacturers, in particular, were complaining about the costs. If you take someone like Tata speciality steels, they were having to shut down every day between 4.00 pm and 6.00 pm and accidentally switched on for production for 30 minutes, which cost them £1 million. Another site like Forgemasters, to turn the kettle on so a guy working in the foundry there could have a cup of tea cost the company £27. How do NISMs affect manufacturing and did it benefit them between November and February, or does manufacturing, in effect, pay for the consumer to have lower energy bills?
Cordi O’Hara: There has been a lot of discussion based on the use of our demand-side balancing reserve on 4 November, and I would like to take a moment to clarify how we use demand-side response generally. Demand-side response is a commercial contract with those businesses. We are not asking them to power down. They are volunteering to offer their services in order to shift or move their loads. That could be air conditioning being tweaked for that peak half hour. We see a growing role and need for demand-side tools within our toolkit as the system operator. We think this is an opportunity for businesses, in that they have the sophistication and capability to use demand very differently in the peak time.
Q33 Tom Blenkinsop: It is nothing to do with transmission costs hitting manufacturing harder, particularly in the north?
Cordi O’Hara: We have a regime called triad avoidance whereby users of energy are incentivised to move their load away from the peak.
Q34 Tom Blenkinsop: But that is getting smaller, isn’t it? Take steel, for example, or another industry. As those players in the market withdraw or liquidate or go bust there are fewer companies within that triad. That means the bill is spread over a thinner group of companies, isn’t it?
Cordi O’Hara: There is a range of different providers participating in triads, so it is not only demand players reducing their energy. It is also new and better generation, small diesels that can contribute to managing that peak.
Q35 Tom Blenkinsop: A lot of those demand players provide energy to the grid, for example SSI in Redcar, which now no longer exists. Its coke ovens were supplying energy to the grid, yet it was getting hit with massive transmission bills.
Duncan Burt: If I can break down both sides of that, in terms of the demand that manufacturing or any other site is taking, the triad product that Cordi is referring to allows a facility with the ability to do so to move demand away from peak periods to use it at other times. That is very useful for us because it helps reduce network investment and minimises the cost of the transmission network on consumers. It also helps that manufacturing facility or industrial facility minimise its costs by, again, not adding to the burden of the transmission network and not using it when they do not need to.
Q36 Tom Blenkinsop: Will a NISM cost manufacturing more or less?
Duncan Burt: To walk through how we would see that feedback loop, all the NISM does is recognise that the market is tight. Very often, when we issue a NISM we have already seen prices rising in the market, again, because we have a scarcity of supply. The NISM reflects that. I would say that on occasion it can prompt—
Tom Blenkinsop: Will it cost more or less?
Duncan Burt: That then feeds into the wholesale price. The price that an industrial site or an end consumer is going to pay for their electricity will be linked to the longer run wholesale price but will tend to reflect the average, for example, of—
Q37 Tom Blenkinsop: Do you think it will cost manufacturing more or less between the period of November and February?
Duncan Burt: In the short run, I would say that it will not change that at all because people will have priced in tight periods over the winter. We flagged well in advance that the market is tight. There has been extensive discussion around the industry.
Q38 Tom Blenkinsop: These firms are just shutting down for two hours every day for three months?
Cordi O’Hara: On 4 November we did see demand reduce over that peak period. That will be a function of some businesses seeing our information, noticing that it is tight and they have an ability to shift and change their production away, so reduce their consumption over that peak period. Other businesses we contract with directly. We do see that that is favourable for those businesses because they have priced the cost of moving and changing their patterns into the contract price. We do see that as a growing market and an opportunity for businesses to lower their costs as well as to contribute to our role of balancing the system.
Q39 Chair: Surely that is not the core purpose of these businesses, to be playing or gaming the electricity market; it is to be doing their core function.
Cordi O’Hara: What we see is that with smarter technology enabling businesses to better understand their demand, this is an opportunity for businesses to move production away from peak periods, to move it to periods of surplus where that could provide an advantage for the business and lower cost. Over time, we expect to see demand-side response evolve to the new system dynamics. We expect this to be an opportunity for businesses and through our Power Responsive campaign, where we are working across the industry and with specific businesses, we are trying to encourage and understand what it will take for more businesses to be able to contribute in this way. We worked extensively with Sainsbury’s, for example, on their energy procurement.
Q40 Antoinette Sandbach: Can I pick up on something you said? You said that businesses volunteer to reduce their consumption. In fact, you pay them or they are paid, are they not?
Cordi O’Hara: Sorry. Yes, they volunteer through our tender. They price at the point at which they are happy to change their consumption and if that is a cost-effective balancing tool for the consumer, and helps us fulfil our balancing role, we will absolutely contract with that demand-side player.
Q41 Antoinette Sandbach: In effect, they can be paid for reducing their demand at peak periods, which allows you then to supply to other areas at that time?
Cordi O’Hara: Correct, and why we see this as really important for the future is if we can harness more of that intelligent use of electricity and pay energy users to do that, we will avoid the unnecessary build of generation and infrastructure.
Antoinette Sandbach: Can I move on to gas supply?
Q42 Chair: Not yet, no. There is a question that is obviously coming up here. Why has the capacity under the supplemental balancing reserve been acquired at more than 10 times the rate of the demand-side balancing reserve?
Cordi O’Hara: I think that is just a reflection of the market that we are trying to stimulate and grow. The supplemental balancing reserve was set up to capture either mothballed plant or plant likely to be coming off the system near winter. They tender their services into us as we procure balancing services. On demand-side players, we have seen year-on-year growth in the contribution of DSBR to those services. We recognise that we need to engage more thoroughly with the industry in terms of growing those services. That will be helped with the transitional arrangements under electricity market reform this year, where we will run the first capacity auction for demand-side response. Over time, we would expect to see the proportion of demand-side balancing reserve grow and the amount of demand-side products grow as we engage more thoroughly with that market. We are very committed to doing that.
Q43 Chair: What can you tell us about the impacts to the consumers and the environment if we are balancing services, and which balancing services are the most effective and why?
Cordi O’Hara: We need a range of tools to balance the system. We are technology neutral in the choice of those balancing services. Our main focus and drive is keeping the cost as low as possible for consumers. As the market changes, the tools available to us will change. We are going to have less thermal generation on the system. We are going to more renewable generation. That is why we feel there is a real opportunity to engage with demand-side players. If we can construct those services correctly, I think we can procure even more cost-effective services in balancing the system because we will be avoiding the need for the buildout of excessive generation.
Q44 Chair: You said you are technology neutral there, but as we know some balancing services will produce greater carbon emissions. Which ones?
Duncan Burt: In terms of the way we procure balancing services, as Cordi says, we are technology neutral but we do have an eye on what best technology would look like in terms of the provision of that. If I can walk the Committee through the background to supply, for all of our services we tend to buy some from part-loaded large thermal generation, so gas or coal-fired. Historically that has been the backbone of provision, but it is decreasing gradually over time. As Cordi says, we also buy a growing and important proportion from demand-side, and demand-side can mean several things. It can mean either the pure movement of demand—so literally a light or a kettle or an industrial process or more normally air conditioning or air handling—away for a particular period. We will buy services from a range of smaller generators as well, which could be an onsite backup generator at an industrial site or at a TV transmitter, for example, or it could be a smaller gas turbine or, indeed, a larger open-cycle gas turbine. We try to make our products available to as large a proportion of that fleet that could participate as possible because that gives us more competition and, therefore, cheaper prices.
Q45 Chair: In the light of this month’s NISM, are you convinced that the 2.43 gigawatts as the new balancing service is adequate for this winter?
Cordi O’Hara: Yes. We have done a lot of analysis on what is the right size of the toolkit and, to put 4 November in context, as I said earlier, our first step is to issue that notice to the market to see if it can provide before we need to use our toolkit. On that day in particular, we instructed some 40 megawatts of demand-side balancing reserve but we still had at our fingertips the additional 2.5. Even though we have issued a NISM on the 4th, the market did respond and reduce consumption and bring additional generation forward, meaning that we only needed to utilise a very, very small amount of the toolkit that we have procured.
Q46 Rushanara Ali: Can I take you back to the point about technology neutrality? Do you have a way of being able to track which ones do lead to greater carbon emissions, and would you consider doing that if you do not do that work?
Duncan Burt: It is a question I have been asked before previously at this Committee by Mr Byles. Off the back of that, we now publish an annual report into the carbon intensity of our STOR tender, which has caused particular attention because of the number of smaller generators, and in particular diesels, that participate in that. We already do that and have done it for this year for the first time. I would be happy to share a copy of that report with the Committee.
Q47 Rushanara Ali: In relation to NISMs and the balancing processes, you do that for the balancing operation?
Duncan Burt: To date we have just done it for our main tender because that is where particular attention has been focused. On any particular day we will be using quite a different range of potential services, both from generation that is already running and part loaded right through to standby generation, which can then run at two minutes or, for example, 10 minutes’ notice through to demand. We have learnt a number of lessons in unpicking the carbon intensity of our STOR tender, our short-term operating reserve tender, which we could share with you and look through that. That probably provides a good representation and will give you a very good feel for how that carbon intensity is spread across the portfolio of products that we buy.
Q48 Rushanara Ali: There has obviously been a lot of concern in terms of the publicity around the NISM that was issued and some references to the weather conditions and so on. In terms of circumstances where people should be concerned about blackouts, can you guarantee that there will not be any blackouts? That is ultimately what the public will be wondering, having read some of the articles early in November when the weather was not that bad.
Cordi O’Hara: We need to remain vigilant throughout the winter period. It is a constant process of monitoring and updating the market with information. In terms of the work we do to establish our balancing reserves, we try to cover as many credible scenarios on the system that we might face. We are asked to look forward to the future and think what could happen on the real-time networks, how can that be informed by what we have seen in the past, and what is effectively the right insurance policy we should put in place to meet the Government’s security of supply standard? That is set at three hours loss of load expectation and I think Mr MacNeil gave the figure earlier that we have secured our reserves to 1.1, so that is below the threshold and standard set by Government. That process has been overseen by our regulator, who—in us buying those insurance products, those services—makes sure that we are covering an appropriate range of credible scenarios that is also cost conscious for the consumer.
Q49 Rushanara Ali: You have done the scenario planning to guarantee to the public that they should not expect a blackout this winter or in future winters?
Cordi O’Hara: What we have said is that, year on year, the margins are a little bit tighter but they are manageable and that is informed by the toolkit that we have bought.
Q50 Rushanara Ali: The public should not be concerned that there will be any blackouts this winter?
Cordi O’Hara: No system operator in the world will give you a 100% guarantee but what I can assure you—
Rushanara Ali: What sort of guarantee can you give in the light of the scenario planning that you have done?
Cordi O’Hara: What I can assure you is that we have done extensive and robust analysis that has been overseen by an independent regulator.
Q51 Chair: What is the statistical certainty of this robust analysis that has been done?
Cordi O’Hara: The statistics we need to focus on are the three hours loss of load expectation, which is the security standard that we need to operate and that has been set by Government. We were well within that standard at 1.1 hours loss of load expectation.
Q52 Antoinette Sandbach: Does that cover storm damage to transmission lines? For example, Storm Abigail had an impact in Scotland recently.
Cordi O’Hara: We will cover a range of weather scenarios. We are particularly focused on cold weather and the impact on demand. Separately, we look at the resilience—
Antoinette Sandbach: Sorry to interrupt—
Chair: I am going to keep Rushanara on, sorry. Rushanara?
Q53 Rushanara Ali: Thank you. I think we need much more clarity and certainty, and I appreciate that you cannot give an absolute guarantee. There was a reference earlier to a point about market responsiveness and some of the risk factors. You mentioned weather and plant unreliability, but, Mr Burt, you also mentioned that if there was a potential risk for the market not responding to NISMs that could present a problem. Could either of you expand more on what you were getting at there and what risks would be posed in terms of making sure the lights are kept on?
Duncan Burt: Yes. Materially, security of supply is delivered by the market investing in generating equipment—both new and maintaining the reliability of existing generation equipment—and investing in alternative services such as flexible demand. Suppliers then contract for that energy ahead of time. We put out through our future energy scenarios and other information streams an awful lot of information around likely levels of demand and the range of uncertainty around that. We see those as big factors in underpinning market investment. In recent years, that has been further underpinned by Government policy, with electricity market reform coming in and the capacity mechanism effectively providing an underpinning to investment in new generation. We see all of that then flowing through to having good availability of capacity in real time, which we would obviously continue to monitor through our “Winter Outlook” report and suchlike.
When we get into the week and then the day in question, in terms of market responsiveness, we would want generators and suppliers to be looking at their portfolio of plant and being on top of it, understanding the technical limits of it, making sure it is well maintained so that it is reliable. On the day when we do issue a NISM, or any tight day when we see a market response, what we tend to be seeing is generation that maybe was on short-term maintenance come back very quickly or, for example, a generator that had a fault the day before, the team worked through the night to make sure that it is back by 10 o’clock in the morning, rather than letting it run through on outage the next day. Those kinds of responses, where people act quickly and move quickly to either make their unit more reliable or to get it back as quickly as they can if it has been unreliable. I hope that helps. That is the sort of response we would be expecting.
Cordi O’Hara: If I could add, in terms of the risk assessment, there is extensive analysis done and that is overseen by a panel of technical experts as well, their advisory role. They are there to challenge and review that assessment. Three hours loss of load expectation is the standard that has been set by Government that we absolutely must meet as a minimum criterion. It is really important to understand that assessment.
Q54 Rushanara Ali: Looking to the future, with the recent announcement about coal, and with nuclear decommissioning and so on, what is your assessment going forward of how that impacts on how you respond and make sure that the balancing services are appropriate to what the market looks like and the supply chain?
Cordi O’Hara: We are already doing extensive work on winter 2016-17. We are expecting a level of coal closures and the retirement of less efficient thermal plant as a feature of decarbonising the energy sector. That is something we model out to 2030, and clearly there are other forms of generation coming through as well. We need to look at both the deficits and the positives. We have taken action already for next winter by consulting with the industry on extending our balancing services. That consultation has already delivered and we will be able to extend the balancing services for winter 2016 and 2017. The next step we have taken is to then issue a tender to the market encouraging both generators and demand-side players to contribute to the tender. That tender will be closed at the end of November when we will be able to be clear on the amount of services we are buying through that first tender.
Q55 Rushanara Ali: I have one final question. You have said that you could not give a complete guarantee, a 100% guarantee. I hope you can give the public close-to-certain confidence that there will not be blackouts. In the event of a worst-case scenario, of course, there is an issue around controlled disconnections, with localised blackouts and so on. Can you shed more light on how that would work in practice and how you would make sure that people did not experience blackouts for too long? We have seen some examples of that recently.
Duncan Burt: Yes, exactly. A day where that is going to occur would start, one would expect, with the market being tight anyway. We almost certainly would have issued a NISM either overnight or through the morning in the run-up to the critical period, which would likely be the teatime peak at about 5.30 pm. That NISM would remain in force and be updated. If things continued to get tight, either because we were not seeing a market response or because we had seen additional plant loss or very high demand, then we would issue something called a high risk of demand reduction, which is effectively a warning to be ready for the next stage. At that point, we would also then be using the significant volume of balancing services we have. We would be looking at the market response and ongoing reliability. Again, it is important for the Committee to remember that most of the time that is going to be absolutely adequate. It will serve all our needs, cover supply and the demand will be met over the peak.
If we continue to have difficulties or saw further losses, then we would move into our emergency measures. We would be calling on any assistance available across interconnectors from France or the Netherlands or Ireland, and that is something that we have seen good use of historically when it gets very tight. We also have a number of emergency services available to us, including Maxgen, where we can ask a number of generators across the system to effectively open all the stops for a couple of hours and generate above their normal commercially available load.
Q56 Rushanara Ali: In terms of the amount of time within which you can restore connections—
Duncan Burt: The peak period over 5.30 is quite short. It is about an hour and a half to two hours. When Cordi quotes the one hour per year loss of load expectation, what that means is that just for one hour a year we are going to be into our emergency measures. You would hope we could contain that with emergency assistance, so the interconnectors or maximum generation. If we went further to that, we would then issue an instruction to the distribution networks to manage the demand to a level that we could match to supply. Again, the Committee will be aware that typically that can be achieved through voltage reduction. At a local level, the voltage would be reduced on the network. When you reduce the voltage you reduce the megawatt demand proportionately. Again, typically, that would be enough to meet supply and achieve balance. Our understanding is that that can be done without local technical issues as well, so headlines such as televisions flickering we would say were incorrect. Even at this point, when we have gone through a first stage of demand management and we have voltage control, we would still expect to see minimal impact on end consumers, other than the long-run market price effect, obviously. At that stage, if we still had challenges, we could be into additional demand control, at which point the distribution networks would have to potentially commence disconnection, which we would expect, over the peak, to be for a very short period and very limited in geographical scope as to where that happens.
Q57 Glyn Davies: This is a follow-up to what Rushanara has been asking. You clearly cannot give a 100% guarantee—that is reasonable—that there will be no power cuts. It is the planning for a crisis that matters and how extensive your planning is. I have seen people ask about the winter in 1987 or 1988, somewhere there, but what about something like 1963? I am old enough to remember 1963 and we have seen nothing remotely like it since. How can you cope with that sort of a winter, or indeed the wind of 2 January 1987? We have not seen anything like those. Do you plan for crises of that sort, which are beyond the range of anything on this subject I see talked about?
Cordi O'Hara: Yes. Where I can give you confidence is in the robust nature of our planning, in our assessment of a wide range of scenarios and making sure we buy the tools that we need to perform our balancing role. May I ask Ro to take you through some of that weather scenario analysis and planning, just to give you a flavour?
Ro Quinn: When we are setting up our base case for analysis, we will be looking at a demand forecast that takes account of all the best information around where demand is likely to go for the next winter, all the way out to 2030. We would then also consider what the weather impact is on that. We would look at long run weather history so we do have those events, which might not be in recent memory, baked into the forecast.
We would then also look at a number of sensitivities so that we really have stress-tested that analysis and we understand what the impact could be. The sensitivities we look at must be credible. We will test them with Ofgem, who will approve them ultimately for the new balancing services. They will also be examined by DECC’s panel of technical experts to make sure that we are using the best modelling approaches, that we are using the best assumptions and that we have looked over a wide enough range. That then means that we have looked at the right risks to consumers around security of supply but also we have put some control around the costs, so that we are buying an efficient level of services in the balancing services regime and also in recommendations to Government for the capacity mechanism.
Q58 Julian Sturdy: We have touched on this a little bit, but what scenario would you predict would cause a lights-out? There must be a scenario. Could you just outline what that scenario might be? What is the worst-case scenario we are looking at?
Cordi O'Hara: There is no one specific scenario. We have to look at a range of things that could happen to the network and the cumulative impact of those as well. Ultimately, we would need to understand and determine what the cause of any failure like that is. That could happen through a number of different activities. Most of those we will seek to protect against.
Q59 Julian Sturdy: Could you outline some of those activities? For example, Glyn has talked about severe cold weather. High pressure over the winter, dull days, no wind, no solar activity and a couple of outages; where would that leave us?
Cordi O'Hara: We would look at a range of different impacts and that informs the amount of balancing services that we procure. One of the other things that we look at is the impact of lower winds because, as you know, we have a lot more renewable generation on the system. That could impact the amount of available generation on the day. We look at a range of weather scenarios from history that could cause distress on the system. We look at how interconnector volumes will flow and what we expect them to do, based on history and the prices we see in the forward markets, and then we also look at a range of different flows from those—
Q60 Julian Sturdy: You still have not answered. What would that scenario be? Say the weather event affected the whole of Europe. It was not just the UK but France, Germany and Holland, where some of our other energy is coming from through the interconnectors. What would a worst-case scenario look like?
Duncan Burt: You are hitting on what a lot of our job is, Mr Sturdy: to think about what could happen, about how that fits into history and the statistics of what we have seen over the last 50 or 100 years, and how the network would measure up against that. That covers both the energy balance position and the network resilience as a whole. As Ro and Cordi said, we absolutely look at the range of demand scenarios that we could get and how supply matches against that.
The particular one with the continent is an important one we have looked at. We know that if we see cold weather in the UK and cold weather on the continent, yes, clearly that is going to see higher demands in both markets. What we also know is that the peak period on the continent is an hour different from ours, as per the hour time difference, and so we would expect on such a scenario for the interconnector to swing and feed the peak in France and Holland and then turn around and feed the UK peak as well, so that both markets can meet good supply and demand balance.
Q61 Julian Sturdy: But there must be a scenario. What I am trying to get at is that there must be a scenario—it might be a one-in-200 or a one-in-500 year event—that would cause the lights to go out.
Cordi O'Hara: In modelling theory, you can absolutely build up a series of events.
Julian Sturdy: You have to model it. You have to go through that process.
Cordi O'Hara: We then have to put that in the context of its probability and, in order to insure against that, consider whether that is an appropriate cost for consumers with that level of probability, which is why we say, “What has credibly happened in the past that is worthy of being insured against? What can we foresee that might happen on the network, based on the characteristics that we should also protect against?” We have a vast range of modelling capabilities to look at some of those worst-case scenarios. What we have to do is balance that—
Q62 Julian Sturdy: Have you looked at them? Have you done it?
Cordi O'Hara: Through all of that analysis, we will look at a range of different events.
Q63 Chair: What probability did you arrive at of the event that Julian Sturdy is describing happening? What was the probability?
Cordi O'Hara: We have not ascribed a particular probability to one scenario. We must look at a range of different impacts and how they interact and relate.
Q64 Julian Sturdy: Have you arrived at any probability at all, then? Sorry.
Duncan Burt: If you break it down, though, what you get to is a supply and demand balance. From the supply margin’s point of view, we work to a Government security standard of three hours per year when we cannot balance supply and demand, and then we still have the emergency measures beyond that.
In terms of the physical network resilience, we undertake a whole range of plans, both from a security and from a resilience point of view, relating to storms and flooding. Those plans over the years have delivered a network that is 99.9999% reliable, one of the most reliable networks in Europe and one of the most meshed and densely populated networks in Europe as well. We know that those plans have worked historically in delivering very resilient, very reliable supplies to Great Britain. We continually work on those plans, both in terms of mitigating the possible effects of climate change and in terms of responding to emerging security threats, to make sure that we keep that physical network, alongside the balance of supply and demand, as resilient as we can.
Chair: Thank you very much. We are going to move on now to gas and electricity issues, and we will be coming on to longer-term issues towards the end.
Q65 Tom Blenkinsop: What is your assessment of the security of supply in the gas market this winter?
Cordi O'Hara: Can I ask Ro to take you through that?
Ro Quinn: When we are preparing our winter outlook report we go through a consultation process with industry, to make sure that we are using all the best available information and to test our assumptions with them. When we have looked at the gas demand and the available supplies, our assessment is that there is plenty of gas available. The question is: where will it come from? We are now in an ever-increasing global gas market, so there are more potential sources of gas between LNG markets, imports from Europe, and from Norway.
Q66 Tom Blenkinsop: How dependent do you think the UK will be on Norwegian or, indeed, Russian gas going forward?
Ro Quinn: In “Future Energy Scenarios” we repeat that analysis on a much longer-term basis to understand the emerging trends around the gas market. Again, we have come to the same conclusion: that there is plenty of supply available worldwide. It is a question of where it will come from, and that will be driven by the market. In some scenarios we will see an increase in flows from Norway; in some we will see increasing flows from LNG providers.
Q67 Tom Blenkinsop: Given the recent events in North Africa, and given the Groningen situation, where they have gone down to 30 bcm, do you anticipate more of that gas to come from Norway and Russia in the future?
Ro Quinn: We have looked at some stress tests around our analysis to explore both the possibility of reduced flows on the BBL pipeline, due to the Groningen issues and also what the impact would be of any ongoing tensions in the Russia/Ukraine situation. I can talk you through both of them. We looked first at what it would mean if we saw reduced imports on the BBL and we have concluded that, with flows from Norway and with the LNG market, we would not see any issues in the GB market.
In terms of Russian gas, it does not flow directly to GB, so what we have explored is the impact on diverting flows across Europe. Then we would see fewer flows from where we would traditionally import, from Europe. We have looked at the sensitivity where we have reduced imports from Norway. We have seen exports from the GB market rather than full imports and have concluded that there are enough supplies still to meet the GB demand. In the situation where we had both issues, the BBL and Russia/Ukraine, there would be very limited periods where we might need to use more of the gas that is in storage, but it would be of very short-term duration and it would be a very small volume.
Q68 Tom Blenkinsop: How short-term?
Ro Quinn: I think it was over one or two peaks in the evening towards the back end of winter, assuming that you had a cold winter period. For this winter, we are confident on the gas side that there is enough gas available in the market and the market can bring that to meet GB demand.
Cordi O'Hara: Just in support of that, Ro, we also do that assessment with Ofgem and DECC as well, particularly where there are geopolitical events involved, like a dispute in Russia/Ukraine. Our analysis is not just done in isolation. We do validate it with both DECC and Ofgem.
Q69 Tom Blenkinsop: Moving on to the electricity supply, is there any technology or source of generation that you might have some concerns about in terms of reliability this winter or going forward?
Ro Quinn: As I mentioned, we look at the reliability of all the technology types individually. We have looked over the last seven years at the historical performance and whether there are any short-term trends. When we look forward at new technologies coming on to the system, we will repeat that analysis and, as we learn more about those technologies, we will build up our understanding of how they will contribute to security of supply as well.
Q70 Tom Blenkinsop: How important is the role of interconnectors in the security of supply?
Cordi O'Hara: Interconnectors are providing an increasingly important role in terms of the volumes that we see coming through from France and the Netherlands, and not only in terms of baseline supply. Typically we will see imports at peak as well. I do not know if you want to add to that, based on your analysis.
Ro Quinn: When we have been looking at the contribution of interconnectors, we work very closely with interconnected TSOs, and with other system operators, to understand what their adequacy assessment is so we can make sure we are not all making contradictory assumptions. We would expect flows from Europe in this winter but we then do stress-test a number of scenarios where we see less. When we look forward, we have done extensive modelling on the capacity of interconnector growth and also what the flows might be, both across the year and at peak periods.
Q71 Tom Blenkinsop: Do you think European electricity prices will be as low as last year or do you think they will be higher?
Ro Quinn: I would not want to comment on where prices will go but we would expect to see imports from Europe to GB, which would support that that would be lower than GB prices, which means GB consumers are benefiting from that lower price.
Q72 Tom Blenkinsop: You think the supply of energy from, say, Germany or France, via the interconnector will be cheaper this year than last year?
Cordi O'Hara: We do not make price forecasts, but there is an open market so we can see how prices are playing out, both on the day and in the forward markets as well. What we typically see is that when there are lower prices on the continent there are higher flows through the interconnectors into our markets. Consumers do benefit from lower prices in one market that flow into the other.
Q73 Tom Blenkinsop: Do you think it will be the same price or do you think it will be higher, coming from the European markets?
Ro Quinn: To clarify, I do not want to comment on how prices would vary from year to year. Rather that pattern of seeing imports from Europe to GB we would expect to continue.
Q74 Chair: Why are the prices cheaper in Germany and France?
Ro Quinn: That is based on a range of factors. It will depend in part on how their treatment of low-carbon generation is factored into their market price and, also, on the treatment of carbon taxes in different markets. It is a wider market and you would expect, with more liquidity, for that to be reflected in prices as well. That is why we think interconnectors are a good option for GB consumers to make sure they can access that wider European market.
Q75 Chair: It has been put to me that Grid has a conflict of interest when it comes to interconnectors, of course, because Grid owns the interconnectors and to have power travelling through them is beneficial to Grid itself as a company. How would you answer that charge?
Cordi O'Hara: Grid has a number of businesses. We have a good, strong track record of managing perceived conflicts of interest through clear business separation rules between each of those businesses. Those are written within our licence and, therefore, they mean that we have to enact against those licences all the changes required within our policies, our procedures, our access to IS systems and the way that people can physically access different buildings. It even impacts the transfer of people across businesses as well. The licence conditions, if we were to breach them, are very punitive—up to 10% of our turnover—and ultimately could lead to revocation of our licence. We take business separation incredibly seriously. It is enforced through our licence. We have an independent compliance officer who is monitoring our performance against those business separation requirements, and that is reported to Ofgem on a regular basis.
Q76 Antoinette Sandbach: You are in the next Capacity Market. Interconnectors are effectively going to be able to bid in that market and you own—as has already been pointed out—over half of the IPA and BritNed connectors, but you also advise Government on capacity requirements. How do you tackle that direct conflict?
Cordi O'Hara: There is a clear information ring-fence around all of the EMR activities. To be clear, we do perform an administrative role. The Government asked for the inclusion of interconnectors within the capacity mechanism auction this year and we are obliged, through that administrative role, to facilitate that through the auction process. All of the information held within that EMR delivery body role is ring-fenced with very specific conditions within our licence. Those teams are physically separate from other teams. I cannot even get into the room where they are performing that analysis. There are some very strict business separation rules.
Q77 Antoinette Sandbach: Can I just ask, are they on the same site?
Cordi O'Hara: No, we are not allowed to have our non-regulated business that owns the interconnector on the same site as our system operator activity. Did you want to add to that?
Ro Quinn: Just on the analysis point, it is all scrutinised by DECC’s panel of technical experts. We presented a recommendation on the volume to procure that Government have the final decision on. We also presented a range of de-rating factors for each of the interconnectors and, again, Government assisted by the panel of technical experts make the final decision on what that reliability factor should be.
Q78 Julian Sturdy: On the interconnectors, are we becoming more reliant on imported energy?
Cordi O'Hara: Do you want to take that from the “Future Energy Scenarios”?
Ro Quinn: When we look at the “Future Energy Scenarios”, we prepare four scenarios that we want to be credible and evidence-based. We work with stakeholders on what they should contain to set out what the future could look like, rather than what we guarantee it will look like. We have increased the capacity of interconnectors within those scenarios and that is based on a number of changes that we have seen this year. Ofgem have approved the cap and floor regime, which is supporting investment. The European Commission have set out quite ambitious targets for the level of interconnection they want to see. In the scenarios we have seen an increase in capacity.
We have also then looked at what transfer we expect to see on the interconnectors and, in three of the four scenarios, we think that we will continue to see imports across the year, so we will see more energy coming in over the year than exporting. In our “gone green” scenario, which is where we have the highest level of green ambition and we would see the most low-carbon generation and the most renewable generation, from 2035 onwards or so we would expect to start to see exports over the year.
Q79 Julian Sturdy: In the short term, over the next few years, what you are saying is that we are going to continue to import more energy?
Chair: Unless we go green.
Ro Quinn: We would expect in the short term that we will continue to import energy from the continent as long as the price mechanisms support that. The interconnectors are driven by the price differential between those markets.
Q80 Julian Sturdy: We are currently not self-sufficient in energy?
Duncan Burt: If I could split the answer: a growing trend in imports absolutely reflects the price differential and the fact that there is cheaper continental power available, which will benefit GB consumers. That trend occurs through the year. I am sure this morning we are importing from France. Actually, being reliant is a slightly different question. As part of the security of supply assessment we look at a whole range of different scenarios. That includes lower flows from the continent, lower flows from Europe and higher flows. We are assessing the security of the system for each one of those scenarios. I would split the answer in two and say that there is an obvious read across there, but we would split out a view on reliance—we can survive without interconnection—from a trend of increasing flows from the continent, which is linked to pricing.
Q81 Julian Sturdy: You are saying we could survive without interconnection? I am not saying that scenario would come up but are we self-sufficient or are we moving away from being self-sufficient? That is my point.
Cordi O'Hara: As the regime changes there are incentives for new interconnection to be built. That is supported by the fact that we have seen lower prices on the continent that could be transported and deliver a benefit for the—
Q82 Julian Sturdy: The point is, though, that we are importing more energy. Are we not now self-sufficient? It is a “Yes” or “No” sort of answer I am looking for.
Duncan Burt: We still have adequate supplies from the UK to meet GB demand.
Q83 Chair: If the interconnectors were cut tomorrow, what would happen?
Ro Quinn: That is one of the sensitivities we consider going into any winter. If we were to see no imports from the interconnectors, how would that impact? That is one of the sensitivities we consider when we were looking at the volume we need to procure.
Q84 Julian Sturdy: So what would happen?
Ro Quinn: We think we would be secure. That is one of the sensitivities that is covered by the volume we have procured under SBR and DSBR.
Q85 Julian Sturdy: Sorry, Chair, I still do not know the answer to that. Would the lights go out or are we saying that energy would be a lot more expensive?
Duncan Burt: No. We can balance supply and demand without the flow across the interconnectors.
Q86 Julian Sturdy: But prices would rise?
Duncan Burt: Everything else being equal, given that those imports to the UK are cheaper than the alternative GB supply at the moment, it would not be unreasonable to assume that that would happen. We are in a highly hypothetical situation, so I might just step back from it a bit and make sure we have a really clear answer to the original question, which is: yes, we have enough indigenous supply in the UK to balance demand, but typically we are seeing higher flows due to cheaper power available on the continent.
Chair: I think what Mr Sturdy—correct me if I am wrong—is pointing out is that we have cheaper supplies coming through from the continent, as I think you said earlier, due to renewable or green energy, primarily in Germany.
Q87 Antoinette Sandbach: Can I clarify? Does green energy include nuclear as a low-carbon source of energy in your scenario planning?
Ro Quinn: Within our scenario planning, when we are looking at the GB system, we would split out low-carbon, including nuclear, from renewable sources. When we are thinking about the continental mix it would be driven by all of the generation they have connected, which would be some nuclear and some renewable sources. The liquidity point across the continent is the one that is key and how they treat different sources within their wholesale prices versus a general taxation.
Q88 Chair: UK prices are lower due to a connection to the Europeans, yes?
Ro Quinn: We believe that interconnectors do allow GB consumers to access the lower prices seen in the European market.
Q89 James Heappey: The assertion that domestic supply is sufficient, I just want to look at that for next winter. I am referring to a Centre for Policy Studies report that came out last week. It says that the remaining dispatchable capacity after the plant closures that are already slated for next year is 52,360 megawatts. Do you agree with that?
Cordi O'Hara: Currently we do not have a definitive figure because we want to do all of our robust analysis with Ofgem. That is underway. We want to make sure we are looking at both what is coming off the system and also what is coming on to the system at quite a granular level. We will also want to understand whether demand is expected to be the same as it is this year for next year. It is quite an involved and extensive process.
Q90 James Heappey: Yes, okay, but the current dispatchable electricity capacity is 68,966 megawatts. Do you agree with that? Yes. The capacity lost by the confirmed closures is 7,366 megawatts, which means that the total dispatchable capacity in April 2016 is 61,600 megawatts. Apparently you then have to de-rate it to 85% to achieve the availability over peak time. That comes to 52,000 megawatts. The usage this winter, as you have said in your “Winter Outlook”, is 54,200 megawatts. Even if there is no growth in consumption, based on those figures there is a deficient already. What is it that you think is going to come online that nobody else is aware of that could meet that gap?
Cordi O'Hara: This is specifically for next winter?
James Heappey: For next winter.
Cordi O'Hara: I refer to my previous answer: we are doing extensive work on that already.
Q91 James Heappey: What, exactly?
Cordi O'Hara: We have already consulted with the industry to extend our balancing services. That was approved by Ofgem. We are currently in the process of a tender to acquire additional reserves, based on the acknowledgment that there is more plant coming on to the system.
Q92 James Heappey: As far as I understand from our discussion this morning, those are all contingency measures. Your expectation is that there will be a generation deficient next year, if that is the right term, which you need to balance with contingency measures?
Cordi O'Hara: We expect to need balancing tools next winter. We expect them to be at least of the volume that we have already procured for this winter. It is too early to be as definitive as you would like me to be in terms of the absolute number but, rest assured, we are working on that at the moment and the first prudent step was to make sure we had those balancing services available. We did not have the rights to the toolkit that we have used last winter and this winter, until we consulted with the industry and gained approval from Ofgem, so that has been our first step. We are in the middle of that tender process at the moment and that tender will close on 30 November, when we will be able to analyse all of the available reserves that could meet our requirements. We will be able to be much clearer in December on what that volume requirement is.
Q93 James Heappey: You see the concern? Earlier on we were talking about this winter, and we were talking about seven to 10 NISMs and that it was impossible to be that certain. For next winter, it is even less possible. One might conclude that flirting with the margins that we are is pretty foolhardy, given the uncertainty in the predictions that you are able to make.
Cordi O'Hara: I think we have to go back to how security of supply is managed. DECC sets the long-term energy policy. The market then materially provides, through the investment in generation and suppliers contracting with customers to meet their needs. We then manage the real-time balancing of supply and demand. That is equivalent to the last 3% of energy in the UK.
In order to perform our role we need access to the right amount of balancing services, so our focus is on, when the market has materially provided, the gap that we need to deliver to perform our role on a real-time basis. That is why all of our action is focused at the moment on making sure we extend the toolkit, and we do the appropriate and rigorous analysis that you are quite rightly pointing out. We need to make sure that is done very effectively and at a level of detail that is appropriate. We have already issued our first tender because we like to take steps as early as possible. I would also like to make a point that we will undertake a period of review over the next 12 to 14 months as well, to see what else happens and materialises in the market.
Q94 James Heappey: Is it fair to say that next winter does not represent routine business for you? Next winter is a serious concern?
Cordi O'Hara: We are in a transition to, ultimately, the enduring regime, which is: electricity market reform and the securing of capacity through the capacity auctions and the contracts for difference allocation.
James Heappey: Which kicks in next year and we will come to that. I sense next year causes you some serious concern.
Cordi O'Hara: We have to make sure we can continue to perform our role and that role is balancing the system minute by minute.
James Heappey: This looks difficult at the moment.
Cordi O'Hara: That is always a challenge. We always have to think of a range of scenarios. We must make sure we have access to the right balancing services and that is why we have taken early action.
James Heappey: We are doing a nice dance but what this boils down to is that next winter looks like a pretty serious concern.
Q95 Chair: Can I cut in? Is it more challenging next winter than this winter?
Cordi O'Hara: We think we will need to buy at least what we have bought this winter, and we are taking action straight away on that.
Duncan Burt: To close that off though—to Mr Heappey’s point—the dispatchable generation number is a different number from the ones we would be looking at. We will be looking at the level of distributed generation and embedded generation that runs actively over the peak, of which there are at least several gigawatts. We would be looking at the innate level of wind that would be running over the peak as well, where our assumption sits around 20%. We would not be as stark as to say that we have less generation than we have supply. There are other sources of routine regular supply there that we would expect to be adding on top of those figures. But, as Cordi says, it is right that we are absolutely looking at the transition between years.
Q96 Antoinette Sandbach: At the moment distributed energy and wind supply are factored in, but you cannot actively see their contribution to your energy mix?
Duncan Burt: We do not have live meter reading so we cannot see it that minute but, absolutely, we can go back, year on year and day after day, and calibrate what the out-turn demand shape looks like. We can produce some fairly good estimates of how much distributed generation is participating.
Q97 Antoinette Sandbach: Will you be able to see it live?
Cordi O'Hara: We do see the impact of embedded generation through lower demand on the transmission system. We have recognised that there are volumes of generation connecting to the distribution level all the time, particularly solar, and we have seen a phenomenal growth in solar in the last year. We have been doing a lot of work with the distribution network owners, and with Ofgem, to make sure that we get as much access to information as possible, such that we can forecast the impact of that distributed generation growth on the transmission level demand. As Duncan says, that will add volumes to thermal generation and other generation that is connected directly to the transmission network. That is why, unfortunately, we do not have a definitive answer today. We have to do all of that work and make that thorough assessment before we procure our balancing tools. But we are on with that and we are ahead in terms of the process for that.
Q98 Chair: Can I ask how much less generation you will have available next winter as opposed to this winter, given the closures that James Heappey mentioned earlier? How many gigawatts is that going to mean? We know we have had a NISM in early November. What do you think the effect of that might be? I know we agreed it is going to be more challenging, next winter, so I wonder if you have a figure for how much less.
Ro Quinn: We have seen closures suggested by generation, obviously in the order of around 4 to 5 gigawatts, but some of those generators are still making final decisions as to whether or not they will close. As Cordi said, we are still waiting for further information from the market. We are still working through our analysis to understand what that final figure is and what the impact will be. It is too early at this point to confirm what that answer will be.
Cordi O'Hara: There is clearly a growing recognition that there have been some public announcements of some closures, which we can factor into our analysis. That is what we are doing. As Ro says, there is a level of uncertainty for some of the plants. We do not build our own generation. The asset owners themselves decide how economic they are to run and what their investment decisions might be, so we need to have a constant and open dialogue with the industry. That is why we do consult through both our “Future Energy Scenarios” process and also through our “Winter Outlook” process, to understand what the strategies of those generators are and what market conditions they are operating within to help give us the best analysis that we can. However, it is a point in time and that is why we have to continuously monitor it and continuously update our analysis as well.
Q99 Chair: You are effectively saying there—I think it is quite significant, Ms Cordi—that this winter, in some ways, is going to inform and affect next winter and might actually inform the closure of some plant as well.
Cordi O'Hara: We will be monitoring what happens this winter all the way through, as we always do; what that means for generators, how they have performed and what reliability they have shown. Have there been any announcements from plant that could affect the position next year? We also do a very robust look-back; how did demand out-turn? Were our forecasts accurate? What have we learnt? What have we seen in terms of the growth of distributed generation and how is that reducing demand at a transmission level? All of that stuff needs to be done on a continuous basis ahead of any winter that we are planning for. You are right, there will be elements of this winter that will play out and will help us understand and inform the position for 2016-17.
Q100 Chair: Some generators have told me that they would be better putting plant on the continent than locating it in the UK. Would you care to comment on that?
Cordi O'Hara: We do not invest or own generation and we do not inform asset investors’ strategies, so that would be a matter to pick up with them.
Q101 Antoinette Sandbach: You said that you go back and you look at your past scenario planning.
Cordi O'Hara: Yes.
Antoinette Sandbach: Obviously there have been issues at Hartlepool, Heysham and Wylfa. Did your planning identify those issues? They were there in the past 12 months. Have you identified that as a concern for this winter or going forward?
Cordi O'Hara: We have an active dialogue with asset owners, trying to understand how they are planning to run, how they maintain their assets and what we should expect to see. That extensively comes through the “Winter Outlook” process in terms of generators submitting information to us. There is also real-time information that they submit every day and every week, which is published, called OC2 data. In the case of last summer, we had extensive discussions with EDF as soon as they was aware that there was a potential type fault. That meant we could engage in very open dialogue around the potential risks to the system, how we might factor that into our planning, and then how we might make any additional balancing service purchases if they were required.
We have made various assumptions about availability for this coming winter, based on what those generators have told us, based on the data that they submit to us, and we will keep that under review. At this point in time there has been no information from the owners of nuclear plant to say that there is any issue.
Q102 James Heappey: I am going to take you to the sunlit uplands of the Capacity Markets when they came in. Are you happy with the outcomes of the Capacity Market auctions so far?
Cordi O'Hara: We act as a delivery body for the Government and the Secretary of State sets the target capacity to be purchased through those auctions. We ran one auction last December and the next one is coming up in this December. Did the capacity auction secure the capacity that was required and set for that auction? Yes. It actually procured more. That is done four years ahead, so last year the auction was run for winter 2018-19. There will be a T-1 auction. One year ahead of 2018-19 there will be a further auction for that winter period. It is fair to say we would like to see the outcome of the second auction. That auction runs this December for winter 2019-20. At that point, I think it is appropriate to step back and say, “Is the capacity mechanism doing everything it should?” In our delivery body role, we can help facilitate discussions around that. Ultimately we do not set the capacity to be secured but based on the first auction the target volume was achieved.
Q103 James Heappey: Is it stimulating enough new-build generation capacity, though? Are we reinventing the wheel by paying people to do what they were already doing?
Cordi O'Hara: There is a lot of discussion about the intent of the capacity mechanism and what generation that is bringing forward. It is clear it is securing additional generation, which was part of its intent, and it has also been stimulating refurbishment of assets as well. The question will always be how much generation needs to be brought forward and how we see that working through. I think Amber Rudd said in her speech she would like to take a step back after the second auction, make sure the auction is doing everything that it intended to do and, as an administrator of that scheme, we will do everything we can to facilitate the administration of it.
Q104 James Heappey: A centrepiece of that speech was gas, yet there is a real inertia in the building of new gas-fired power stations. How much gas do you expect will be successful in this year’s upcoming Capacity Market auction?
Cordi O'Hara: We do not make predictions about that.
James Heappey: You must have an instinct.
Cordi O'Hara: Perhaps in terms of modelling for “Future Energy Scenarios”.
Ro Quinn: When we have looked at “Future Energy Scenarios”, we have flexed what the potential growth of gas might be across those four scenarios. These are widely published. We know that various stakeholders use them in different ways to inform their own modelling. They have all that information and they have that to include in their own strategies for the Capacity Market. We would say that, going into this auction, there are a number of plants that are contracted and that have TEC, so they have passed the prequalification criteria to enter the auction. Then it will be based on the price in the auction and the competitiveness overall, in terms of what is successful.
Q105 James Heappey: I have two final questions on gas and the Capacity Market. Would you care to make any recommendations for what could be changed in the Capacity Market process in order to stimulate more gas to come on stream?
Ro Quinn: As Cordi mentioned, it is probably too early to start making recommendations on changes to the Capacity Market and that would not necessarily be our role. Our role would be to facilitate the discussion, to make sure we have understood stakeholders’ concerns and to help DECC in their work on that. It will be appropriate, after the second auction, to step back and review the whole process holistically, to understand whether there are any niggles that are causing concerns or ways that we could optimise some of the decisions made to make sure consumers are getting maximum value from the process.
Q106 James Heappey: I was going to ask you exactly how much gas is needed over the next decade, but I suspect you will give me a similar answer, which is entirely reasonable. I noticed in The Telegraph over the weekend that they had a screenshot of the generation on the day that you declared the NISM and wind had collapsed to 0.5% of the UK’s needs. On other days, as when the Committee was in your control room, wind is surging. You must have a view on the amount of gas that is required to buy out that huge variation in the generation capacity of the wind sector.
Cordi O'Hara: I will start with a comment on wind. You are absolutely right that wind is intermittent, but on the day in question we were already forecasting or expecting that volume on the system, so we were not surprised by that volume. It is intermittent but it is reliable, in that we can forecast it in terms of the amount of generation on to the system.
Chair: At the time in question—if my figures are right—it was 262 megawatts of wind from an expected total of 12.9 gigawatts, and the NISM was coming in after sunset, so the 8 gigawatts of solar and wind did not play in either of them.
Q107 James Heappey: It just seems that gas is the obvious, dynamic generation source that you can gear up to compensate, so it would be useful for us to hear your analysis of how much gas needs to be built, and how quickly, in order to enable that sort of intermittency to continue within the renewable sector.
Ro Quinn: If I may, I will start by setting out how we treat wind in our analysis around the security of supply and then how we treat that in our “Future Energy Scenarios”. When we are considering wind generation, we do not de-rate it in the same way that you would a thermal generator. With thermal generation you would assume that, if the price is right, it will run as long as it is available. With wind generation we will look at what is known as the equivalent firm capacity and we will calculate how much thermal generation—assuming perfect reliability—you would need to replace the entire wind fleet. That calculation comes out at around the 23% mark, so that is what we would assume for wind generation in our security of supply analysis.
When we are then building up our “Future Energy Scenarios”, there are three rules that we hold firm to make sure that we are helping industry understand the picture. One of the rules is that we will not spend money that is not available, so the Levy Control Framework will be binding. We will assume that the security of supply standard set by Government on electricity is met and that the equivalent security of supply standard on gas is also met. When we are building up those scenarios, we will have contained within them what thermal generation is required to make sure security of supply can be delivered.
That will vary from scenario to scenario based on how much wind generation you have, how much nuclear generation you have and what the mix is between closure of existing nuclear and coal assets and the rate of deployment of gas. When we look across those four scenarios, there are varying projections of how much gas generation is needed and when. That will also be impacted by the growth of distributed generation, which will come from a variety of sources as well. Within those four scenarios it sets out what the potential options could be, so that the industry are well-informed in terms of making their own investment decisions as to when to bring forward new assets and what load factors they might expect to achieve on those assets as well.
Q108 James Heappey: In terms of how you model future developments, is storage going to be a function of the Grid or will storage facilities effectively be generators to deal with? Will you ask them to discharge what they have stored at a time of your choosing?
Cordi O'Hara: There is lots of work to be done on storage. We did our first case study in the “Future Energy Scenarios” about the possibility for growth and penetration of storage on the UK networks. We are seeing the cost-effectiveness of battery storage making that a potentially reliable and investable technology in the UK. There is quite a bit of work to be done to understand how it can be optimised, how it should be classified within the regulatory regime and, therefore, how we can best use that—for example, in our own balancing services—to be as cost-effective as possible in balancing the network. We do see a potential new future for battery storage. We are working through a lot of the analysis around that at the moment. There are lots of questions to answer around where that storage will connect and what it is capable of, in terms of offering us services for balancing the system. We certainly want to understand that much more clearly and we are doing a lot of work on that at the moment.
Q109 Antoinette Sandbach: I want to go back very quickly to the Capacity Market auctions. You said it had been successful in guaranteeing supply, but a lot of the supply that it has guaranteed has been from what I would call dirty diesel generation. It is the Department for Energy and Climate Change. Given that, do you consider that the climate change aspect of the energy secured has been satisfied? In other words, is there a different risk that is being pursued, a climate change risk, in Capacity Markets delivering diesel generation rather than gas?
Chair: Can the Capacity Market remain technology neutral?
Duncan Burt: First and foremost, we are technology neutral. I am sure it will be an element that DECC will want to reflect on after the second round. I would say that we do have a lot of back-up generation within our balancing services. We have looked at that quite closely, historically, to understand whether we should be concerned about the emissions position. The way I would steer the Committee on that is that those diesels are useful in that they are not running most of the time. If your alternative, as it is for our balancing services, is to part-load a larger generator and, in doing so, make it less efficient—
Q110 Chair: What percentage of the Capacity Market will the diesels be churning out?
Duncan Burt: It still represents a very small component of the overall capacity element.
Chair: Roughly?
Duncan Burt: It is around a gigawatt.
Q111 Antoinette Sandbach: In terms of tweaking for the future, do you think the Capacity Market should look at climate change or emissions issues in terms of securing its supply or not?
Cordi O'Hara: As a result of the first auction, one of the conversations that people are naturally having is asking, “What type of generation is the mechanism bringing forward? Is that meeting the original intent?” I think it would be really helpful, with the changes that we have administered to the second auction, to get through that auction, step back and say, “Is it doing what was intended?” It is the job of Government to review that and of DECC to opine on that, but certainly we are very happy in our administrative role to provide feedback from all the stakeholders that we interact with as a function of providing the auction itself. We would say it is a bit too early to say, but those are the kinds of questions that should be reviewed.
Q112 Julian Sturdy: I want to touch on the energy storage point that James talked about. I think you are absolutely right to say that it is going to play an important role in future energy supply, but would you say the Government is behind the curve on energy storage compared to other European countries?
Ro Quinn: In our case study that we published in the “Future Energy Scenarios” document last July, we did look at where storage was used across the world in energy systems. We would not have said that we were behind the curve. We did identify a number of signals—traffic lights is how we refer to them—but if they all went green we would see the storage industry and real value unlocked. There are questions to be answered around the optimal place to use storage and how that feeds into its regulatory treatment, but it is a very exciting point for the storage market. There is huge opportunity and a number of different providers are getting involved. We are having a lot of conversations with providers around what services they might be able to offer to the National Grid as system operator, and we know that they are engaged across the supply section of the energy market.
Q113 Julian Sturdy: Would you say we need to do more on this?
Ro Quinn: There is an awful lot of work already started. Ofgem and DECC are both looking at flexibility projects and storage. We are quite excited to be involved in that work, to make sure that storage and the potential for it is being leveraged quickly.
Cordi O'Hara: To add to that, if we see that storage can provide vital cost-effective services in terms of balancing services, we want to make sure we optimise and get after that on behalf of the consumer. It is an exciting time for us and we want to be at the forefront of some of those conversations, making sure we are taking full consideration of new technology into the balancing services that we need in the future in order to get the lowest cost.
Q114 Chair: There is a final point I want to cover. We talked earlier about the interconnectors and we touched on the conflicts of interest, and you said that of course the arms of the business are separate from one another. Ultimately they are answerable to the same shareholders and it does not take a genius within Grid to understand that it is beneficial for the company to have some traffic on its interconnectors. If I, Mr Heappey and Mr Sturdy were in Grid, we would not necessarily have to talk to each other to understand that it would be useful for our assets to be used and to be earning money. In fact, we would never need to have that conversation; it is a given. The conflict of interest is clearly there. How can you assure the public that National Grid are not designing scenarios to use that asset for their benefit as opposed to a greater public good?
Cordi O'Hara: I do need to go back to the very prescriptive business separation requirements that are embedded in our licence. That means that those businesses are financially operated completely separately from the SO. That is embedded within the licence. Those companies need to be hosted in different facilities and there are specific ring-fences within our role, in terms of analysing and understanding the role that interconnectors play within our licence as well. There are very strict measures within our licence that ultimately could lead to significant fines if we were to demonstrate non-compliance. We have appointed separate and independent compliance officers to oversee our business separation activities embedded in our licence. We report regularly to Ofgem on our performance against those compliance statements, and we have a good track record of managing conflicts of interest. Clearly there is greater confidence required in those perceived conflicts. That is why it is important for us to share with the industry all of the work that we do on business separation, and we are obliged to do that within our licence.
Q115 Chair: In fairness to you, I hear your assurances but, as soon as the sun rises, two arms of the business will know that the assets being used are beneficial to the business. That is inescapable. It is nearly a law of physics. The United States of America has an independent system operator, and the Secretary of State has said as much here. What would your reaction be to an independent system operator? Although there is no connection within the firm, there could then be no charge or no questioning of a potential conflict of interest.
Cordi O'Hara: If I may clarify, within Amber Rudd’s speech she did say there may be a greater need for independence, but I would not necessarily say that means we need to jump directly to an independent system operator. Over history, the system operator has been asked to perform additional roles on behalf of the industry, and through that time we have taken on those roles. We have put in place significant business separation in order to perform those roles and manage those conflicts of interest. With the growing roles we are being asked to do, it is fair to say we have been in growing dialogue with DECC and Ofgem around market confidence around those perceived conflicts of interest.
Q116 Chair: Would you concede, though, for as long as you have shareholders—it is not like the system in the United States, where it is genuinely a function of regulation—that you can never escape that feeling or that question that there is a conflict of interest?
Cordi O'Hara: There are less radical steps than moving to a full, independent system operator. We are already in discussion about what other areas of separation may be appropriate to manage the confidence around conflicts of interest but maintain the role within National Grid. Clearly there are elements, such as legal separation of the SO and TO functions, which we should consider before we move directly to a fully independent system operator.
What I can say is that we welcome those discussions. We are happy to be at the table because we can help inform, with our experience, some of those options. We do have a business in the US, so we have extensive insight into working with other independent system operators. We would like to do more analysis on the cost-benefit of independent system operators. We would like to compare that with other options there might be to provide greater independence and separation without going as far as an independent system operator. Our anchor in the SO is making sure that, whatever changes are made, the interests of the consumer are at the heart of those decisions.
Chair: Thank you very much. Your American friends might be interested to know they are running a radical system. It may be good for their blood pressure, if nothing else. I thank you all very much, Mr Burt, Ms O’Hara and Ms Quinn, for your evidence this morning.
Oral evidence: Security of Supply 2014-15, HC 509 7